REG - Harbour Energy PLC - Full-year results for the year to 31 December 2023
07/03/2024 07:15
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RNS Number : 9687F Harbour Energy PLC 07 March 2024
Harbour Energy plc
Full-year results for the year to 31 December 2023
7 March 2024
Harbour Energy plc ("Harbour" or the "Company" or the "Group") today announces
its results for the year ended 31 December 2023.
Harbour operational highlights
§ Production of 186 kboepd (2022: 208 kboepd), split 52% natural gas/48%
liquids and within guidance
§ Operating costs of $16/boe (2022: $14/boe), in line with guidance
§ Total recordable injury rate reduced to 0.7 per million hours worked (2022:
0.8)
§ Total 2P reserves and 2C resources increased to 880 mmboe (2022: 865 mmboe)
reflecting reserve additions at our operated UK hubs and international
exploration success, partially offset by production
§ Continued momentum on Harbour's UK CCS projects, Viking and Acorn, with
both projects awarded Track 2 status; estimated independently verified net
CO(2) storage capacity in excess of 200 million tonnes
§ Announced transformational acquisition of the Wintershall Dea asset
portfolio (the "Acquisition")
Harbour financial highlights(( 1 (#_ftn1) ))
§ Realised, post hedging oil and UK gas prices of $78/bbl and 54p/therm
(2022: $78/bbl and 86p/therm)
§ Revenue of $3.7 billion (2022: $5.4 billion), reflecting lower natural gas
prices and production
§ Profit before tax of $0.6 billion (2022: $2.5 billion); profit after tax of
$32 million (2022: $8 million) reflecting an effective tax rate of 95% (2022:
100%)
§ Free cash flow (post-tax, pre-distributions) of $1.0 billion (2022: $2.1
billion)
§ Returned $249 2 (#_ftn2) million through share buybacks in addition to the
$200 million annual dividend, resulting in $1 billion of shareholder
distributions since becoming a public company in April 2021
§ Net debt reduced to $0.2 billion (2022: $0.8 billion) with $2.7 billion of
net debt reduction since April 2021; leverage reduced to 0.1x (2022: 0.2x)
§ Proposed final dividend of $100 million, in line with $200 million annual
dividend policy and equating to 13 cents per share (2022: 12 cents),
reflecting dividend per share growth for the full year 2023 of c.9%
2024 and 2025 outlook for Harbour 3 (#_ftn3)
§ Production guidance of 150-165 kboepd reiterated; production to end
February of c.172 kboepd
§ 2024 unit operating cost guidance unchanged at c.$18/boe; total capital
expenditure guidance reiterated at $1.2 billion
§ Free cash flow is expected to be marginally positive(( 4 (#_ftn4) )) in
2024, after estimated cash tax of $1.0 billion, assuming commodity prices of
$85/bbl Brent and reduced UK gas prices of 70p/therm
§ For 2025, production levels and operating costs are expected to be similar
to 2024 while total capital expenditure is anticipated to be materially lower;
Harbour continues to expect to generate significant free cash flow in 2025,
resulting in a net cash position by year end
§ Harbour has hedged c.50% and c.25% of its 2024 UK gas and liquids volumes
at 67p/therm and $84/bbl and c.25% and c.15% of its 2025 UK gas and liquids
volumes at 90p/therm and $77/bbl 5 (#_ftn5) , respectively
Acquisition of Wintershall Dea Asset Portfolio on track to complete in Q4 2024
In December, Harbour announced the acquisition of substantially all of
Wintershall Dea's upstream assets for $11.2 billion. The Acquisition will
transform Harbour into one of the world's largest and most geographically
diverse independent oil and gas companies, adding material positions in
Norway, Germany, Argentina and Mexico.
Since the announcement, significant progress has been made on the various
approvals and workstreams required for completion:
§ Irrevocable undertakings from shareholders to vote in favour of the
Acquisition increased, and currently represents c.35% of Harbour's issued
share capital as at 6 March 2024
§ Harbour is on track to publish the prospectus and shareholder circular and
to hold the shareholder meeting to approve the Acquisition in Q2 2024
§ Successful bondholder vote to amend certain terms and conditions of
Wintershall Dea's c.$4.9 billion investment grade bonds and subordinated
notes; over 80% of bondholders participated in the vote and the amendments
were approved with significant bondholder support 6 (#_ftn6)
§ Successful syndication of the proposed $3 billion RCF and $1.5 billion
bridge facility with strong support from both existing relationship banks and
new banks resulting in oversubscription for both facilities
§ Submission of filings in the relevant jurisdictions for substantially all
the regulatory, anti-trust and foreign direct investment approvals required
for completion have been made and are progressing as expected
Harbour continues to expect the Acquisition to complete in Q4 2024.
Linda Z Cook, Chief Executive Officer, commented:
"Harbour materially advanced its strategy during 2023. We improved our safety
performance, generated material free cash flow, and progressed our
international growth opportunities and CCS projects, while maintaining our
capital discipline. This enabled continued shareholder returns over and above
our base dividend while retaining the flexibility that allowed us to announce
a transformational acquisition in December.
"We remain focused on the successful completion of the Wintershall Dea
acquisition and the ongoing safe and efficient management of our existing
portfolio. We are excited about our future as we look to continue to build a
geographically diverse, large scale, independent oil and gas company focused
on safe and responsible operations, value creation and shareholder returns."
Enquiries
Harbour Energy plc
Elizabeth Brooks, Head of Investor Relations +44 20 3833 2421
Brunswick
Patrick Handley, Will Medvei +44 20 7404 5959
Analyst and investor conference call and webcast
Harbour will host a live webcast today at 9.00am (UK time) which will be
available via its website www.harbourenergy.com (http://www.harbourenergy.com)
. A conference call is also available for those unable to join the webcast:
Dial in: +44 20 3936 2999 (tel:+442039362999) ; Access Code: 038726.
A replay will be available on Harbour's website shortly after the event.
Summary of 2023 performance
Operational performance in line with guidance
Production averaged 186 kboepd (2022: 208 kboepd), split 52 per cent natural
gas and 48 per cent liquids and in line with guidance. In the UK, we delivered
higher production from our operated J-Area hub, supported by new wells
on-stream around the end of 2022, while our operated Greater Britannia Area
(GBA) continued to outperform expectations. This was offset by the deferral of
drilling at partner-operated hubs resulting in fewer wells on-stream later in
the year. Production was also impacted by some extended shutdowns in the
second half of the year, including at our operated AELE hub and the East Irish
Sea assets.
Operating costs for the year were $1.1 billion (2022: $1.1 billion),
reflecting active management of our cost structure, including a reduction of
staff in our UK operations and the further development of strategic supply
chain partnerships and consolidation of contracts. On a unit of production
basis, operating costs were higher at $16/boe (2022: $14/boe) due to lower
production. 2023 total capital expenditure was c.$1.0 billion (2022: $0.9
billion) reflecting higher international exploration activity offset in part
by the deferral of certain UK opportunities in response to the Energy Profits
Levy (EPL).
Safe and responsible operations
In 2023, Harbour delivered an improved safety performance with our Total
Recordable Injury Rate reduced to 0.7 (2022: 0.8) per million hours worked.
In addition, we achieved two firsts for Harbour: zero lost time injuries and
no serious (Tier 1 or 2) process safety events. This improvement was supported
by the company-wide Back to Basics safety campaign initiated in 2022 and now
fully embedded throughout our business.
In 2023, our gross operated greenhouse gas emissions reduced to 1.3 million
tonnes, representing a c.30 per cent reduction compared to 2018, while our GHG
intensity increased to 23 kgCO(2)e/boe (2022: 21 kgCO(2)e/boe) due to lower
production. In January 2024, we signed the United Nations Environment
Programme Oil and Gas Methane Partnership 2.0 (https://ogmpartnership.com/)
memorandum of understanding.
During 2023, we successfully plugged and abandoned seven wells bringing the
total that Harbour has decommissioned in the UK since 2014 to 161. Harbour
also executed numerous seabed clearance and remediation campaigns during the
year with onshore dismantlement and processing of removed infrastructure
resulting in a recycling rate in excess of 97 per cent.
Maximising the value of our UK producing assets
The majority of Harbour's capital programme is focused on infrastructure-led
opportunities designed to optimise production and cash flow. These
opportunities are typically low risk, high return, short cycle investments
with low GHG intensity.
Within our operated portfolio, we delivered first gas from Tolmount East in
November, increasing production rates from Tolmount. At J-Area we completed
development drilling at Talbot, a three-well subsea tie-back to the Judy
platform with first oil on track for around the end of 2024. We also approved
plans to drill a well and retrofit three producing wells for gas lift,
targeting improved recovery from the Judy Chalk. At our AELE hub, we approved
an infill well at North West Seymour which, together with plant modifications,
is expected to extend producing life of the Armada field beyond 2030.
At our operated Greater Britannia Area, Harbour progressed plans to return to
drilling at the satellite fields, including an infill well at Callanish which
spudded in February 2024, and an appraisal well at Brodgar. In addition, we
successfully appraised the Leverett gas discovery in 2023 with the potential
development via a subsea tie-back to the Britannia platform now being
evaluated.
In our partner-operated portfolio, Beryl production was boosted by initial
high rates from two new wells online in the second quarter. However,
production on a full year basis was impacted by the operator's decision to
pause further subsea and platform drilling in response to the EPL. Production
from our West of Shetland assets was supported by four wells drilled across
Clair Phase One and Clair Ridge, and a further three wells at Schiehallion.
Further drilling at both Clair and Schiehallion is planned for 2024. In
addition, the operator continues to optimise the Clair Phase 3 development,
which is expected to target Clair South.
As at 31 December 2023, Harbour's proven and probable (2P) reserves on a
working interest basis were 361 mmboe (2022: 410 mmboe). This reflects the
impact of production (c.68 mmboe) partially offset by over 20 mmboe of
additions across our UK operated J-Area, AELE and GBA hubs following the
approval of several new wells.
Attractive international growth projects with potential for material reserves
replacement
During 2023 we continued to invest in our international growth opportunities
in Mexico and Indonesia. These have the potential to materially add to our
reserves and production and diversify our company over time.
In Mexico, the unit development plan for Zama was approved by the regulator in
June and the Zama unit partners have formed an integrated project team to
manage the delivery of the development. Good progress was also made on the
various commercial agreements. FEED is planned to begin in 2024. The Zama unit
has the potential to add reserves equivalent to a year's worth of Harbour's
current production. South west of Zama, in Block 30, we made a significant oil
discovery with the Kan-1 well in April. The appraisal plan has been approved
by the regulator with drilling scheduled for the second half of 2024. In
parallel, early engineering studies are being undertaken on a potential Kan
development.
In Indonesia, we made a significant gas discovery at Layaran-1 on the South
Andaman licence (Harbour 20 per cent interest) in December following the
Timpan-1 gas discovery on the Andaman II licence (Harbour 40 per cent operated
interest) in 2022. Post year end, the rig moved to drill the Halwa and Gayo
prospects on Andaman II where operations are nearing completion. The Halwa-1
well encountered low gas saturations while a small gas discovery has been made
at Gayo. Once the Gayo testing programme is complete, the rig will return to
South Andaman to drill the shallower Tangkulo prospect to the south of Layaran
aiming to prove up additional volumes. In addition, Mubadala, operator of
South Andaman, intends to add a fifth well to the campaign to appraise the
Layaran discovery.
Harbour's 2C resource increased to 519 mmboe as at 31 December 2023 (2022: 455
mmboe), driven by the addition of the Layaran gas discovery and the Kan oil
discovery. As a result, 2023 saw significant growth in our international
(non-UK) resource base which now accounts for over 60 per cent of our 2C
resources, underpinning future potential reserve replacement and
diversification of our company.
Investing in CCS to enable the energy transition
2023 saw good momentum on our two UK CCS projects - the Harbour-led Viking CCS
project (Harbour 60 per cent interest) and Acorn (Harbour 30 per cent
non-operated interest) with both awarded Track 2 status as part of the UK
Government's regulatory process. These projects have a critical role to play
in the UK's transition to a lower carbon economy and provide a potential
long-term stable income stream for Harbour.
The Harbour-led Viking project aims to transport and store 10 million tonnes
of CO(2) emissions per annum by 2030 and up to 15 million tonnes per annum by
2035, making it one of the largest planned CCS projects in the world. The
project allows for scalable transportation and storage of CO(2) emissions from
the Humber, the UK's most industrial emissions intensive region, and also for
shipped CO(2) emissions from emitters both in the UK and in Europe.
Material progress on Viking during 2023 included: the Development Consent
Order for the 55 km onshore CO(2) transportation pipeline being submitted and
accepted for examination; the award of two CCS licences adjacent to Harbour's
existing Viking licences, potentially increasing the project's independently
verified 300 million tonnes of gross storage capacity by more than 50 per
cent; and the project securing its first potential CO(2) shipping customer.
In addition, bp joined the project as a partner in early 2023, with a 40 per
cent interest. Post year end, in January, the FEED contract was awarded,
marking another important milestone for Viking as it progresses towards a
final investment decision.
The Acorn CCS project plans to transport CO(2) from emitters across Scotland
to storage reservoirs offshore, targeting at least five million tonnes of
CO(2) per year by 2030. There is also the potential for shipped CO(2) volumes
via the Peterhead port. In September 2023, the project was awarded two further
CCS licences, covering the East Mey and Acorn East areas. FEED on the
Transportation and Storage System is expected to commence in 2024 ahead of a
potential investment decision.
Strong financial position and disciplined capital allocation
During 2023, we generated significant free cash flow of c.$1 billion, enabling
Harbour to reduce its net debt to $0.2 billion from c.$0.8 billion at the end
of 2022. We also successfully amended and extended on favourable terms our RBL
facility which was undrawn as at year end. This strong financial position
allowed our Board to return $249 million through share buybacks during the
year, in addition to our $200 million annual dividend.
The Board has declared a final dividend of $100 million in respect of the 2023
financial year to be paid in May 2024, equating to 13 cents per share, subject
to shareholder approval. Given our share buyback programme, this represents
full year on year dividend per share growth of 9 per cent.
Since becoming a public company in 2021, our sustained operational and
financial delivery along with our disciplined approach to capital allocation
has enabled us to reduce our net debt by $2.7 billion and return c.$1 billion
to shareholders while retaining the flexibility to reach agreement on a
transformational acquisition.
A transformational acquisition aligned with our strategy
On 21 December 2023, Harbour announced the acquisition of substantially all of
Wintershall Dea's upstream oil and gas assets for $11.2 billion. The
Acquisition will be funded through porting of existing investment grade bonds
from Wintershall Dea, Harbour equity and cash.
The Acquisition is expected to increase our production to c.500 kboepd 7
(#_ftn7) and adds significant positions in Norway, Germany, Argentina and
Mexico. Importantly, the Acquisition will lengthen our reserve life and is
accretive across all key metrics on a per share basis, supporting enhanced and
sustainable shareholder returns. In addition, the Acquisition advances our
energy transition goals, significantly lowering our GHG emissions intensity
and expanding our already strong CCS interests into new European markets.
Further, the Acquisition is expected to transform our capital structure and
deliver investment grade credit ratings upon completion.
The Acquisition is subject to Harbour shareholder approval and we plan to
publish a prospectus and shareholder circular setting out the details of the
shareholder meeting to approve the Acquisition in the second quarter of 2024.
Harbour has received irrevocable undertakings from shareholders which, as at 6
March 2024, represented c.35 per cent of our issued share capital to vote in
favour of the acquisition.
The Acquisition is also subject to, amongst other things, regulatory,
anti-trust and foreign direct investment approvals. Substantially all
necessary filings required for such approvals have been submitted in the
relevant jurisdictions, including in the UK and Germany, and are progressing
as expected.
Regarding the financing of the transaction, in February 2024, Harbour and
Wintershall Dea's finance subsidiaries successfully completed a bondholder
vote to amend certain terms and conditions of Wintershall Dea's c.$4.9 billion
investment grade bonds and subordinated notes to reflect the anticipated group
structure. Over 80 per cent of bondholders participated in the vote and the
amendments were approved with significant bondholder support across all five
bond tranches. The consent is subject to final technical implementation.
In March 2024, Harbour successfully completed the syndication of the $3
billion revolving credit facility (RCF) and $1.5 billion bridge facility with
strong support from both existing relationship banks and new banks resulting
in oversubscription for both facilities. This reflects strong lender support
for Harbour's strategy going forward and is testament to the high-quality
credit profile of the pro forma company.
Harbour continues to expect the Acquisition to complete in the fourth quarter
of 2024.
Outlook
On a standalone basis and before any contribution from the Acquisition and
assuming a Brent oil price of $85/bbl and a reduced UK gas price of
70p/therm 8 (#_ftn8) , we expect to be marginally free cash flow positive for
2024. This is after a higher capital investment programme to support future
production and c.$1.0 billion of cash tax payments, reflecting the full
utilisation of our available UK corporate tax losses in the first half of 2024
and phasing of UK EPL payments.
Looking to 2025, we anticipate production remaining broadly stable, with
increased volumes from new wells and projects substantially offsetting natural
decline, and our total capital expenditure to be materially lower. As a
result, we expect to generate significantly higher free cash flow in 2025
compared to 2024 and to build a net cash position by year end.
As we look to the future, we have a strong balance sheet, our asset base is
generating robust cash flow and we have good momentum on our organic growth
opportunities and UK CCS projects. At the same time, we are on track to
complete the acquisition of the Wintershall Dea asset portfolio in the fourth
quarter of 2024 which will transform our scale and asset diversification as
well as our capital structure.
Our ambition to grow through M&A remains unchanged and we are well
positioned for future opportunities. However, we will maintain our disciplined
approach to capital allocation, balancing any future growth opportunities
alongside a commitment to an investment grade balance sheet and competitive
shareholder returns.
Financial Review
Summary of financial results
Analysis of these key metrics are discussed in detail across the following
pages of the Financial Review.
Units 2023 2022
Production and post-hedging realised prices
Production kboepd 186 208
Crude oil $/boe 78 78
UK natural gas p/therm 54 86
Indonesia natural gas $/mscf 13 14
Income statement
Revenue and other income $ million 3,751 5,431
EBITDAX(1) $ million 2,675 4,011
Profit before taxation $ million 597 2,462
Profit after taxation $ million 32 8
Basic earnings per share cents/share 4 1
Other financial key figures
Total capital expenditure(1) $ million 969 908
Operating cash flow $ million 2,144 3,130
Free cash flow(1) $ million 1,042 2,105
Shareholder returns paid(1) $ million 439 552
Net debt(1 ) $ million (213) (704)
Leverage ratio(1) times 0.1 0.2
(1) See Glossary for the definition of non-IFRS measures. Reconciliations
between IFRS and non-IFRS measures are provided within this review.
Income Statement
2023 2022
$ million $ million
Revenue and other income 3,751 5,431
Cost of operations (2,357) (2,845)
EBITDAX(1) 2,675 4,011
Operating profit 913 2,541
Profit before tax 597 2,462
Taxation (565) (2,454)
Profit after tax 32 8
Cents /share Cents /share
Basic earnings per share 4 1
(1) Non-IFRS measure - see Glossary for the definition.
Revenue and other income
Total revenue and other income decreased to $3,751 million (2022: $5,431
million). This was driven by lower commodity prices, especially UK natural gas
prices, and reduced production.
2023 2022
$million $million
Revenue and other income 3,751 5,431
Crude oil 2,086 2,792
Gas 1,415 2,322
Condensate 179 238
Tariff income and other revenue 35 38
Other income 36 41
Revenue earned from hydrocarbon production activities decreased to $3,680
million (2022: $5,352 million) after realised hedging losses of $911 million
(2022: $3,185 million). This decrease was mainly driven by lower post-hedging
realised UK natural gas prices and reduced production volumes.
Crude oil sales decreased to $2,086 million (2022: $2,792 million) after
realised hedging losses of $93 million (2022: $753 million). This was driven
by lower production volumes, with our realised post-hedging oil price stable
at $78/bbl (2022: $78/bbl).
Gas revenue was $1,415 million (2022: $2,322 million), split between UK
natural gas revenue of $1,284 million (2022: $2,142 million) including
realised hedging losses of $818 million and international gas revenue of $131
million (2022: $180 million). The realised post-hedging price for our UK and
Indonesia gas was 54 pence/therm (2022: 86 pence/therm) and $13/mscf (2022:
$14/mscf), respectively.
Other income amounted to $36 million (2022: $41 million) which includes
partner recovery on related lease obligations and a receipt related to the
Viking CCS Development Agreement entered into with bp in March 2023.
Cost of operations
Cost of operations decreased to $2,357 million (2022: $2,845 million) driven
primarily by a positive movement in hydrocarbon inventories and
(over)/underlift.
2023 2022
$million $million
Operating costs
Field operating costs 1,171 1,114
Non-cash depreciation on non-oil and gas assets (26) (26)
Tariff income (30) (30)
Total operating costs 1,115 1,058
Operating costs per barrel ($ per barrel)(1) 16.4 13.9
Movement in over/underlift balances and hydrocarbon inventories (225) 181
Depreciation, depletion and amortisation (DD&A)
before impairment charges
Depreciation of oil and gas properties (cost of operations only) 1,395 1,508
Depreciation of non-oil and gas properties 35 37
Amortisation of intangible assets - 1
Total DD&A 1,430 1,546
DD&A before impairment charges ($ per barrel)(1) 21.1 20.4
(1) Non-IFRS measure - see Glossary for the definition.
Total operating costs were flat year on year at $1,115 million (2022: $1,058
million) driven by strong cost control in an inflationary environment.
Operating costs were higher on a unit of production basis at $16.4/boe (2022:
$13.9/boe) due to lower production volumes.
Depreciation, depletion and amortisation (DD&A) unit expense, which
reflects the capitalised costs of producing assets divided by produced
volumes, was $21.1/boe (2022: $20.4/boe).
EBITDAX(1)
EBITDAX(1) was $2,675 million (2022: $4,011 million), with the reduction
mainly driven by lower revenue.
2023 2022
$million $million
Operating profit 913 2,541
Depreciation, depletion and amortisation 1,430 1,546
Impairment/(impairment reversal) of property, plant and equipment 214 (170)
Impairment of goodwill 25 -
Exploration and evaluation expenditure, and new ventures 36 42
Exploration costs written-off 57 64
Gain on disposal - (12)
EBITDAX(1) 2,675 4,011
(1) Non-IFRS measure - see Glossary for the definition.
The Group has recognised a net pre-tax impairment charge on property, plant
and equipment of $214 million (2022: $170 million net reversal). Approximately
half of this is in respect of revisions to decommissioning estimates on mainly
non-producing assets with no remaining net book value. The balance relates to
the announced sale of our Chim Sao asset in Vietnam and an impairment on two
UK North Sea assets, one driven primarily by a significant reduction in the
gas price outlook compared to the 2022 year-end view, and the other by a
revised decommissioning cost profile. In addition, there is a goodwill
impairment of $25 million in respect of the Vietnam assets.
During the year, the Group expensed $93 million (2022: $106 million) for
exploration and appraisal activities. This includes exploration write-off
expense of $57 million (2022: $64 million) mainly in relation to the Ix-1EXP
well in Mexico, the JDE well in Norway and costs associated with licence
relinquishments and uncommercial well evaluations and a further $29 million
(2022: $28 million) in relation to our UK CCS projects.
Net financing costs
Finance income amounted to $104 million (2022: $279 million), including
derivative gains of $68 million (2022: $48 million loss) related to changes in
the fair value of an embedded derivative within one of the Group's gas
contracts. The reduction in finance income compared to 2022 is mainly due to
unrealised foreign exchange gains of $202 million in 2022 which predominately
arose on the revaluation of open sterling denominated gas hedges as a result
of the weakening of sterling against the US dollar in the period.
Finance expenses amounted to $420 million (2022: $358 million). This included
interest expense incurred on debt facilities of $42 million (2022: $98
million), the reduction reflecting the impact of lower drawn down debt
partially offset by higher interest rates. Other financing expenses include
the unwinding of the discount on decommissioning provisions of $156 million
(2022: $65 million) which increased due to higher cost estimates and bank and
financing fees of $100 million (2022: $91 million) and $57 million of foreign
exchange losses as a result of the strengthening of sterling in the year
(2022: $202 million of foreign exchange gains).
Earnings and taxation
Profit after tax amounted to $32 million (2022: $8 million profit). This
resulted in earnings per share of 4 cents (2022: 1 cent ) after taking into
account the weighted average number of ordinary shares in issue of 804 million
(2022: 900 million) following the share buyback programme.
Harbour's tax expense decreased in 2023 to $565 million (2022: $2,454
million). The 2022 charge included a one-off non-cash charge of $1,469 million
as a result of the revaluation of the deferred tax position on the balance
sheet following the introduction of the Energy Profits Levy (EPL) in the UK.
The tax expense is split between a current tax expense of $677 million (2022:
$706 million), which includes an EPL current tax charge of $525 million (2022:
$326 million) and a deferred tax credit of $112 million (2022: $1,748 million
expense including $1,469 million one-off non-cash deferred tax charge).
The effective tax rate is 95 per cent (2022: 100 per cent) materially higher
than the standard UK tax rate for the period of 75 per cent. This is in part
due to costs which are not fully deductible at the UK statutory rates. If
these items had not arisen then we would have expected the effective tax rate
for the period to be c.85 per cent.
Shareholder distributions
A final dividend with respect to 2022 of 12 cents per ordinary share was
proposed on 9 March 2023 and approved by shareholders at the AGM on 10 May
2023. The dividend was paid on 24 May 2023 to all shareholders on the register
as at 14 April 2023, totalling $99 million 9 (#_ftn9) . An interim dividend
was announced on 24 August 2023 at 12 cents per share and was paid on 18
October 2023 at a value of $91 million 10 (#_ftn10) .
In addition to these dividend payments, Harbour completed on 15 February 2023
the remaining $43 million 11 (#_ftn11) of a $100 million share buyback
approved by the Board in November 2022. The Board approved a further $200
million share buyback scheme on 9 March 2023, which concluded on 28 September
2023. The purpose of these share buyback programmes was to reduce the
Company's share capital and all ordinary shares purchased as part of the
programmes were cancelled. During 2023, we repurchased and cancelled 76.8
million of our own shares at a cost of $249 million3 (2022: $361 million),
equating to 9 per cent of our issued share capital at 1 January 2023.
The Board is proposing a final dividend with respect to 2023 of 13 cents per
ordinary share to be paid in GBP at the spot rate prevailing on the record
date. This dividend is subject to shareholder approval at the AGM, to be held
on 9 May 2024. If approved, the dividend will be paid on 22 May 2024 to
shareholders on the register as of 12 April 2024. A dividend re-investment
plan (DRIP) is available to shareholders who would prefer to invest their
dividends in the shares of the company. The last date to elect for the DRIP in
respect of this dividend is 26 April 2024.
Statement of Financial Position
2023 2022
$million $million
Assets
Non-current assets, excluding deferred taxes 8,074 9,033
Deferred tax assets 7 1,406
Current assets 1,482 2,127
Assets held for sale 334 -
Total assets 9,897 12,566
Liabilities and Equity
Borrowings net of transaction fees 509 1,238
Decommissioning provisions 4,021 4,141
Deferred tax liabilities 1,260 397
Lease creditor 673 825
Derivative liabilities 284 3,450
Other liabilities 1,368 1,494
Liabilities directly associated with assets held for sale 242 -
Total liabilities 8,357 11,545
Equity 1,540 1,021
Total liabilities and equity 9,897 12,566
Net debt (213) (704)
Assets
The decrease in total assets of $2,669 million is mainly as a result of the
move from a net deferred tax asset position of $1,009 million to a net
deferred tax liability of $1,253 million primarily driven by the realisation
of the hedging position, reduction in property, plant and equipment (PP&E)
of $973 million, lower right-of-use assets, which have reduced by $148
million, partially offset by an increase to intangible assets of $292 million.
Total assets included assets held for sale in respect of the Vietnam disposal
of $334 million.
Liabilities
The reduction in total liabilities of $3,188 million is mainly driven by a
reduction in derivative liabilities of $3,166 million following maturity of
contracts and lower commodity prices in the year, a reduction in borrowings of
$729 million mainly related to the repayment of the reserves-based lending
(RBL) facility and the move to a net deferred tax liability position mentioned
above. The decommissioning provision decrease of $120 million was due to
changes in cost estimates mainly driven by increased discount rates and spend
in the year, partially offset by the unwinding of the discount. Total
liabilities included liabilities directly associated with assets held for sale
in respect of the Vietnam disposal of $242 million.
The net deferred tax position on the balance sheet is a liability of $1,253
million. This is primarily made up of a deferred tax liability in respect of
the future profits which will flow from our PP&E of $2,901 million offset
by a deferred tax asset in respect of future tax relief on decommissioning
spend of $1,574 million. Whilst our future UK profits in the period to 31
March 2028 will be subject to 75 per cent taxation due to the EPL, UK
decommissioning spend is not deductible for EPL and so relieved at 40 per
cent.
Equity and reserves
Total equity increased mainly due to the gains in comprehensive income related
to favourable fair market value movements on cash flow hedges of $3,168
million (2022: $269 million), gains on currency translation of $103 million
(2022: losses of $198 million), offset by movements in tax on cash flow hedges
of $2,376 million (2022: gains of $1,006 million), share buybacks of $249
million (2022: $361 million) and dividend payments of $190 million (2022: $191
million) made in the year. Retained earnings increased by the profit after
tax.
Net debt
As at 31 December 2023, net debt of $213 million (2022: $704 million)
consisted of cash balances of $280 million (2022: $500 million), net of the
$500 million bond (2022: $500 million) adjusted for unamortised fees of $7
million (2022: $9 million). Following net repayments of the RBL facility of
$775 million and settlement in full of the exploration finance facility (EFF)
of $11 million, the RBL facility is $nil (2022: $775 million less unamortised
fees of $73 million) and the EFF is $nil (2022: $11 million). The remaining
$61 million unamortised fees for the RBL have been reclassified to debtors.
The RBL facility was amended and extended in November 2023 which resulted in
the debt availability of $1.3 billion. Available liquidity, being undrawn RBL
facility plus cash balances of $0.3 billion, was $1.6 billion at the end of
the year.
As at 31 December 2023, the leverage ratio(1) was 0.1x (2022: 0.2x) which has
reduced primarily as a result of repayments of the RBL facility during the
year resulting in nil drawdown at year end.
2023 2022
$million $million
Leverage ratio
Net debt(1) 213 704
EBITDAX(1) 2,675 4,010
Leverage ratio(1) 0.1x 0.2x
(1) Non-IFRS measure - see Glossary for the definition.
Derivative financial instruments
We carry out hedging activity to manage commodity price risk, to ensure we
comply with the requirements of the RBL facility and to ensure there is
sufficient funding for future investments. We have entered into a series of
fixed-price sales agreements and a financial hedging programme for both oil
and gas, consisting of swap and option instruments. Our future production
volumes are hedged under the physical and financial arrangements in place at
31 December 2023. These are set out in the following table. Hedges realised to
date are in respect of both crude oil and natural gas.
The current hedging programme is shown below:
Hedge position 2024 2025 2026
Oil
Volume hedged (mmboe) 7.32 4.38 -
Average price hedged ($/bbl) 84.37 77.35 -
UK natural gas
Volume hedged (mmboe) 13.08 7.38 1.55
Average priced hedged (p/therm) 67.19 89.68 99.28
At 31 December 2023, our financial hedging programme on commodity derivative
instruments showed a pre-tax negative mark-to-market fair value of $18 million
(2022: $3,257 million), with no ineffectiveness charge to the income
statement.
Statement of cash flows(1)
2023 2022
$million $million
Cash flow from operating activities after tax 2,144 3,130
Cash flow from investing activities - capital investment (718) (634)
Cash flow from investing activities - other 25 5
Operating cash flow after investing activities 1,451 2,501
Cash flow from financing activities(2) (409) (396)
Free cash flow(3) 1,042 2,105
Cash and cash equivalents 280 500
1 Table excludes financing activities related to debt principal movements.
2 Interest and lease payments only, excludes shareholder distributions.
3 Non-IFRS measure - see Glossary for the definition.
Net cash from operating activities after tax amounted to $2,144 million (2022:
$3,130 million) after accounting for positive working capital movements of
$199 million, including movements in realised but unsettled hedges of $207
million (2022: $104 million). Capital investment was $718 million (2022: $634
million) which included property, plant and equipment additions of $496
million (2022: $477 million) and exploration and evaluation additions of $202
million (2022: $127 million). Cash outflow from financing activities totalled
$409 million (2022: $396 million) split between interest payments of $150
million (2022: $142 million) and lease payments of $259 million (2022: $254
million).
Shareholder distributions consist of dividends paid of $190 million (2022:
$191 million) and $249 million (2022: $361 million) related to the repurchase
of Harbour's own shares.
The Group made net tax payments of $438 million in the period (2022: $552
million) primarily in relation to the UK Energy Profits Levy.
Cash and cash equivalent balances were $280 million (2022: $500 million) at
the end of the year.
Capital investment is defined as additions to property, plant and equipment,
fixtures and fittings and intangible exploration and evaluation assets,
excluding changes to decommissioning assets.
2023 2022
$million $million
Additions to oil and gas assets (482) (532)
Additions to fixtures and fittings, office equipment & IT software (29) (42)
Additions to exploration and evaluation assets (210) (111)
Total capital investment(1) (721) (685)
Movements in working capital (22) 28
Capitalised interest 7 1
Capitalised lease payments 18 22
Cash capital investment per the cash flow statement (718) (634)
(1) Non-IFRS measure - see Glossary for the definition.
During the year, the Group incurred total capital expenditure(1) of $969
million (2022: $908 million), split by capital investment $721 million (2022:
$685 million) and decommissioning spend $248 million (2022: $223 million)
respectively.
The capital investment in the UK mainly consisted of, for operated assets,
development drilling in the J-Area, including at Talbot, the tie in of
Tolmount East to Tolmount, the appraisal of the Leverett discovery which is
close to the Britannia platform and long lead items for the Callanish and
North Seymour infill wells at our GBA and AELE hubs respectively. For partner
operated assets, capital investment consisted primarily of the tie in of two
subsea wells at Beryl, and drilling at Buzzard, Clair and Schiehallion. In
International, exploration wells were drilled at Layaran-1 in Indonesia, the
JDE well in Norway and the Kan and Ix-1EXP wells in Mexico.
Principal risks
There are no significant changes to the headline principal risks from those
disclosed in the 2023 half-year results.
Post balance sheet events
On 5 March 2024 Harbour signed a new $3.0 billion fully unsecured revolving
credit facility (RCF) and $1.5 billion bridge facility which will be available
at completion to fund the acquisition of the Wintershall Dea asset portfolio.
The RCF has a $1.75 billion letter of credit sublimit, a five-year term from
signing and will replace the existing RBL facility.
On 6 March 2024, the UK government announced that Energy Profit Levy (EPL)
would be extended for a further 12 months to 31 March 2029 from the former end
date of 31 March 2028. Harbour is currently assessing the potential impact of
this announcement.
Going concern
The Directors consider the going concern assessment period to be up to 30 June
2025. The Group monitors and manages its capital position and its liquidity
risk regularly throughout the year to ensure that it has access to sufficient
funds to meet forecast cash requirements. Cash forecasts are regularly
produced, and sensitivities considered based on, but not limited to, the
Group's latest life of field production and expenditure forecasts,
management's best estimate of future commodity prices based on recent forward
curves, adjusted for the Group's hedging programme and the Group's borrowing
facilities.
The ongoing capital requirements are financed by the Group's $2.75 billion
reserves-based lending (RBL) facility that has a current borrowing base of
$1.3 billion after the amendment and extension that was completed in November
2023, and $0.5 billion bond which matures in 2026. The amount drawn down under
these facilities at 31 December 2023 was nil and $0.5 billion respectively,
which together with cash of $0.3 billion, gave a total available liquidity of
$1.6 billion. Further details can be found in note 14 on page 45. The RBL
facility has a financial covenant relating to the ratio of consolidated total
net debt to consolidated EBITDAX on a historic and forward-looking basis,
which is tested semi-annually. The amount available under the facility is
redetermined annually based on a valuation of the Group's borrowing base
assets when applying certain forward-looking assumptions, as defined in the
borrowing agreements.
The Group's latest approved business plan underpins the base case going
concern assessment and is based upon management's best estimate of forward
commodity price curves, production in line with approved asset plans,
unavoidable committed fees in respect of the Wintershall Dea acquisition and
the ongoing capital requirements of the Group that will be financed by free
cash flow, the existing RBL and bond financing arrangements.
In December 2023 Harbour announced the Wintershall Dea acquisition
transaction, which is anticipated to complete in Q4 2024 and will be accretive
to Harbour's free cash flow. Once complete, Harbour is expected to receive
investment grade credit ratings and to benefit from a significantly lower cost
of financing, including the porting of existing euro denominated Wintershall
Dea bonds with a nominal value of approximately $4.9 billion and a weighted
average coupon of c.1.8 per cent; the Group would also have access to a new
$3.0 billion revolving credit facility and $1.5 billion bridge facility. As
part of the going concern assessment, a base case, sensitivities and reverse
stress tests have been run on the enlarged group forecasts, which are
supported by Harbour's acquisition due diligence work, and show that the
probability of a liquidity deficit or covenant breach is remote. The base case
indicates that the Group is able to operate as a going concern with sufficient
headroom and remain in compliance with its loan covenants throughout the
assessment period.
In line with the principal risks that have been identified to impact the
financial capability of the Group to operate as going concern, a single
downside sensitivity scenario has been prepared reflecting a reduction in:
§ Brent crude and UK natural gas prices of 20 per cent, and
§ the Group's unhedged production of 10 per cent
throughout the assessment period.
In this downside scenario when applied individually and in aggregate to the
base case forecast, the Group is forecast to have sufficient liquidity
headroom throughout the assessment period and to remain in compliance with its
financial covenants.
Reverse stress tests have been prepared reflecting further reductions in
commodity price and production parameters, prior to any mitigation strategies,
to determine at what levels each would need to reach such that either the
lending covenant is breached, or liquidity headroom runs out. The results of
these reverse stress tests demonstrated the likelihood that a sustained
significant fall in commodity prices or a significant fall in production over
the assessment period that would be required to cause a risk of funds
shortfall, or a covenant breach is significantly below the sensitivity test
performed and hence remote.
Taking the above analysis into account and considering the findings of the
work performed to support the statement on the long-term viability of the
company and the Group, the Board was satisfied that, for the going concern
assessment period, the Group is able to maintain adequate liquidity and comply
with its lending covenants up to 30 June 2025 and has therefore adopted the
going concern basis for preparing the financial statements.
By order of the Board,
Alexander Krane
Director
6 March 2024
Disclaimer
This statement contains certain forward-looking statements that are subject to
the usual risk factors and uncertainties associated with the oil and gas
exploration and production business. Whilst Harbour believes the expectations
reflected herein to be reasonable in light of the information available to
them at this time, the actual outcome may be materially different owing to
factors beyond Harbour's control or within Harbour's control where, for
example, Harbour decides on a change of plan or strategy. Accordingly, no
reliance may be placed on the figures contained in such forward-looking
statements.
Financial Statements
Consolidated income statement
For the year ended 31 December 2023
Note 2023 2022
$ million $ million
Revenue 4 3,715 5,390
Other income 4 36 41
Revenue and other income 3,751 5,431
Cost of operations 5 (2,357) (2,845)
(Impairment)/impairment reversal of property, plant, and equipment 10 (214)
170
Impairment of goodwill (25) -
Exploration and evaluation expenses and new ventures 5 (36) (42)
Exploration costs written-off 9 (57) (64)
Gain on disposal 5 - 12
General and administrative expenses 5 (149) (121)
Operating profit 5 913 2,541
Finance income 6 104 279
Finance expenses 6 (420) (358)
Profit before taxation 597 2,462
Income tax expense 7 (565) (2,454)
Profit for the year 32 8
Profit for the year attributable to:
Equity owners of the company 32 8
Earnings per share Note $ cents $ cents
Basic 8 4 1
Diluted 8 4 1
Consolidated statement of comprehensive income
For the year ended 31 December 2023
2023 2022
$ million $ million
Profit for the year 32 8
Other comprehensive profit
Items that may be reclassified to the income statement:
Fair value gains on cash flow hedges 3,168 269
Tax (expense)/credit on cash flow hedges (2,376) 1,006
Exchange differences on translation 103 (198)
Other comprehensive profit for the year, net of tax 895 1,077
Total comprehensive profit for the year, net of tax 927 1,085
Total comprehensive profit attributable to:
Equity owners of the company 927 1,085
Consolidated balance sheet
As at 31 December 2023
Note 2023 2022
$ million $ million
Assets
Non-current assets
Goodwill 1,302 1,327
Other intangible assets 9 1,172 880
Property, plant and equipment 10 4,717 5,690
Right-of-use assets 11 587 735
Deferred tax assets 7 7 1,406
Other receivables 184 298
Other financial assets 15 112 103
Total non-current assets 8,081 10,439
Current assets
Inventories 200 143
Trade and other receivables 832 1,403
Other financial assets 15 170 81
Cash and cash equivalents 280 500
1,482 2,127
Assets held for sale 12 334 -
Total current assets 1,816 2,127
Total assets 9,897 12,566
Equity and liabilities
Equity
Share capital 171 171
Other reserves 289 (606)
Retained earnings 1,080 1,456
Total equity 1,540 1,021
Non-current liabilities
Borrowings 14 493 1,216
Provisions 13 3,818 3,934
Deferred tax 7 1,260 397
Trade and other payables 13 19
Lease creditor 11 474 604
Other financial liabilities 15 87 1,279
Total non-current liabilities 6,145 7,449
Current liabilities
Trade and other payables 886 1,252
Borrowings 14 16 22
Lease creditor 11 199 221
Provisions 13 230 231
Current tax liabilities 442 199
Other financial liabilities 15 197 2,171
1,970 4,096
Liabilities directly associated with the assets held for sale 12 242 -
Total current liabilities 2,212 4,096
Total liabilities 8,357 11,545
Total equity and liabilities 9,897 12,566
The notes 1 to 19 form an integral part of these financial statements.
Consolidated statement of changes in equity
For the year ended 31 December 2023
Share capital Share premium(1) Merger reserve(1) Capital redemption reserve Cash flow hedge reserve(2) Costs of hedging reserve(2) Currency translation reserve Retained earnings Total
$ million $ million $ million $ million $ million $ million $ million $ million equity
$ million
At 1 January 2022 171 1,505 677 8 (2,062) 2 98 75 474
Profit for the year - - - - - - - 8 8
Other comprehensive income - - - - 1,286 (11) (198) - 1,077
Total comprehensive income - - - - 1,286 (11) (198) 8 1,085
Purchase and cancellation of own shares - - - - - - - (361) (361)
Share-based payments - - - - - - - 36 36
Capital restructuring(1) - (1,505) (406) - - - - 1,911 -
Purchase of ESOP Trust shares - - - - - - - (22) (22)
Dividend paid - - - - - - - (191) (191)
At 31 December 2022 171 - 271 8 (776) (9) (100) 1,456 1,021
Profit for the year - - - - - - - 32 32
Other comprehensive income - - - - 779 13 103 - 895
Total comprehensive income - - - - 779 13 103 32 927
Purchase and cancellation of own shares - - - - - - - (249) (249)
Share-based payments - - - - - - - 46 46
Purchase of ESOP Trust shares - - - - - - - (15) (15)
Dividend paid - - - - - - - (190) (190)
At 31 December 2023 171 - 271 8 3 4 3 1,080 1,540
(1) In 2022, share premium and merger reserve balances were recategorised to
retained earnings following the capital reduction effective 3 August 2022.
(2) Disclosed net of deferred tax.
(
)
Consolidated statement of cash flows
For the year ended 31 December 2023
Note 2023 2022
$ million $ million
Net cash inflows from operating activities 16 2,144 3,130
Investing activities
Expenditure on exploration and evaluation assets (202) (127)
Expenditure on property, plant and equipment 10 (496) (477)
Expenditure on non-oil and gas intangible assets (20) (30)
Expenditure on other intangible assets (81) -
Receipts for sub-lease income 10 10
Proceeds from/payments relating to disposal of oil and gas properties 3 (6)
Expenditure on business combinations - deferred consideration - (19)
Finance income received 93 20
Net cash outflows used in investing activities (693) (629)
Financing activities
Repurchase of shares (249) (361)
Proceeds from new borrowings - reserves-based lending facility 14 660 -
Proceeds from new borrowings - exploration finance facility 14 - 11
Lease liability payments (259) (254)
Repayment of reserves-based lending facility 14 (1,435) (1,663)
Repayment of exploration finance facility 14 (11) (38)
Repayment of financing arrangement 14 (21) (15)
Purchase of ESOP Trust shares (12) (21)
Interest paid and bank charges (150) (142)
Dividends paid 18 (190) (191)
Net cash outflows from financing activities (1,667) (2,674)
Net decrease in cash and cash equivalents (216) (173)
Net foreign exchange difference (4) (26)
Cash and cash equivalents at 1 January 500 699
Cash and cash equivalents at 31 December 280 500
Notes to the consolidated financial statements
1. General information
Harbour Energy plc ('Harbour') is a limited liability company incorporated in
Scotland and listed on the London Stock Exchange. The address of the
registered office is 4th Floor, Saltire Court, 20 Castle Terrace, Edinburgh,
EH1 2EN, United Kingdom.
The financial information for the year ended 31 December 2023 and 2022
contained in this document does not constitute statutory accounts of Harbour
Energy plc (the Company), as defined in section 435 of the Companies Act 2006.
The financial information for the years ended 31 December 2023 and 2022 have
been extracted from the consolidated financial statements of Harbour Energy
plc and all its subsidiaries (the Group), which were authorised for issued by
the Board of Directors on 6 March 2024 and will be delivered to the Registrar
of Companies in due course. The auditor's report on those financial statements
was unqualified and did not contain a statement under section 498 of the
Companies Act 2006.
The Group's principal activities are the acquisition, exploration, development
and production of oil and gas reserves on the UK and Norwegian continental
shelves, Indonesia, Vietnam and Mexico.
2. Basis of preparation and significant accounting policies
2.1 Basis of preparation
The consolidated financial statements have been prepared on a going concern
basis in accordance with UK-adopted International Accounting Standards (IAS)
in conformity with the requirements of the Companies Act 2006. The analysis
used by the Directors in adopting the going concern basis considers the
various plans and commitments of the Group as well as various sensitivity and
reverse stress test analyses. The results from the downside sensitivities with
regard to production and commodity price assumptions, which in management's
view reflect two of the principal risks, indicate that material changes within
one year that would impact the going concern basis of preparation are
unlikely. Further details are within the Financial Review.
The presentation currency of the Group financial information is US dollars and
all values in the Group financial information are presented in millions ($
million) and all values are rounded to the nearest 1 million, except where
otherwise stated.
The financial statements have been prepared on the historical cost basis,
except for certain financial assets and liabilities, including derivative
financial instruments, which have been measured at fair value.
2.2 Accounting policies
The accounting policies adopted in the preparation of the 2023 consolidated
financial statements are consistent with those adopted and disclosed in
Harbour's 2022 Annual Report and Accounts. A number of amendments to existing
standards and interpretations were effective from 1 January 2023 but had no
impact on the full-year financial statements. The Group has not early adopted
any standard, interpretation or amendment that has been issued but is not yet
effective.
2.3 Basis of consolidation
The consolidated financial statements comprise the financial statements of the
Company and its subsidiaries as at 31 December 2023. Subsidiaries are those
entities over which the Group has control. Control is achieved where the Group
has the power over the subsidiary, has rights, or is exposed to variable
returns from the subsidiary and has the ability to use its power to affect its
returns. All subsidiaries are 100 per cent owned by the Group and there are no
non-controlling interests.
If the Group loses control over a subsidiary, it derecognises the related
assets (including goodwill), liabilities, non-controlling interest and other
components of equity, while any resultant gain or loss is recognised in profit
or loss. Any investment retained is recognised at fair value.
The results of subsidiaries acquired or disposed of during the year are
included in the income statement from the effective date of acquisition or up
to the effective date of disposal, as appropriate. Where necessary,
adjustments are made to the financial statements of subsidiaries acquired to
bring the accounting policies used into line with those used by other members
of the Group.
All intra-group transactions and balances have been eliminated on
consolidation.
2.4 Use of judgements and estimates
In preparing these financial statements, management has made judgements and
estimates that affect the application of accounting policies and the reported
amounts of assets and liabilities, income and expenses. Actual results may
differ from these estimates. The significant judgements made by management in
applying the Group's accounting policies, and the key sources of estimation
uncertainty, were the same as those described in Harbour's 2022 Annual Report
and Accounts, apart from change in the judgement associated with tax due to a
reduction in judgement required in 2023 with regards to deferred tax
associated with the UK Energy Profits Levy (EPL) but an increase in judgements
around uncertain tax positions. Disclosure regarding the judgements and
estimates made in assessing the impact of climate change and the energy
transition are detailed below.
2.5 Impact of climate change on the financial statements and related
disclosures
Judgements and estimates made in assessing the impact of climate change and
the energy transition
Harbour monitors global climate change and energy transition developments and
plans. Management recognises there is a general high level of uncertainty
about the speed and scale of impacts which, together with limited historical
information, provides challenges in the preparation of forecasts and plans
with a range of possible future scenarios which may have the potential to
materially impact the balance sheet.
The Group's continued strategic ambition is to achieve net zero by 2035 with
an interim target of a 50 per cent reduction in Scope 1 and 2 emissions by
2030 against the 2018 baseline. This will be achieved through several
opportunities including operational efficiency improvements, potential partial
UK offshore electrification and the eventual cessation of production of mature
fields. In addition, the company is investing in the development of carbon
capture and storage projects in the UK. Where the Group cannot reduce its
Scope 1 and 2 emissions, it will invest in high quality, independently
verified, carbon offsets to achieve the goal of net zero.
All new economic investment decisions include the cost of carbon, and
opportunities are assessed on their climate-impact potential and alignment
with Harbour Energy's net zero goal, taking into consideration both GHG
volumes and intensity. The corporate modelling that supports the preparation
of the financial statements (such as asset and goodwill impairment assessment,
going concern and viability, deferred tax asset recoverability) includes
project costs related to CCS, certain limited electrification and other
activities to reduce Scope 1 and 2 GHG emissions, the UK Emissions Trading
Scheme cost and carbon offset purchases.
Emissions reduction incentives are part of staff remuneration through the
annual bonus program. Additionally, the cost of borrowing is tied to our gross
operated CO(2) emissions performance, with GHG metrics being linked to our RBL
interest expense, further incentivising our emissions reduction targets.
Climate change and the energy transition have the potential to significantly
impact the accounting estimates adopted by management and therefore the
valuation of assets and liabilities reported on the balance sheet. On an
ongoing basis management continues to assess the potential impacts on the
significant judgements and estimates used in the preparation of the financial
statements. Estimates adopted in the financial statements reflect management's
best estimate of future market conditions where, in particular, commodity
prices can be volatile. Commodity and carbon price curve assumptions are
described below noting that there is consideration given to other assumptions,
not exhaustively, such as foreign exchange and discount rates. Notwithstanding
the challenges around climate change and the energy transition, it is
management's view that the financial statements are consistent with the
disclosures in the Strategic report.
This note provides insight into how Harbour has considered the impact on
valuations of key line items in the financial statements and how they could
change based on the climate change scenarios and sensitivities considered. The
scenarios presented show what the possible impact could be on the financial
statements considering both high and low-price commodity price outlooks.
Importantly, these climate change scenarios do not form the basis of the
preparation of the financial statements but rather indicate how the key
assumptions that underpin the financial statements would be impacted by the
climate change scenarios. They are also designed to challenge management's
perspective on the future business environment. It is recognised that the
reality of the nature of progress of energy transition may bring greater
levels of disruption and volatility than these external scenarios expect and
do not represent management's current best estimate.
Management's current best estimate for the foreseeable future, which was
derived from consideration of a range of considered economic forecasts, has
been used on the same basis to prepare the financial statements and is
represented by the Harbour scenario oil price curve. Management continues to
review these estimates and assumptions to ensure they reflect the latest
economic environment conditions and market information available.
Impairment of property, plant and equipment, and goodwill
The energy transition has the potential to significantly impact future
commodity and carbon prices which would, in turn, affect the future operating
and capital costs, estimates of cessation of production, useful lives, and
consequently the recoverable amount of property, plant and equipment and
goodwill. In the current period, when testing for impairment, the Harbour
scenario real long-term commodity price assumptions from 2026 for Brent crude
were $70/bbl (2022: $65/bbl) and UK NBP gas 90 pence/therm (2022: 65
pence/therm) combined with the short term forecast period reflecting market
forward curves at the year end.
Carbon costs will develop over time and carry considerable uncertainty due to
the rate of transition and maturity of regulatory regimes. For the UK price of
carbon, Harbour management's real forward price curve assumption in 2024 is
£50/tonne ($63/tonne) rising to £140/tonne ($175/tonne) in 2030. The
sensitivity was run on the IEA Net Zero carbon price curve. The foreign
exchange rate was assumed to be $1.00:£1.25 flat for future periods to
convert to nominal prices. Such assumptions are inherently uncertain and may
ultimately differ from the actual amounts.
During 2023 there was a total net pre-tax impairment charge of $239 million
(2022: $170 million) across goodwill of $25 million and property, plant and
equipment $214 million. Further details on the latter amount can be found in
and note 10.
Further, sensitivities on the impairment of property, plant and equipment and
goodwill have been prepared using various commodity price scenarios to show
the possible impact on net book carrying values. As noted, the Harbour
scenario is the basis for the preparation of the financial statements.
Impairment sensitivities have been prepared at an average -10 per cent and +10
per cent to the Harbour scenario average for crude, gas and carbon and
selected published climate change price curves.
The sensitivity scenarios described below incorporate changes to the commodity
price assumptions and assumes that all other factors remain unchanged from the
Harbour scenario used for the basis of preparation of the financial
statements. These sensitivities are stated before any management mitigation
actions to manage downside risks if the scenarios were to occur.
This analysis covers the transition risks and the graphs below show the crude
oil and UK NBP gas price curves for the period to 2050 for the following
scenarios: IEA Net Zero 2050, IEA Stated Policies and IEA Announced Pledges.
All the scenario price curves are dependent on factors covering supply,
demand, economic and geopolitical events and therefore are inherently
uncertain and subject to significant volatility and hence unlikely to reflect
the future outcome.
§ Harbour scenario base price curves used for impairment testing
§ IEA Net Zero Emissions by 2050 (NZE) limiting global temperature rise to
1.5(o)C
§ IEA Stated Policies (STEPS) current policy commitments by sector and
country
§ IEA Announced Pledges (APS) current climate commitments by governments and
industries
The crude price curves reflect the published IEA price curves for all periods.
For UK NBP gas there are no IEA published price curves therefore management
has derived the UK NBP gas price curves by converting from the published IEA
European gas price curve. The was achieved by converting from USD per mbtu to
pence per therm and applying other known correlation coefficients between the
European and UK gas markets. In addition, for the period for 2024-2027, the
derived gas price curve matches the Harbour scenario price curve to create a
scenario that was considered reasonably plausible.
Pre-development assets such as Zama in Mexico and Andaman in Indonesia are
recorded in other intangible assets ahead of demonstration of commerciality
and recognition of 2P reserves and hence are not included below. However, they
are subject to the same management rigour with the corporate models.
The results of the sensitivities are as follows and show the impact on the
property, plant and equipment balance sheet carrying values when it had
resulted in a material decrease in carrying value.
Commodity Carrying value Pre-tax sensitivity in carrying value
$ million $ million
+10% price to Harbour scenario -10% price to Harbour IEA Net Zero Emissions by 2050 IEA Stated Policies IEA Announced Pledges
scenario (NZE) (STEPS) (APS)
Property, plant, and equipment (note 10) Crude Oil 4,717 - (86) (221) - -
UK NBP Gas - (21) (9) - -
(derived)
Carbon - - (27)
The +/-10% price curves used in the Harbour scenarios adjust long-term prices
from 2027.
Under the -10% price to Harbour scenario for crude there is a pre-tax
impairment to property, plant and equipment on two UK fields of $86 million
(post-tax $40 million) and for UK NBP gas a pre-tax impairment on a single UK
field of $21 million (post-tax $6 million).
For crude, under the IEA NZE 2050 scenario, there is a pre-tax impairment to
property, plant and equipment on a single UK field of $221 million (post-tax
$104 million) and for UK NBP gas, there is a pre-tax impairment on two UK
fields of $9 million (post-tax $3 million). For carbon, under all scenarios
carbon price does not drive a material change in carrying value as they are
not a sensitive and material assumption in the cash flow forecasts. There is
no impairment to property, plant and equipment across the three +10% price to
Harbour scenarios nor the IEA STEPS and APS scenarios.
Under the IEA Net Zero Emissions by 2050 scenario for carbon, there is a
pre-tax impairment to property, plant and equipment on a single UK field of
$27 million (post-tax $13 million).
For goodwill, there are no impairments under any scenario except for the -10%
price to Harbour scenario for UK NBP gas which reflects an impairment of $4
million.
Property, plant and equipment - depreciation and expected useful lives
A significant proportion of property, plant and equipment assets are expected
to reach cessation of production over the next 10 to 20 years. The energy
transition has the potential to reduce the expected useful lives of assets and
consequently accelerate the cessation of production dates and increase the
rate at which depreciation is charged. There are no significant judgements
and/or critical estimation uncertainty related to climate factors.
Intangible assets - exploration and evaluation assets
The energy transition has the potential to affect the future development or
viability of exploration and evaluation prospects. A significant portion of
the Group's exploration and evaluation assets relate to prospects that could
be tied back to existing infrastructure and hence require less capital
investment as these assets are less exposed to the impacts of the energy
transition compared to large frontier developments. At each balance sheet
date, all exploration and evaluation prospects are reviewed against the
Group's financial framework to ensure that the continuation of activities is
planned and expected. There are no significant judgements and/or critical
estimation uncertainty related to climate factors.
Decommissioning cost and provisions
The energy transition may accelerate the decommissioning of assets which would
result in an increase in the carrying value of associated decommissioning
provisions. Whilst the Group currently expects to incur decommissioning costs
over the next 40 years, we anticipate the majority of costs will be incurred
between the next 10 to 20 years which will reduce the exposure to the impact
of the energy transition. Decommissioning cost estimates are based on the
current regulatory and external environment. These cost estimates and
recoverability of associated deferred tax may change in the future, including
as a result of the energy transition.
On the basis that all other assumptions in the calculation remain the same, a
10 per cent increase in the cost estimates, and a 10 per cent reduction in the
applied discount rates used to assess the final decommissioning obligation,
would result in increases to the decommissioning provision of approximately
$456 million and $440 million, respectively. This change would be principally
offset by a change to the value of the associated asset unless the asset is
fully depreciated, in which case the change in estimate is recognised directly
within the income statement.
Currently, the timing of decommissioning expenditures has not been materially
brought forward and management do not consider that any reasonable change in
the timing of decommissioning expenditure will have a material impact on the
decommissioning provisions.
3. Segment information
The chief operating decision maker, who is responsible for allocating
resources and assessing performance of the Group's business segments, has been
identified as the Chief Executive Officer.
The Group's activities consist of one class of business, being the
acquisition, exploration, development and production of oil and gas reserves
and related activities and are split geographically and managed in two
regions: namely North Sea and International. The North Sea segment includes
the UK and Norwegian continental shelves, and the International segment
includes Indonesia, Vietnam and Mexico.
Information on major customers can be found in note 4.
Income statement
2023 2022
$ million $ million
Revenue
North Sea 3,478 5,082
International 237 308
Total Group sales revenue 3,715 5,390
Other income
North Sea 36 41
International - -
Total Group revenue and other income 3,751 5,431
Group operating profit
North Sea 898 2,388
International 15 153
Group operating profit 913 2,541
Finance income 104 279
Finance expenses (420) (358)
Profit before income tax 597 2,462
Income tax expense (565) (2,454)
Profit for the year 32 8
Balance sheet
2023 2022
$ million $ million
Segment assets
North Sea 8,632 11,346
International 1,265 1,220
Total assets 9,897 12,566
Segment liabilities
North Sea (7,818) (10,938)
International (539) (607)
Total liabilities (8,357) (11,545)
Other information
2023 2022
$ million $ million
Capital additions
North Sea 611 576
International 110 109
Total capital additions 721 685
Depreciation, depletion and amortisation
North Sea 1,369 1,471
International 61 75
Total depreciation, depletion and amortisation 1,430 1,546
Exploration and evaluation expenses and new ventures
North Sea 36 34
International - 8
Total exploration and evaluation expenses and new ventures 36 42
Exploration costs written-off
North Sea 38 71
International(1) 19 (7)
Total exploration costs written-off 57 64
(1 ) ( )In 2022, International included a credit to the income statement
related to a change to the decommissioning estimate in the Falkland Islands
business unit.
4. Revenue from contracts with customers and other income
2023 2022
$ million $ million
Type of goods
Crude oil sales 2,086 2,792
Gas sales 1,415 2,322
Condensate sales 179 238
Total revenue from contracts with customers(1) 3,680 5,352
Tariff income 30 30
Other revenue 5 8
Revenue from production activities 3,715 5,390
Other income(2) 36 41
Total revenue and other income 3,751 5,431
(1) Revenues from contracts with customers of $4,591 million (2022: $8,537
million) include crude oil sales of $2,179 million (2022: $3,545 million) and
gas sales of $2,233 million (2022: $4,754 million). This was prior to realised
hedging losses in the period of $93 million (2022: $753 million) on crude oil
and $818 million (2022: $2,432 million) on gas sales.
(2) Other income mainly represents partner recoveries related to lease
obligations and, in 2023 a receipt related to the Viking CCS Development
Agreement that was signed in March.
Approximately 88 per cent (2022: 84 per cent) of the revenues were
attributable to sales to energy trading companies of the Shell group.
5. Operating profit
Note 2023 2022
$ million $ million
Cost of operations
Production, insurance and transportation costs 1,171 1,114
Gas purchases 12 36
Royalties 4 5
Depreciation of oil and gas assets 10 1,192 1,319
Depreciation of right-of-use oil and gas assets 11 230 219
Capitalisation of IFRS 16 lease depreciation on oil and gas assets 11 (27) (30)
Amortisation of oil and gas intangible assets - 1
Movement in over/underlift balances and hydrocarbon inventories (225) 181
Total cost of operations 2,357 2,845
Impairment expense/(reversal) of property, plant and equipment 10 108 (88)
Impairment loss/(gain) due to increase in decommissioning provision 10 106 (82)
Impairment of goodwill 25 -
Exploration costs written-off(1) 9 57 64
Exploration and evaluation expenditure and new ventures(2) 36 42
Gain loss on disposal(3) - (12)
General and administrative expenses
Depreciation of right-of-use non-oil and gas assets 11 9 11
Depreciation of non-oil and gas assets 10 3 5
Amortisation of non-oil and gas intangible assets 9 23 21
Other administrative costs(4) 114 84
Total general and administrative expenses 149 121
Auditors' remuneration
Audit fees
Fees payable to the company's auditor for the company's Annual Report 3
3
Audit of the company's subsidiaries pursuant to legislation 1 1
Non audit fees(5)
Other services pursuant to legislation - interim review - -
Other services(6) 1 1
1 Exploration costs written-off of $57 million (2022: $64 million) includes
$13 million related to the Ix-1EXP well in Mexico, $15 million related to the
JDE well in Norway and also includes costs associated with licence
relinquishments and uncommercial well evaluations and $4 million related to an
increase in decommissioning provisions in the North Sea (note 13).
2 Exploration and evaluation expenditure and new ventures of $36 million
(2022: $42 million) includes $29 million (2022: $28 million) of early project
costs on new ventures incurred in respect of the Group's interest in CCS and
electrification projects in the UK, plus $7 million (2022: $13 million) of
ongoing pre-licence costs.
3 The gain on disposal in 2022 of $12 million relates to the release of a
provision associated with Premier's sale of its legacy Pakistan assets in 2019
after the expiry of the deadline in the period for tax claims to be submitted.
4 Other administrative costs in 2023 include consultancy costs of $33 million
(2022: $9 million).
5 The Company has a policy on the provision of non-audit services by the
auditor which is aimed at ensuring their continued independence. This policy
is available on the Group's website. The use of the external auditor for
services relating to accounting systems, financial statement preparations is
not permitted, as are various other services including some advisory services
that could give rise to conflicts of interest or other threats to the
auditor's objectivity that cannot be reduced to an acceptable level by
applying safeguards.
6 Other non-audit services in 2023 primarily relate to transaction related
activities.
6. Finance income and finance expenses
Note 2023 2022
$ million $ million
Finance income
Bank interest 19 10
Other interest and finance gains 6 20
Lease finance income 2 2
Realised gains on interest rate swaps - 6
Realised gains on foreign exchange forward contracts 9 1
Gains on derivatives(1) 68 38
Foreign exchange gains(2) - 202
Total finance income 104 279
Finance expenses
Interest payable on reserves-based lending 15 71
Interest payable on bond 27 27
Other interest and finance expenses 17 12
Lease interest 11 51 25
Losses on derivatives(1) - 48
Finance expense on deferred revenue 4 20
Foreign exchange losses 57 -
Bank and financing fees(3) 100 91
Unwinding of discount on decommissioning and other provisions 13 156 65
427 359
Finance costs capitalised during the year(4) (7) (1)
Total finance expense 420 358
(1) Gains and losses on derivatives relate to changes in the fair value of
an embedded derivative within one of the Group's gas contracts (2022: $48
million loss on derivatives). Gains on derivatives in 2022 included mark to
market gains on unrealised interest rate and foreign exchange derivatives.
(2) In 2022, significant unrealised foreign exchange gains arose mainly from
the revaluation of open gas hedges denominated in sterling.
(3) Bank and financing fees include an amount of $48 million (2022: $55
million) relating to the amortisation of arrangement fees and related costs
capitalised against the Group's long-term borrowings (note 14).
(4) The amount of finance costs capitalised was determined by applying the
weighted average rate of finance costs applicable to the borrowings of the
Group of 6.0 per cent to the expenditures on the qualifying assets (2022: 4.4
per cent).
7. Income tax
2023 2022
$ million $ million
Current income tax expense:
UK corporation tax 641 672
Overseas tax 14 53
Adjustment in respect of prior years 22 (19)
Total current income tax expense 677 706
Deferred tax (credit)/expense:
UK corporation tax(1) (74) 1,772
Overseas tax (18) (8)
Adjustment in respect of prior years (20) (16)
Total deferred tax (credit)/expense (112) 1,748
Total income tax expense reported in the income statement 565 2,454
The tax expense/(credit) in the statement of comprehensive income is as
follows:
Tax expense/(credit) on cash flow hedges 2,376 (1,006)
1 2022 includes a $1,469 million charge in respect of the revaluation of the
deferred tax on the balance sheet due to the introduction of the Energy
Profits Levy.
Reconciliation of tax expense and the accounting profit before taxation
multiplied by the statutory rate of corporation tax and supplementary charge
applying to UK oil and gas production operations for the years ended 31
December 2023 and 2022 is, as follows:
2023 2022
$ million $ million
Profit before income tax 597 2,462
At the Group's statutory income tax rate of 75.0% (2022: 55.0%) 448 1,354
Effects of:
Expenses/ (income) not deductible/ (taxable) for tax purposes 101 (12)
Interest not deductible for supplementary charge and Energy Profits Levy 60 53
Adjustments in respect of prior years 2 (36)
Remeasurement of deferred tax 13 (72)
Deferred Energy Profits Levy - 1,469
Impact of different tax rates (29) (190)
Expenses not deductible for Energy Profits Levy 52 8
Energy Profits Levy investment allowance (64) (81)
Investment allowance (18) (39)
Total tax expense reported in the consolidated income statement at the 565 2,454
effective tax rate of 95% (2022: 100%)
The effective tax rate for the year was 95 per cent, compared to 100 per cent
for 2022.
The tax expense reconciliation has been prepared based on the statutory rate
of taxation applying to UK oil and gas production because the majority of
Group profit was generated on the UK continental shelf. UK oil and gas
production is taxed at a rate of 30 per cent (2022: 30 per cent), a
supplementary charge of 10 per cent (2022: 10 per cent), and with effect from
1 January 2023, the Energy Profits Levy (EPL) of 35 per cent (2022: 25 per
cent) to give an overall tax rate of 75 per cent (2022: 65 per cent). As the
EPL was introduced part way through the previous financial year a blended
average rate of 55 per cent was applied.
The future effective tax rate is impacted by the mix of jurisdictions in which
the Group operates. The UK statutory tax rate for oil and gas production
operations is expected to remain a primary influence on the effective tax
rate. The Energy Profits Levy at the 35 per cent rate is currently in place
until 31 March 2028.
Deferred tax
The principal components of deferred tax are set out in the following tables:
2023 2022
$ million $ million
Deferred tax assets 7 1,406
Deferred tax liabilities (1,291) (397)
(1,284) 1,009
Reclassification of deferred tax liabilities directly associated with assets 31 -
held for sale (note 12)
Total deferred tax (1,253) 1,009
The origination of and reversal of temporary differences are, as shown in the
next table, related primarily to movements in the carrying amount and tax base
value of expenditure and the timing of when these items are changed and are
credited against accounting and taxable profit.
Accelerated capital Decomm-issioning Losses Fair Other Overseas Total
value of derivatives
allowances $ million $ million
$ million $ million deferred tax asset/ (liability)
$ million
$ million $ million
As at 1 January 2022 (2,820) 2,013 1,314 1,392 39 (187) 1,751
Deferred tax (expense)/ credit (658) (362) (745) 49 (40) 8 (1,748)
Comprehensive income - - - 1,006 - - 1,006
Foreign exchange 82 (86) - 5 (2) 1 -
As at 31 December 2022 (3,396) 1,565 569 2,452 (3) (178) 1,009
Deferred tax (expense)/ credit 546 (25) (388) (61) 22 18 112
Comprehensive expense - - - (2,376) 1 - (2,375)
Foreign exchange (51) 34 - (9) 1 (5) (30)
As at 31 December 2023 (2,901) 1,574 181 6 21 (165) (1,284)
The Group's deferred tax assets as at 31 December 2023 are recognised to the
extent that taxable profits are expected to arise against which the tax assets
can be utilised. The Group assessed the recoverability of its UK ring fenced
losses and allowances using corporate assumptions which are consistent with
the Group's impairment assessment. Based on those assumptions, the Group
expects to fully utilise its recognised UK tax losses and allowances. The
recovery of the Group's UK decommissioning deferred tax asset is additionally
supported by the ability to carry back decommissioning tax losses and set
these against ring fence taxable profits of prior periods.
The EPL increased to a rate of 35 per cent from 25 per cent with effect from 1
January 2023. The EPL is currently in place until 31 March 2028. Any temporary
differences subject to the EPL expected to reverse in this period have
consequently been remeasured to the higher rate. Ring fence tax losses cannot
be offset against profits subject to EPL nor are deductions given for
expenditure incurred on decommissioning. Consequently, the deferred tax assets
representing future decommissioning deductions and ring fence tax losses are
not impacted by EPL with the effect of EPL primarily being on the deferred tax
liability associated with accelerated capital allowances. The closing deferred
tax liability for the period of $1,284 million includes $1,014 million of
deferred tax liabilities arising from the impact of EPL.
In line with other sensitivity analysis undertaken, we have assessed the
impact on the recoverability of deferred tax assets based on an average -10
per cent to the Harbour scenario average crude price curves. The sensitivity
analysis indicates that there would no material impact to the recoverability
of deferred tax assets.
The Group has unrecognised UK tax losses and allowances as at 31 December 2023
of approximately $181 million (2022: $202 million) in respect of ring fence
losses, $138 million (2022: $111 million) in respect of ring fence investment
allowance and $803 million (2022: $807 million) in respect of non-ring fence
losses.
The Group also has unrecognised tax losses of approximately $168 million
(2022: $157 million) in respect of its international operations. These losses
include amounts of $13 million which will expire within 10 years and $24
million which will expire within 5 years.
The overseas deferred tax relates mainly to temporary differences associated
with fixed asset balances.
No deferred tax liabilities have been provided on unremitted earnings of
overseas subsidiaries, because due to the application of withholding reliefs
under international double taxation treaties and dividend exemptions under UK
and Netherlands legislation no additional taxation is expected to arise on
future distribution.
Legislation was introduced in UK Finance Act 2021 to increase the main rate of
UK corporation tax for non-ring fence profits from 19 per cent to 25 per cent
from 1 April 2023. This change does not have a material impact on the Group as
the UK profits are primarily subject to the UK ring fence tax rate.
Global minimum corporation tax rate - Pillar Two requirements
The legislation implementing the Organisation for Economic Co-operation and
Development's (OECD) proposals for a global minimum corporation tax rate
(Pillar Two) was substantively enacted into UK law on 20 June 2023. The rules
have effect from 1 January 2024 and therefore the rules do not impact the
Group's results to 31 December 2023.
The Group has applied the mandatory exception to recognising and disclosing
information about the deferred tax assets and liabilities related to Pillar
Two income taxes in accordance with the amendments to IAS 12 published by the
IASB on 23 May 2023.
The Group has performed an assessment of the Group's potential exposure to
Pillar Two income taxes for periods from 1 January 2024. The assessment of the
potential exposure to Pillar Two income taxes is based on the most recent tax
filings, country-by-country reporting and financial statements for the
constituent entities in the Group. Based on the assessment, the Pillar Two
effective tax rates in most of the jurisdictions in which the Group operates
are above 15 per cent and the transitional safe harbour relief is expected to
apply. On this basis the Group does not expect a material exposure to Pillar
Two income taxes in any jurisdictions.
Uncertain tax positions
During the period an uncertain tax position has been identified in certain UK
subsidiaries relating to the timing of the taxation of fair value movements
and realised gains and losses on hedges entered into in order to manage
commodity price risk. On the strength of independent advice, management
considers that there is no expectation of a net additional outflow of
funds. As such no additional liability has been recognised in the
consolidated financial statements as at 31 December 2023. However, a
contingent liability exists as the UK Tax Authorities could take an
alternative view on whether the fair value movements on the hedged instruments
are disregarded for tax purposes. While not considered a likely outcome, if
the UK Tax Authorities were to disagree and successfully challenge the
position, a possible liability currently estimated not to exceed $120 million
could arise because of the differences in tax rates across the periods in
question.
8. Earnings per share (EPS)
Basic EPS is calculated by dividing the profit after tax attributable to
ordinary shareholders of the Group by the weighted average number of ordinary
shares in issue during the year.
Diluted EPS is calculated by dividing the profit after tax attributable to
ordinary shareholders by the weighted average number of ordinary share in
issue during the year plus the weighted average number of ordinary shares that
would be issued on conversion of all the dilutive potential ordinary shares
into ordinary shares.
The following table reflects the income and share data used in the basic and
diluted EPS calculations:
2023 2022
Earnings for the year ($ millions)
Earnings for the purpose of basic earnings per share 32 8
Effect of dilutive potential ordinary shares - -
Earnings for the purpose of diluted earnings per share 32 8
Number of shares (millions)
Weighted average number of ordinary shares for the purposes of basic earnings 804 900
per share(1)
Dilutive potential ordinary shares(2) 2 12
Weighted average number of ordinary shares for the purposes of diluted 806 912
earnings per share
Earnings per share ($ cents)
Basic 4 1
Diluted 4 1
(1) During the current period 76.8 million ordinary shares were repurchased
and cancelled as part of the share buyback programme.
(2) Excludes certain share options outstanding at 31 December 2023 as their
option price was greater than market price.
9. Other intangible assets
Note Oil and gas Non-oil and gas assets(1) Carbon allowances(3) Total
$ million
assets $ million $ million
$ million
Cost
At 1 January 2022 813 119 - 932
Additions during the year 111 31 - 142
Transfers to property, plant and equipment 10 (29) - - (29)
Reduction in decommissioning asset 13 (12) - - (12)
Exploration written-off(2) (64) - - (64)
Currency translation adjustment (2) (13) - (15)
At 31 December 2022 817 137 - 954
Additions during the year 210 20 - 230
Transfers from property, plant and equipment 10 - 7 - 7
Reclassification from trade and other receivables - - 86 86
Increase in decommissioning asset 13 4 - - 4
Exploration written-off(2) (57) - - (57)
Currency translation adjustment 42 8 - 50
At 31 December 2023 1,016 172 86 1,274
Amortisation
At 1 January 2022 - 60 - 60
Charge for the year - 21 - 21
Currency translation adjustment - (7) - (7)
At 31 December 2022 - 74 - 74
Charge for the year - 23 - 23
Currency translation adjustment - 5 - 5
At 31 December 2023 - 102 - 102
Net book value
At 31 December 2022 817 63 - 880
At 31 December 2023 1,016 70 86 1,172
(1) Non-oil and gas assets relate primarily to Group IT software.
(2) The exploration write-off of $57 million (2022: $64 million) includes $13
million related to the Ix-1EXP well in Mexico, $15 million related to the JDE
well in Norway and also includes costs associated with licence relinquishments
and uncommercial well evaluations and $4 million related to an increase in
decommissioning provisions in the North Sea (note 13) (2022: $6 million
credit).
(3) On 31 December 2023, the Group reclassified purchases of UK ETS carbon
allowances of $61 million and Voluntary Emissions Reductions (VER) credits of
$25 million from trade and other receivables to intangible assets, $43 million
of which are expected to be released to the income statement in the next 12
months.
10. Property, plant and equipment
Note Oil and gas Fixtures and fittings & office equipment Total
$ million
assets $ million
$ million
Cost
At 1 January 2022 12,022 30 12,052
Additions(1) 532 11 543
Transfers from intangible assets 9 29 - 29
Decrease in decommissioning asset(2) 13 (778) - (778)
Currency translation adjustment (369) (3) (372)
At 31 December 2022 11,436 38 11,474
Additions(1) 482 9 491
Transfers to intangible assets 9 - (7) (7)
Reclassification of asset held for sale 12 (198) - (198)
Decrease in decommissioning asset(2) 13 (22) - (22)
Currency translation adjustment 159 2 161
At 31 December 2023 11,857 42 11,899
Accumulated depreciation
At 1 January 2022 4,785 21 4,806
Charge for the year 1,319 5 1,324
Net impairment reversal (170) - (170)
Currency translation adjustment (174) (2) (176)
At 31 December 2022 5,760 24 5,784
Charge for the year 1,192 3 1,195
Impairment charge 214 - 214
Reclassification of asset held for sale 12 (103) - (103)
Currency translation adjustment 91 1 92
At 31 December 2023 7,154 28 7,182
Net book value
At 31 December 2022 5,676 14 5,690
At 31 December 2023 4,703 14 4,717
(1) Included within property, plant and equipment additions of $491 million
(2022: $543 million) are associated cash flows of $496 million (2022: $477
million) and non-cash flow movements of $5 million (2022: ($66 million)),
represented by a $30 million decrease in capital accruals (2022: $43 million
increase), $18 million of capitalised lease depreciation (2022: $22 million)
and $7 million of capitalised interest (2022: $1 million).
(2) A decrease in the decommissioning assets of $22 million (2022: $778
million) was made during the year as a result of both new obligations and an
update to the decommissioning estimates (note 13).
During the year, the Group recognised a pre-tax impairment charge of $214
million (post-tax $109 million) (2022: net impairment credit of $170 million;
post-tax $50 million). This comprised a pre-tax impairment charge representing
a write-down of property, plant and equipment assets of $108 million (2022:
$163 million), across two CGUs in the UK of $70 million. Of these CGUs, one
was driven primarily by a significant reduction in the gas price forward
curve, and the other by a revised decommissioning cost profile. In addition
there was a Vietnam fair value impairment on the held for sale asset of $38
million plus a pre-tax impairment charge of $106 million (2022: $82 million
credit) in respect of revisions to decommissioning estimates on mainly
non-producing assets with no remaining net book value (see note 13).
In 2022, a net pre-tax impairment credit of $170 million was recognised as a
result of impairments reversals on North Sea assets of $251 million driven by
a higher forward curve and long term price assumption for gas, and a pre-tax
impairment credit of $82 million in respect of revisions to decommissioning
estimates on the Group's non-producing assets with no remaining net book
value. This was partially offset by an impairment to property, plant and
equipment of $163 million from a single CGU in the UK North Sea, driven
primarily by the contracted price realised for crude sales being negatively
impacted by the pricing differential between Urals and Brent crude and a
revised operating cost profile for the field.
Key assumptions used in calculations
Assumptions used in impairment measurement include estimates of commercial
reserves and production volumes, future oil and gas prices, discount rates and
the level and timing of expenditures, all of which are inherently uncertain.
Commodity and carbon prices - The Group uses the fair value less cost of
disposal method (FVLCD) to calculate the recoverable amount of the
cash-generating units (CGU) consistent with a level 3 fair value measurement
(see note 15). In determining the recoverable value, appropriate
discounted-cash-flow valuation models were used, incorporating market-based
assumptions. Management's commodity price curve assumptions are benchmarked
against a range of external forward price curves on a regular basis.
Individual field price differentials are then applied. The first three years
reflect the market forward price curves transitioning to a long-term price
from 2027, thereafter inflated at 2.5 per cent per annum. The long-term
commodity prices used were $70 per barrel for crude and 90p per therm for gas.
Production volumes and oil and gas reserves - Production volumes are based on
life of field production profiles for each asset within the CGU. Proven and
probable reserves are estimates of the amount of oil and gas that can be
economically extracted from the Group's oil and gas assets. The Group
estimates its reserves using standard recognised evaluation techniques,
assessed at least annually by management. Proven and probable reserves are
determined using estimates of oil and gas in place, recovery factors and
future commodity prices.
Costs - Operating expenditure, capital investment and decommissioning costs
are derived from the Group's business plan. The discount rate reflects
management's estimate of the Group's country-based weighted average cost of
capital (WACC). Foreign exchange rates are based on management's long-term
rate assumptions, with reference to a range of underlying economic indicators.
Sensitivity to changes in assumptions used in calculations
Reductions or increases in the long-term oil and gas prices of 10 per cent are
considered to be reasonably possible changes for the purpose of sensitivity
analysis. As shown in note 2 of the financial statements the decreases to the
long-term oil and gas prices from 1 January 2027 specified above would result
in a further pre-tax impairment of $86 million (post-tax $40 million) and $21
million (post-tax $6 million), respectively.
Considering the discount rates, the Group believes a one per cent increase in
the post-tax discount rate is considered to be a reasonable possibility for
the purpose of sensitivity analysis. A one per cent increase in the post-tax
discount rate would lead to a further pre-tax impairment of $24 million
(post-tax $11 million), and a one per cent decrease in the post-tax discount
rate would have no impact on the post-tax impairment charge.
11. Leases
This note provides information for leases where the Group is a lessee.
Balance sheet
Right-of-use assets Land and buildings Drilling FPSO Offshore facilities Equipment Total
rigs
$ million
$ million
$ million $ million $ million
$ million
Cost
At 1 January 2022 100 153 509 - 18 780
Additions during the year(1) - - - 338 - 338
Cost revisions/remeasurements 3 33 53 (4) 4 89
Disposals (6) - - - - (6)
Currency translation adjustment (9) (17) - - (2) (28)
At 31 December 2022 88 169 562 334 20 1,173
Additions during the year(1) 25 - - - 1 26
Cost revisions/remeasurements 1 48 63 (6) 4 110
Reclassification as asset held for sale (5) - (71) - - (76)
Disposals (4) (19) - - - (23)
Currency translation adjustment 4 10 - - 1 15
At 31 December 2023 109 208 554 328 26 1,225
Accumulated depreciation
At 1 January 2022 22 98 102 - 7 229
Charge for the year 12 43 107 61 7 230
Disposals (6) - - - - (6)
Currency translation adjustment (2) (12) - - (1) (15)
At 31 December 2022 26 129 209 61 13 438
Charge for the year 9 42 94 89 5 239
Reclassification of asset held for sale (2) - (23) - - (25)
Disposals (4) (19) - - - (23)
Currency translation adjustment 1 7 - - 1 9
At 31 December 2023 30 159 280 150 19 638
Net book value
At 31 December 2022 62 40 353 273 7 735
At 31 December 2023 79 49 274 178 7 587
(1) Additions of $26 million mainly related to new land and buildings were
made to the right-of-use assets during the year (2022: total additions of $338
million related to the Tolmount offshore facilities).
Right-of-use liabilities Note 2023 2022
$ million $ million
At 1 January 825 654
Additions 28 338
Re-measurement 110 89
Finance costs charged to income statement 6 51 25
Finance costs charged to decommissioning provision 13 1 1
Reclassification of liabilities as held for sale 12 (95) -
Lease payments (262) (254)
Currency translation adjustment 15 (28)
At 31 December 673 825
Classified as:
Current 199 221
Non-current 474 604
Total lease liabilities 673 825
The significant portion of the Group's lease liabilities represent lease
arrangements for an FPSO vessel on the Catcher asset, and offshore facilities
on the Tolmount asset.
The lease liabilities and associated right-of-use-assets have been calculated
by reference to in-substance fixed lease payments in the underlying agreements
incurred throughout the non-cancellable period of the lease along with periods
covered by options to extend the lease where the Group is reasonably certain
that such options will be exercised. When assessing whether extension options
were likely to be exercised, assumptions are consistent with those applied
when testing for impairment.
Income statement
Depreciation charge of right-of-use assets Note 2023 2022
$ million $ million
Land and buildings - non-oil and gas assets 8 11
Land and buildings - oil and gas assets 1 1
Drilling rigs 42 43
FPSO 94 107
Offshore facilities 89 61
Equipment - non oil and gas assets 1 -
Equipment - oil and gas assets 4 7
239 230
Capitalisation of IFRS 16 lease depreciation(1)
Drilling rigs (25) (26)
Equipment (2) (4)
Total depreciation charge included within the consolidated income statement 212 200
Lease interest 6 51 25
(1) Of the $27 million (2022: $30 million) capitalised IFRS 16 lease
depreciation, $18 million (2022: $22 million) has been capitalised within
property, plant and equipment and $9 million (2022: $8 million) within
provisions (note 13).
The total cash outflow for leases in 2023 was $259 million (2022: $254
million).
12. Assets held for sale
In August 2023, Harbour announced that it had entered into a Sale and Purchase
Agreement to sell its business in Vietnam, which holds its 53.125 per cent
interest in Chim Sao and Dua producing fields to Big Energy Joint Stock
Company for a consideration of $84 million. The transaction, which is subject
to government approvals, has an effective date of 1 January 2023. The assets
and liabilities of Vietnam have been classified as assets held for sale in the
balance sheet as at 31 December 2023 as completion is expected to be achieved
within 12 months from entering into the SPA.
The Group's Vietnam operations are included in the International segment
however are not considered a major geographical area or line of business and
therefore the disposal has not been classified as discontinued operations.
The major classes of assets and liabilities of the Group as held for sale as
at 31 December 2023, are as follows:
Note 2023
$ million
Assets
Property, plant and equipment 95
Right of use assets 11 51
Other receivables and working capital 188
Assets held for sale 334
Liabilities
Provisions 13 87
Lease creditor 11 95
Trade and other payables 29
Deferred tax 7 31
Liabilities directly associated with assets held for sale 242
Net assets directly associated with disposal group 92
Impairment loss recorded 38
Immediately before the classification of the disposal group as assets held for
sale, the recoverable amount was estimated for the disposal group and no
impairment loss was identified. The assets in the disposal group are held at
the lower of their carrying amount and fair value less costs to sell. As at 31
December 2023, an impairment of $38 million was recognised as the fair value
less cost to sell, being the expected consideration adjusted for items agreed
under the SPA, was below the carrying amount of the disposal group. Following
the impairment charge the net assets directly associated with the disposal
group held on the consolidated balance sheet was $92 million.
13. Provisions
Decommissioning Other Total
$ million
provision provisions
$ million $ million
At 1 January 2022 5,354 27 5,381
Additions 24 - 24
Changes in estimates - decrease to oil and gas tangible decommissioning assets (720) - (720)
Changes in estimates - decrease to oil and gas intangible decommissioning (6) - (6)
assets
Changes in estimates on oil and gas tangible assets - credit to income (82) - (82)
statement
Changes in estimates on oil and gas intangible assets - credit to income (6) - (6)
statement
Changes in estimates - credit to income statement - (1) (1)
Amounts used (223) (2) (225)
Disposal (9) - (9)
Interest on decommissioning lease (1) - (1)
DD&A on decommissioning right-of-use leased asset (8) - (8)
Unwinding of discount 65 - 65
Currency translation adjustment (247) - (247)
At 31 December 2022 4,141 24 4,165
Additions 40 - 40
Changes in estimates - decrease to oil and gas tangible decommissioning assets (203) - (203)
Changes in estimates on oil and gas tangible assets - debit to income 141 - 141
statement
Changes in estimates on oil and gas intangible assets - debit to income 4 - 4
statement
Changes in estimates - debit to income statement - 3 3
Amounts used (248) - (248)
Reclassification of liabilities directly associated with assets held for sale (87) - (87)
Interest on decommissioning lease (1) - (1)
DD&A on decommissioning right-of-use leased asset (9) - (9)
Unwinding of discount 156 - 156
Currency translation adjustment 87 - 87
At 31 December 2023 4,021 27 4,048
Non-current liabilities Current Total
$ million liabilities $ million
$ million
Classified within
At 31 December 2022 3,934 231 4,165
At 31 December 2023 3,818 230 4,048
Decommissioning provision
The Group provides for the estimated future decommissioning costs on its oil
and gas assets at the balance sheet date. The payment dates of expected
decommissioning costs are uncertain and are based on economic assumptions of
the fields concerned. The Group currently expects to incur decommissioning
costs within the next 40 years, the majority of which are anticipated to be
incurred between the next 10 to 20 years. These estimated future
decommissioning costs are inflated at the Group's long term view of inflation
of 2.5 per cent per annum (2022: 2.5 per cent per annum) and discounted at a
risk-free rate of between 4.3 per cent and 5.2 per cent (2022: 3.5 per cent
and 3.7 per cent) reflecting a 6-month (2022: 6-month) rolling average of
market rates over the varying lives of the assets to calculate the present
value of the decommissioning liabilities. The unwinding of the discount is
presented within finance costs.
These provisions have been created based on internal and third-party
estimates. Assumptions based on the current economic environment have been
made, which management believe are a reasonable basis upon which to estimate
the future liability. These estimates are reviewed regularly to consider any
material changes to the assumptions. However, actual decommissioning costs
will ultimately depend upon market prices for the necessary decommissioning
work required, which will reflect market conditions at the relevant time. In
addition, the timing of decommissioning liabilities will depend upon the dates
when the fields become economically unviable, which in itself will depend on
future commodity prices and climate change, which are inherently uncertain.
Other provisions
Other provisions relate to termination benefit provision in Indonesia of $27
million (2022: $24 million), where the Group operates a service, severance and
compensation pay scheme under a collective labour agreement with the local
workforce.
14. Borrowings and facilities
The Group's borrowings are carried at amortised cost:
2023 2022
$ million $ million
Reserves-based lending (RBL) facility(1) - 702
Bond 493 491
Exploration finance facility - 11
Other loans 16 34
Total borrowings 509 1,238
Classified within:
Non-current liabilities 493 1,216
Current liabilities 16 22
Total borrowings 509 1,238
(1 ) The reserves-based lending (RBL) facility was fully repaid in the year,
leaving $61 million of unamortised fees and related costs to be amortised over
the remaining term of the facility which have been reclassified within current
and non-current assets as appropriate
The RBL facility was amended and extended in November 2023, and the key terms
of the amended RBL facility are:
§ Term matures 31 December 2029.
§ Facility size of $2.75 billion, with a $1.75 billion letter of credit
sub-limit.
§ Debt availability at $1.346 billion effective 24 November 2023.
§ Debt availability to be redetermined on an annual basis.
§ Interest at compounded SOFR plus a margin of 3.2 per cent, rising to a
margin of 3.4 per cent from November 2025 and 3.6 per cent from November 2027.
§ A margin adjustment linked to carbon-emission reductions.
§ Straight line amortisation of LC sub-limit from January 2027 to 6 months
before maturity. No material cash collateralisation required until 2028.
§ Liquidity and leverage covenant tests.
§ A syndication group of 15 banks.
Certain fees are also payable, including fees on available commitments at 40
per cent of the applicable margin and commission on letters of credit issued
at 50 per cent of the applicable margin.
In October 2021, the Group issued a $500 million bond under Rule 144A and with
a tenor of five years to maturity. The coupon was set at 5.50 per cent and
interest is payable semi-annually.
At the balance sheet date, the outstanding RBL balance excluding incremental
arrangement fees and related costs was $nil million (2022: $775 million). As
at 31 December 2023, $1,340 million remained available for drawdown under the
RBL facility (2022: $1,972 million).
The Group has facilities to issue up to $1,750 million of letters of credit,
of which $1,186 million was in issue as at 31 December (2022: $966 million),
mainly in respect of future abandonment liabilities.
A further $34 million of arrangement fees and related costs were capitalised
during the year following amendments to the RBL facility which became
effective from November 2023.
During the year $48 million (2022: $55 million) of arrangement fees and
related costs have been amortised and are included within financing costs.
At 31 December 2023, $68 million of arrangement fees and related costs remain
capitalised (2022: $82 million), of which $21 million is due to be amortised
within the next 12 months (2022: $20 million). $61 million of these
arrangement fees relate to the RBL facility, $19 million of which have been
reclassified within current assets, and $42 million, which are due to be
amortised beyond the next 12 months, have been reclassified to non-current
assets.
Bond interest of $6 million (2022: $6 million comprising both bond and RBL
interest) had accrued by the balance sheet date and has been classified within
accruals.
Since 2019, the Group has been operating within an exploration finance
facility (EFF), of NOK 1 billion, in relation to part-financing the
exploration activities of Harbour Energy Norge AS. This facility was repaid in
full in February 2023.
Other loans represent a commercial financing arrangement with Baker Hughes
(formerly BHGE), that covered a three-year work programme for drilling,
completion and subsea tie-in of development wells on Harbour's operated
assets. The loan will be repaid based on production performance, subject to a
cap
The table below details the change in the carrying amount of the Group's
borrowings arising from financing cash flows.
Total
$ million
Total borrowings as at 1 January 2022 2,886
Repayment of RBL (1,663)
Repayment of financing arrangement (15)
Repayment of EFF loan (38)
Proceeds from EFF loan 11
Currency translation adjustment on EFF loan (7)
Financing arrangement interest payable 9
Amortisation of arrangement fees and related costs 55
Total borrowings as at 31 December 2022 1,238
Proceeds from drawdown of borrowing facilities 660
Repayment of RBL (1,435)
Repayment of financing arrangement (21)
Repayment of EFF loan (11)
Arrangement fees and related costs on RBL capitalised (34)
Financing arrangement interest payable 3
Amortisation of arrangement fees and related costs 48
Reclassification of RBL arrangement fees and related costs to current and 61
non-current assets
Total borrowings as at 31 December 2023 509
15. Other financial assets and liabilities
The Group held the following financial instruments at fair value at 31
December 2023. The fair values of all derivative financial instruments are
based on estimates from observable inputs and are all level 2 in the IFRS 13
hierarchy, except for the royalty valuation, which includes estimates based on
unobservable inputs and are level 3 in the IFRS 13 hierarchy.
31 December 2023 31 December 2022
$ million $ million
Current Assets Liabilities Assets Liabilities
Measured at fair value through the income statement
Foreign exchange derivatives 6 - 6 -
Interest rate derivatives - - 24 -
Fair value of embedded derivative within a gas contract
10 - - (57)
16 - 30 (57)
Measured at fair value through other comprehensive income
Commodity derivatives 154 (197) 51 (2,114)
Total current 170 (197) 81 (2,171)
Non-current
Measured at fair value through the income statement
Interest rate derivatives - - 18 -
18 -
Measured at fair value through other comprehensive income
Commodity derivatives 112 (87) 85 (1,279)
Total non-current 112 (87) 103 (1,279)
Total current and non-current 282 (284) 184 (3,450)
15.1 Fair value measurements
All financial instruments that are initially recognised and subsequently
remeasured at fair value have been classified in accordance with the hierarchy
described in IFRS 13 Fair Value Measurement. The hierarchy groups fair-value
measurements into the following levels, based on the degree to which the fair
value is observable.
§ Level 1: fair value measurements are derived from unadjusted quoted prices
for identical assets or liabilities.
§ Level 2: fair value measurements include inputs, other than quoted prices
included within level 1, which are observable directly or indirectly.
§ Level 3: fair value measurements are derived from valuation techniques that
include significant inputs not based on observable data.
Financial Assets Financial Liabilities
Level 2 Level 3 Level 2 Level 3
$ million
$ million $ million $ million
At 31 December 2023
Fair value of embedded derivative within gas contract
10 - - -
Commodity derivatives 266 - (284) -
Foreign exchange derivatives 6 - - -
Total fair value 282 - (284) -
Financial Assets Financial Liabilities
At 31 December 2022 Level 2 Level 3 Level 2 Level 3
$ million
$ million $ million $ million
Fair value of embedded derivative within gas contract - -
(57) -
Commodity derivatives 136 - (3,393) -
Foreign exchange derivatives 6 - - -
Interest rate derivatives 42 - - -
Total fair value 184 - (3,450) -
There were no transfers between fair value levels in 2022 or 2023.
Fair value movements recognised in the income statement on financial
instruments are shown below:
2023 2022
$ million $ million
Finance income
Change in fair value of embedded derivative within gas contract 68 -
Foreign exchange derivatives - 7
Interest rate derivatives (43) 31
25 38
2023 2022
$ million $ million
Finance expense
Change in fair value of embedded derivative within gas contract - 48
- 48
15.2 Fair values of other financial instruments
The following financial instruments are measured at amortised cost and are
considered to have fair values different to their book values.
2023 2022
$ million $ million
Book value Fair value Book value Fair value
Bond (493) (487) (491) (446)
The fair value of the bond is within level 2 of the fair value hierarchy and
has been estimated by discounting future cash flows by the relevant market
yield curve at the balance sheet date. The fair values of other financial
instruments not measured at fair value including cash and short-term deposits,
trade receivables, trade payables and floating rate borrowings equate
approximately to their carrying amounts.
15.3 Cash flow hedge accounting
The Group uses a combination of fixed price physical sales contracts and
cash-settled fixed price commodity swaps and options to manage the price risk
associated with its underlying oil and gas revenues. As at 31 December 2023,
all of the Group's cash-settled fixed price commodity swap derivatives have
been designated as cash flow hedges of highly probable forecast sales of oil
and gas.
The following table indicates the volumes, average hedged price and timings
associated with the Group's financial commodity derivatives. Volumes hedged
through fixed price contracts with customers for physical delivery are
excluded.
Position as at 31 December 2023 2024 2025 2026
Oil
Volume hedged (thousand bbls) 7,320 4,380 -
Weighted average hedged price ($/bbl) 84.37 77.35 -
UK natural gas
Volume hedged (million therms) 759 428 90
Weighted average hedged price (p/therm) 67.19 89.68 99.28
As at 31 December 2023, the fair value of net financial commodity derivatives
designated as cash flow hedges, all executed under ISDA agreements with no
margining requirements, was a net payable of $66 million (2022: $3,516
million) and net unrealised pre-tax losses of $16 million (2022: $3,185
million) were deferred in other comprehensive income in respect of the
effective portion of the hedge relationships.
Amounts deferred in other comprehensive income will be released to the income
statement as the underlying hedged transactions occur. As at 31 December 2023,
net deferred pre-tax losses of $51 million (2022: $2,368 million) are expected
to be released to the income statement within one year.
15.4 Interest Rate Benchmark Reform (IBOR)
During the year, the Group transitioned to alternative benchmark rates to
cater for the discontinuation of IBOR rates. Our bond is at a fixed interest
rate of 5.5 per cent whilst the RBL (undrawn at 31 December 2023) transitioned
from US LIBOR to SOFR (Secured Overnight Financing Rate).
16. Notes to the statement of cash flows
Net cash flows from operating activities consist of:
2023 2022
$ million $ million
Profit before taxation 597 2,462
Adjustments to reconcile profit before tax to net cash flows:
Finance cost, excluding foreign exchange 363 358
Finance income, excluding foreign exchange (104) (77)
Depreciation, depletion and amortisation 1,430 1,546
Fair value movement in carbon swaps - 2
Net impairment of property, plant and equipment 214 (170)
Impairment of goodwill 25 -
Share based payments 20 17
Decommissioning expenditure (268) (217)
Exploration costs written-off 57 64
Onerous contract payments - (2)
Gain on disposal - (12)
Movement in realised cash-flow hedges not yet settled (207) (104)
Unrealised foreign exchange loss/(gain) 49 (238)
Working capital adjustments:
(Increase)/decrease in inventories (52) 65
Decrease/(increase) in trade and other receivables 519 (75)
(Decrease)/increase in trade and other payables (61) 63
Net tax (438) (552)
payments
Net cash inflow from operating activities 2,144 3,130
Reconciliation of net cash flow to movement in net borrowings
2023 2022
$ million $ million
Proceeds from drawdown of borrowing facilities (660) -
Proceeds from EFF loan - (11)
Repayment of RBL facility 1,435 1,663
Repayment of EFF loan 11 38
Repayment of financing arrangement 21 15
Financing arrangement interest payable (3) (9)
Arrangement fees and related costs capitalised 34 -
Amortisation of arrangement fees and related costs capitalised (48) (55)
Currency translation adjustment on EFF loan - 7
Movement in total borrowings 790 1,648
Movement in cash and cash equivalents (220) (199)
Decrease in net borrowings in the year 570 1,449
Opening net borrowings (738) (2,187)
Closing net borrowings (168) (738)
Analysis of net borrowings
2023 2022
$ million $ million
Cash and cash equivalents 280 500
RBL facility - (702)
Bond (493) (491)
EFF loan - (11)
Net debt (213) (704)
Financing arrangement (16) (34)
Closing net borrowings (229) (738)
Non-current assets 42 -
Current assets 19 -
Closing net borrowings after total unamortised fees(1) (168) (738)
(1) $61 million of fees associated with the RBL are recognised in debtors.
The carrying values on the balance sheet are stated net of the unamortised
portion of issue costs and bank fees of $68 million of which $61 million
relates to the RBL and is recognised in assets and $7 million is netted
against the bond (2022: $82 million of which $73 million related to the RBL
and $9 million related to the bond both of which were netted off against the
borrowings).
17. Related Parties
Transactions between the company and its subsidiaries, which are related
parties, have been eliminated on consolidation and are not disclosed in this
note.
Harbour Energy's Viking CCS entered into an arrangement with West Burton
Energy, the independent power generation company based in Nottinghamshire,
which is a subsidiary of EIG, Harbour's largest shareholder. The intention is
to capture, transport and permanently store CO2 emissions from the West Burton
B power station. Harbour Energy and West Burton Energy have begun the
necessary engineering design to connect West Burton B to the high-capacity
Viking CCS storage sites located beneath the Southern North Sea.
There have not been any financial transactions with West Burton Energy in
2023.
Compensation of key management personnel of the Group
Remuneration of key management personnel, including Directors of the Group, is
shown below.
2023 2022
$ million $ million
Salaries and short-term employee benefits 13 15
Payments made in lieu of pension contributions 1 1
Total 14 16
18. Distributions made and proposed
A final dividend of 12 cents per ordinary share in relation to the year ended
31 December 2022 was paid on 24 May 2023 pursuant to shareholder approval
received on 10 May 2023.
Pursuant to shareholder approval received on 10 May 2023, an interim dividend
of 12 cents per ordinary share in relation to the half year ended 30 June 2023
was paid on 18 October 2023.
2023 2022
$ million $ million
Cash dividends on ordinary shares declared and paid:
Final dividend for 2022: 12 cents per share (2021: 11 cents per share) 99 98
Interim dividend for 2023: 12 cents per share (2022: 11 cents per share) 91 93
Total 190 191
Proposed dividends on ordinary shares:
Final dividend for 2023: 13 cents per share (2022: 12 cents per share) 100 100
Proposed dividends on ordinary shares are subject to approval at the annual
general meeting and are not recognised as a liability as at 31 December.
19. Post balance sheet events
On 5 March 2024 Harbour signed a new $3.0 billion fully unsecured revolving
credit facility (RCF) and $1.5 billion bridge facility which will be available
at completion to fund the acquisition of the Wintershall Dea asset portfolio.
The RCF has a $.1.75 billion letter of credit sub-limit, a five-year term from
signing and will replace the existing RBL facility.
On 6 March 2024, the UK government announced that Energy Profit Levy (EPL)
would be extended for a further 12 months to 31 March 2029 from the former end
date of 31 March 2028. Harbour is currently assessing the potential impact of
this announcement.
Glossary
2C Best estimate of contingent resources
2P Proven and probable reserves
AGM Annual general meeting
APS Announced Pledges Scenario
bbl Barrel
boe Barrel of oil equivalent
CCS Carbon capture and storage
CGU Cash generating unit
DD&A Depreciation, depletion and amortisation
DRIP Dividend re-investment plan
EBITDAX Earnings before interest, tax, depreciation, amortisation and exploration
EFF Exploration financing facility
EPL Energy Profits Levy (UK)
EPS Earnings per share
ESOP Employee stock ownership plan
ETS Emission trading system
FEED Front End Engineering & Design
FPSO Floating production storage offtake vessel
FVLCD Fair value less cost of disposal
GAAP Generally accepted accounting principles
GHG Greenhouse gas emissions
IAS International Accounting Standards
IASB International Accounting Standards Board
IBOR Inter-bank Offered Rates
ISDA International Swaps and Derivatives Association
IFRSs International Financial Reporting Standards
kboepd Thousand of barrels of oil equivalent per day
LC Letter of credit
LIBOR London Inter-bank Offered Rates
mbtu Million British thermal unit
mmbbl Million barrels of oil
mmboe Million barrels of oil equivalent
mscf Thousand standard cubic feet
NBP Natural gas prices
NOK Norwegian krone
OECD Organisation for Economic Co-operation and Development
PP&E Property, plant and equipment
PSC Production sharing contract
RBL Reserves-based lending
RCF Revolving credit facility
SOFR Secured Overnight Financing Rate
SPA Sales and purchase agreement
STEPS IEA Stated Policies
Therm Unit of UK natural gas
VER Voluntary emissions reductions
WACC Weighted average cost of capital
Non-IFRS measures
Harbour uses certain measures of performance that are not specifically defined
under IFRS or other generally accepted accounting principles (GAAP). These
non-IFRS measures, which are presented within the financial review, are
defined below:
§ Capital investment: Depicts how much the Group has spent on purchasing
fixed assets in order to further its business goals and objectives. It is a
useful indicator of the Group's organic expenditure on oil and gas assets, and
exploration and appraisal assets, incurred during a period.
§ DD&A per barrel: Depreciation and amortisation of oil and gas
properties for the period divided by working interest production. This is a
useful indicator of ongoing rates of depreciation and amortisation of the
Group's producing assets.
§ EBITDAX: Earnings before interest, tax, depreciation and amortisation,
impairments, remeasurements, onerous contracts and exploration expenditure.
This is a useful indicator of underlying business performance.
§ Free cash flow: Operating cash flow less cash flow from investing
activities less interest and lease payments and is before shareholder
distributions.
§ Leverage ratio: Net debt divided by the last 12 months EBITDAX.
§ Liquidity: The sum of cash and cash equivalents on the balance sheet and
the undrawn amounts available to the Group on our principal facilities. This
is a key measure of the Group's financial flexibility and ability to fund
day-to-day operations.
§ Net debt: Total reserves-based lending facility and bond (net of the
carrying value of unamortised fees) less cash and cash equivalents recognised
on the consolidated balance sheet. This is an indicator of the Group's
indebtedness and contribution to capital structure.
§ Operating cost per barrel: Direct operating costs (excluding
over/underlift) for the period, including tariff expense, insurance costs and
mark to market movements on emissions hedges, less tariff income, divided by
working interest production. This is a useful indicator of ongoing operating
costs from the Group's producing assets.
§ Shareholder returns paid: Dividends plus share buybacks completed in the
period are included in this metric which shows the overall value returned to
stakeholders in the period.
§ Total capital expenditure: Capital investment 'additions' per notes 9 and
10 plus decommissioning expenditure 'amounts used' per note 13.
Group reserves and resources
Oil and gas 2P reserves and 2C resources(1)
UK International(2) Total
Oil, NGLs Gas Total Oil, NGLs Gas Total Oil, NGLs Gas Total
mmbbls bcf mmboe mmbbls bcf mmboe mmbbls bcf mmboe
2P reserves (working interest)
1 January 2023 213 936 390 9 57 20 221 993 410
Revisions and additions(3) 1 87 17 - 11 2 2 98 19
Production (31) (173) (64) (1) (14) (4) (33) (186) (68)
31 December 2023 183 851 343 7 54 18 190 905 361
2P reserves (entitlement)(4)
31 December 2023 183 851 343 6 43 14 189 893 357
2C resources (working interest)
1 January 2023 142 361 204 137 657 250 279 1,019 455
Revisions, additions, relinquishments(5) 3 (27) (2) 25 238 66 28 210 64
31 December 2023 145 334 202 162 895 316 307 1,229 519
( )
(1) Volumes reflect internal estimates. ERCE as a competent independent person
has audited the Group's 2P net entitlement and working interest reserves as at
31 December 2023 and ERCE considers these to be fair and reasonable as per the
SPE Standards Pertaining to the Estimating and Auditing of Oil and Gas
Reserves Information. ERCE has also audited c. 80 per cent of the Group's 2C
contingent resources as at 31 December 2023 and is of the opinion that
Harbour's estimates are fair and reasonable. Further, ERCE believes that if
its audit had included all of Harbour's 2C resources then it would have been
able to express the same opinion. Conversion of gas volumes from bcf to boe is
determined using an energy conversion of 5.8 mmbtu per boe. Fuel gas is not
included in these estimates.
(2) International consists of Indonesia, Vietnam and Mexico.
(3) UK 2P reserves additions includes over 20 mmboe of additions across
Harbour's UK operated J-Area, AELE and GBA hubs, following the approval of
several new wells
(4) Harbour's net entitlement 2P reserves are lower than its working interest
2P reserves for its international assets, reflecting the terms of the
Production Sharing Contracts (PSC).
(5) Increase in 2C resource largely reflects the addition of the Layaran gas
discovery in Indonesia and the Kan oil discovery in Mexico.
The Group provides for amortisation of costs relating to evaluated properties
based on direct interests on an entitlement basis, which incorporates the
terms of the PSCs in Indonesia and Vietnam. On an entitlement basis, reserves
were 357 mmboe as at 31 December 2023.
Because of rounding, some totals may not agree exactly with the sum of their
component parts.
CO(2) Storage capacity
2C resources (working interest)(1) UK
(million tonnes)
1 January 2023 300
Additions and disposals(2) (78)
31 December 2023 222
( )
(1) Reflects Harbour's internal estimates which have been externally audited
by ERCE, a competent independent person. ERCE considers Harbour's internal
estimates to be fair and reasonable.
(2) Reflects the addition of storage resource associated with Harbour's 30 per
cent working interest in the Acorn project offset by the impact of bp joining
the Viking project with a 40 per cent interest during 2023. Excludes any
potential storage capacity associated with the two Viking licences which were
awarded during 2023 and are in the process of being appraised and volumes
associated with several further development options available to Acorn.
1 (#_ftnref1) See Glossary for the definition of non-IFRS measures used in
this section.
2 (#_ftnref2) Total spend on share buybacks includes transaction fees and
foreign exchange differences applied to the sterling denominated shares
repurchased.
3 (#_ftnref3) 2024 and 2025 outlook excludes any effects from the
Acquisition
4 (#_ftnref4) $200 million free cash flow forecast provided in January 2024
reflected $85/bbl and 100p/therm
5 (#_ftnref5) Hedge price for gas hedge collars reflects the forward curve
as at 6 March 2024
6 (#_ftnref6) Formal legal implementation of amendments to follow
7 (#_ftnref7) Based on 2023 production numbers.
8 (#_ftnref8) $200 million free cash flow sensitivity provided in January
2024 reflected $85/bbl and 100p/therm
9 (#_ftnref9) Difference to the final dividend value declared of $100
million is due to foreign exchange adjustments on sterling denominated shares
at the date of payment.
10 (#_ftnref10) Difference to the interim dividend declared of $100 million
is due to foreign exchange adjustments on sterling denominated shares and
reduced share count in issue between the record date and the announcement
driven by the repurchases of shares.
11 (#_ftnref11) Total spend on share buybacks includes transaction fees and
foreign exchange differences applied to the sterling denominated shares
repurchased.
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