TIDMHBR
RNS Number : 3713S
Harbour Energy PLC
09 March 2023
Harbour Energy plc
("Harbour" or the "Group" or the "Company")
Full Year Results
9 March 2023
Harbour Energy today announces its audited full year results for
the year ended 31 December 2022.
Linda Z Cook, Chief Executive Officer, commented:
"In our first full year as a publicly listed company, Harbour
delivered materially higher production which - together with
improved margins - enabled us to continue to deleverage and make
material shareholder distributions. We further developed our Net
Zero strategy, setting ourselves an interim target, and built
significant momentum in our flagship Viking CCS project. Most
importantly we achieved all of this while improving our safety
record.
However, the UK Energy Profits Levy, which applies irrespective
of actual or realised commodity prices, has disproportionately
impacted the UK-focused independent oil and gas companies that are
critical for domestic energy security. For Harbour, the UK's
largest oil and gas producer, it has all but wiped out our profit
for the year. This has driven us to reduce our UK investment and
staffing levels. Given the fiscal instability and outlook for
investment in the country, it has also reinforced our strategic
goal to grow and diversify internationally.
Thanks to our robust balance sheet, we enter 2023 well-placed to
deliver on our strategy of building a global diverse oil and gas
company. We will continue to return any excess capital to
shareholders while investing in our existing portfolio and
maintaining capacity for meaningful but disciplined M&A."
2022 Operational highlights
-- Production of 208 kboepd (2021: 175 kboepd), a 19 per cent
increase on 2021
-- Improved unit operating costs of $13.9/boe (2021:
$15.2/boe)
-- Total recordable injury rate reduced to 0.8 per million hours
worked (2021: 1.3)
-- Investment decisions taken on Talbot development and Leverett
appraisal in the UK
-- Material discovery at Timpan-1 (Indonesia), de-risking a
multi-TCF gas play
-- Zama (Mexico) development plan substantially agreed ahead of
submission to the regulator
-- 2P reserves and 2C resources of 865 mmboe (2021: 948 mmboe),
reflecting Indonesia exploration success offset by production and
UK licence relinquishments
-- Net Zero by 2035: Board-approved interim target to halve our
emissions by 2030
-- Viking CCS CO(2) storage resources of 300 mt independently
verified; customer base expanded
2022 Financial highlights
-- Realised, post hedging, oil and UK gas prices of $78/bbl and
86p/therm (2021: $59/bbl, 54p/therm)
-- Increased EBITDAX of $4.0 billion (2021: $2.4 billion) and
profit before tax of $2.5 billion (2021: $0.3 billion)
-- Profit after tax of $8 million (2021: $101 million) impacted
by a $1.5 billion one off non-cash deferred tax charge associated
with the EPL
-- Free cash flow of $2.1 billion (2021: $0.7 billion) after
total capital expenditure of $0.9 billion (2021: $0.9 billion) and
$551 million of tax payments (2021: $280 million)
-- Approved $600 million of shareholder distributions: $553
million made in 2022; $41 million in 2023
-- Net debt (excluding unamortised fees) and leverage reduced to
$0.8 billion (2021: $2.3 billion) and 0.2x (2021: 0.9x),
respectively
-- Proposed final dividend of $100 million (12 cents per share)
for 2022, in line with $200 million annual dividend policy; given
our buybacks, this represents dividend per share growth of nine per
cent
Outlook for 2023
-- Production guidance of 185-200 kboepd reiterated; production
to end February of 202 kboepd
-- Opex guidance unchanged at c.$16/boe
-- Total capex guidance reiterated at c.$1.1 billion, including
c.$0.2 billion decommissioning, split 85 per cent UK / 15 per cent
international
- UK capex targeting high return, near field and/or infrastructure-led opportunities
- International capex focused on growth opportunities with
potential for material reserves replacement, including Zama
(Mexico) and Andaman (Indonesia)
-- Review of UK organisation to align with lower activity levels
to complete in second half of 2023
-- Continued efforts to reduce emissions and progress UK CCS
projects to a final investment decision
-- At $85/bbl, 150 pence/therm, forecast 2023 free cash flow
(post-tax, pre-distributions) of c.$1.0 billion(1) with the
potential to be net debt free in 2024
-- New $200 million share buyback announced today which,
together with the $200 million annual dividend policy, brings total
announced shareholder returns to $1 billion since December 2021
Enquiries
Harbour Energy plc
Elizabeth Brooks, Head of Investor Relations
020 3833 2421
Brunswick
Patrick Handley, Will Medvei
020 7404 5959
(1) The $1 billion of free cash flow is after tax payments and
reflects that the majority of our 2023 EPL liability is expected to
be paid in 2024 due to one of the Harbour entities not currently
falling within the UK tax instalment payment regime.
Performance Review
Materially increased oil and gas production, supporting UK
domestic energy supply
Production increased to 208 kboepd in 2022 (2021: 175 kboepd),
towards the top end of our 195-210 kboepd original guidance and
split equally between liquids and gas (2021: 55 per cent liquids,
45 per cent gas).
The almost 20 per cent increase in production was driven by new
wells, primarily gas, coming online including at Tolmount, J-Area
and Everest in the UK and by the full-year contribution from the
Premier Oil assets. Our strong production performance was also
supported by consistent outperformance from our Greater Britannia
Area (GBA) satellite fields, Callanish and Brodgar. In addition, we
benefited from shorter maintenance shutdowns and improved
reliability.
Operating costs for the year were $1.1 billion, equating to
$13.9/boe on a unit of production basis (2021: $15.2/boe). This
improvement was driven by higher volumes and a weaker sterling to
US dollar exchange rate. Total capital expenditure in 2022 was $0.9
billion (2021: $0.9 billion). This was lower than the $1.3 billion
forecast at the outset of the year due to the decisions not to
proceed with several North Sea exploration and appraisal wells and
the dela yed arri val of drilling rigs at multiple locations. Our
operating and capital expenditure also reflected continued progress
on integration, including supply chain savings as we consolidated
key supplier contracts following recent acquisitions.
2023 production is forecast at 185-200 kboepd, with new wells
coming on-stream partially offsetting natural decline. Our
production mix is expected to remain stable at approximately 50 per
cent liquids, 50 per cent gas. The outlook for unit operating cost
for 2023 is c.$16/boe, higher than in 2022 because of lower
production and some inflationary pressures.
2023 total capital expenditure is estimated at $1.1 billion,
split 85 per cent UK, 15 per cent international. We reduced our
planned 2023 UK capital expenditure following the changes to the
Energy Profits Levy (EPL) announced in November, with certain
investment opportunities delayed or no longer being progressed. We
also rephased some of our decommissioning activities.
Safe and responsible operator
Harbour delivered an impr oved safety performance in 2022. With
nearly 12 million hours worked during the year, we recorded no
serious injuries or significant spills and materially reduced our
total recordable injury ra te per million hours to 0.8 (2021: 1.3).
However, we did experience an uptick in high potential incidents
through the first half of the year reminding us of the need to
remain vigilant as we strive to meet our 'zero incident'
ambition.
Harbour is committed to proactively addressing its environmental
impact and to achieving its 2035 net zero goal. In 2022, our
emissions intensity across our operated assets was broadly stable
at 21 kgCO(2) e/boe (2021: 21 kgCO(2) e/boe [1] ), despite a full
year's contribution from the more emissions-intensive Premier Oil
assets. The performance reflects improved efficiency and the
implementation of emissions-reduction projects within our operated
hubs. 2022 also saw us further develop our net zero strategy,
setting an interim target of 50 per cent reduction in our emissions
by 2030 versus a 2018 baseline and aligning our emissions
definitions and targets more closely with industry standards.
T argeted UK capital investment programme
Harbour's UK capital investment is focused on high return, lower
risk, near field and infrastructure-led opportunities which add
reserves, impr ove recovery and extend producing life, activities
all critical to the UK's energy security. During 2022, we completed
c.50 well intervention programmes and brought online 14 new wells.
In total, we developed over 35 mmboe of 2P reserves, volumes that
are now contributing to our production.
In April, we brought the Tolmount gas project on-stream which
reached gross plateau rates of 40 kboepd (Harbour 50 per cent
interest) in July, increasing the UK's domestic gas supply by
approximately five per cent at a critical time. The project reached
cash payback in September and has since come off plateau
production, earlier than originally anticipated. Post-period end we
completed the Tolmount East development well which is expected
online in 2024, while the near field Earn prospect is scheduled to
be tested in the second half of 2023.
At J-Area, the successful Jade South exploration well was
brought into production in January 2022 helping boost production
levels from the hub. Two J-Area infill wells were brought online
around the end of the year, one of which has performed below
expectations. Another near field exploration well, targeting the
Jocelyn South prospect, is planned for the second half of 2023. We
also completed a three well drilling programme at Catcher, two of
which were brought on-stream around the year-end. The third
encountered sub-commercial volumes and was not completed.
In our non-operated portfolio, Clair Ridge production continues
to be supported by an ongoing development programme w ith two
producer and wa ter injector wells completed during 2022. The
operator also plans to return to platform drilling at Clair Phase 1
during the first half of 2023. At Beryl, production was impacted by
underperformance of the Storr-2 well which came online during the
first quarter of 2022 and delays to the Buckland South West well
which is expected on-stream in the second quarter of 2023. Further
drilling is planned at Beryl during 2023, although less than
forecast at the outset of the year following the operator's
decision to terminate its drilling contract for the Ocean
Patriot.
2022 saw us approve the Talbot oil development comprising a
multi-well subsea tieback to our Judy platform. Development
drilling is expected to commence in the first half of 2023 with the
start of production scheduled for around the end of 2024. We also
appr oved the appraisal of the Leverett gas discovery, loca ted
close to the Greater Britannia Area, with the well scheduled to
spud in the second quarter of 2023.
We continue to invest in high return investment opportunities to
maximise value from our producing asset base. However, the changes
to the EPL announced in November have caused us to scale back our
UK investment levels in certain areas and to review our UK
organisation. The review, which is targeted for completion in the
second half of 2023, is expected to lead to a significant reduction
in our UK workforce.
Attractive international growth projects with potential for
material reserves replacement
Our aim is to gr ow and diversify internationally via
acquisitions. We seek to acquire cash generative producing assets
which are accretive to our reserve life, margins and GHG intensity
thereby improving our credit rating and ability to support
shareholder returns over the longer term. While market conditions
were challenging for acquisitions during 2022, there are signs of a
more active M&A market in 2023.
In addition, we ha ve several organic gr owth pr ojects which t
o g ether could add ma terially to our reserves and future
production. In M e xic o , H a r bour h a s a 1 2 .39 per cent
non-ope ra t ed in t e r es t in the Zama u nit whe re the Blo c k
7 partne r s and P em e x have substantially agreed the field d e v
e lopment plan ahead of targeted submission t o the M e xican r e
gul a t o r by the end of the first quarter of 2023. Front-End
Engineering and Design work (FEED) is planned f or 2023, along with
an update of project co s t es t im a t es, ah e ad of a final i nv
es tment decisio n.
In Indonesia, we made a ma terial offshore gas discovery with
the pl a y -openi n g Ti m pan-1 w e ll on our An d aman II licenc
e in July. As a result, we acquired 3,400 km(2) of 3D seismic
across the eastern part of the Andaman II licence at the end of
2022 and plan to drill at least three e xplo r a tion and appraisal
w e lls ac r o s s our An d aman ac r e a ge beginning in the
second half of 2023.
Elsewhere in Indonesia the government approved a plan of
development for the Tuna field in December. However, further
progress has been impacted by EU and UK sanctions which limit our
ability as operator to provide certain services to our Russian
partner in the Tuna licence. We are working with our partner to
reach a solution to enable us to progress the project in 2023.
Maturing our 2P reserves and 2C resources to support production
and reserves replacement
As at 31 December 2022, Harbour's pr oven and probable (2P)
reserves on a working interest basis were 410 mmboe (2021: 488
mmboe), reflecting the impact of 2022 production. While we made
progress maturing 2C resources into 2P reserves, including at
J-Area and Greater Britannia Area, this was offset by a downward
revision at the Tolmount field based on pressure and other
performance data.
Harbour's 2C resources stood at 455 mmboe as at 31 December 2022
(2021: 460 mmboe). This reflects the material addition of the
Timpan gas discovery in Indonesia, offset by the movement of some
volumes to 2P reserves and relinquishments and r evisions following
the high grading of our remaining UK 2C portfolio.
Investing in the energy transition
Harbour is well positioned to contribute to the energy
transition through our CCS projects, utilising our skills,
infrastructure and 40 years' knowledge of operating in the North
Sea, and through responsibly decommissioning retired oil and gas
infrastructure which cannot be repurposed for CCS.
During 2022, we made significant progress on our flagship CCS
project, Viking. We completed pre-FEED work and concluded
non-statutory and statutory consultations for the onshore pipeline.
In addition, we had our contingent CO(2) storage resources of 300
million tonnes independently evaluated by ERCE via a Competent
Person's Report, we believe the first project in the UK and only
the third in the world to have done so.
We m a t e r ial l y e xpanded the project's future customer b a
se through early commercial agreements w ith W es t Burt on Ene rgy
and RWE, whilst maintaining strong technical progress under
existing agreements with Phillips 66 and VPI . As a result , the
Viking CCS cluster has the p o t en t ial t o ca p t u r e , t r an
s port and s t o r e 10 mtpa of C O (2) b y 2030 and 15 mtpa b y
203 5 , m a t e r ial l y cont r ibu t i n g t o the U K 's g oal
of 20 t o 30 mtpa b y 203 0. W e also en t e r ed in t o an ex c
lus i v e comme r cial r e l a t ionship w ith Associated British
Ports who are advancing plans to d e v e lop a C O (2) i m port t e
r minal at Immi n gha m , enabling the potential for shipped CO(2)
(domestic and imported) to be transported and stored by Viking
CCS.
Harbour, together with its partners, continued to progress the
Acorn project in Scotland whi c h h a s the p o t en t ial t o s t
o r e up t o 9 mtpa of CO (2) . Subject to receiving clarity from
the UK Government on the fiscal, regulatory and commercial
framework, Harbour is aiming to progress Viking and Acorn to final
investment decisions in 2024, with first CO(2) injection as early
as 2027.
During 2022, Harbour's decommissioning team continued to deliver
a strong safety and environmental performance. In the southern
North Sea, we successfully plugged and abandoned seven wells,
removed seven platforms and completed an extensive post removal
seabed remediation campaign.
In total during 2022, Harbour spent c.$300 million on our energy
transition activities including the decommissioning of
non-producing oil and gas facilities, our CCS activities and
projects to reduce our own emissions.
A solid financial position
Du r i n g 202 2 , w e g ene ra t ed f r e e cash flo w of $2.1
billion (2021: $0.7 billion). The significant increase w a s d ri v
en b y higher p r oduc t ion l e v e ls and the improved commodity
price environment offset by hedging losses and significantly
increased cash tax payments. Our realised oil and gas prices were
$78/bbl and 86 pence/therm, materially below the average Brent and
UK NBP gas prices of $101/bbl and 198 pence/therm due to our
historical hedging programme.
Our cash flow generation enabled us to rapidly deleverage our
balance sheet during 2022 with net debt (excluding unamortised
fees) reducing to $0.8 billion (2021: $2.3 billion) and leverage
(net debt/EBITDAX) reducing to 0.2x (2021: 0.9x).
As a result of this strong financial performance, our Board appr
oved $400 million of share buybac ks during the year, in addition
to our $200 million annual dividend. As a result of the share
buybacks, $361 million of which was completed in 2022 and $41
million in 2023, we repurchased and cancelled 9.7 per cent of our
issued share capital.
In line with our stated dividend policy to pay ordinary
dividends of $200 million per annum, the Board has declared a final
dividend of $100 million in respect of the 2022 financial year to
be paid in May 2023, subject to shareholder approval.
2022 saw the introduction of the UK EPL, which was subsequently
increased and extended, taking our UK headline tax rate to 75 per
cent until March 2028. The EPL has disproportionately impacted UK
focused independent oil and gas companies. For Harbour, the largest
oil and gas producer in the UK, it has all but extinguished our
profit for the year, necessitated a review of our future activity
and staffing levels in the country and reinforced our strategic
goal to grow and diversify internationally.
Outlook for 2023
Harbour enters 2023 well placed to deliver on its strategy of
building a global, diverse oil and gas company, supported by a
cash-generative asset base, a robust balance sheet, disciplined
capital allocation and a prudent approach to risk management. We
will continue to return any excess capital to shareholders while
investing in our existing portfolio and maintaining capacity for
meaningful M&A. As a result, the Board has approved a $200
million share buyback programme. This, together with our $200
million annual dividend policy, brings total announced shareholder
returns to $1 billion since December 2021.
At $85/bbl and 150 pence/therm average oil and gas prices, we
forecast 2023 free cash flow of c.$1 billion and have the potential
to be net debt free in 2024 following increased shareholder
returns.
Financial Review
These 2022 results represent the first full year for Harbour
through to 31 December 2022.
The 2021 comparative results for the income statement are
representative of three months of Chrysaor (January to March 2021)
and nine months of Harbour (April to December 2021, post-merger of
Chrysaor and Premier Oil on 31 March 2021).
Summary of financial results
2022 2021
Production and post-hedging realised
prices
Production - kboepd 208 175
Crude oil - $/boe 78 59
UK natural gas - p/therm 86 54
Indonesia natural gas - $/mscf 14 12
Income statement
Revenue and other income - $ million 5,431 3,618
EBITDAX (1) - $ million 4,011 2,431
Profit before taxation - $ million 2,462 315
Profit after taxation - $ million 8 101
Basic earnings per share - $/share 0.0 0.1
Other financial key figures
Total capital expenditure (1) -
$ million 907 935
Operating cash flow - $ million 3,130 1,614
Free cash flow (1) - $ million 2,105 678
Shareholder returns paid - $ million 553 -
Net debt (after unamortised fees)
(1) - $ million 704 2,147
Leverage ratio (1) 0.2 0.9
=========================================== ================================ ======
(1) See Glossary for the definition of non-IFRS measures.
Reconciliations between IFRS and non-IFRS measures are provided
within this review.
Income Statement
2022 2021
$ $
million million
Revenue
and
other
income
(note
4) 5,431 3,618
* Crude 2,792 2,023
* Gas 2,322 1,264
* Condensate 238 164
* Tariff income and other revenue 38 28
* Other income 41 139
EBITDAX 4,011 2,431
Operating
profit 2,541 640
Profit
before
taxation 2,462 315
Taxation (2,454) (213)
Profit
after
tax 8 101
$/share $/share
Basic
earnings
per
share 0.0 0.1
============================================== ========= =========
Revenue and other income
Total revenue and other income increased to $5,431 million
(2021: $3,618 million). This was driven by the increase in
production, especially UK gas production, which was 34 per cent
higher compared to 2021, and higher post-hedging realised
prices.
Revenue earned from hydrocarbon production activities increased
to $5,352 million (2021: $3,451 million) after realised hedging
losses of $3,185 million (2021: $1,517 million). Some of our
hydrocarbon production is sold pursuant to fixed-price contracts.
The rest is sold at market values, subject to standard quality and
basis adjustments.
Crude oil sales increased to $2,792 million (2021: $2,023
million), with a realised post-hedging oil price of $78/bbl (2021:
$59/bbl).
Gas revenue was $2,322 million (2021: $1,264 million), split
between UK natural gas revenue of $2,142 million (2021: $1,143
million) and international gas revenue of $180 million (2021: $121
million). The realised post-hedging price for our UK and Indonesia
gas was 86 pence/therm (2021: 54 pence/therm) and $14.2/mscf (2021:
$11.7/mscf), respectively.
Other income amounted to $41 million (2021: $139 million). The
reduction on the prior year was driven by mark-to-market losses on
European Union Agency emissions hedges of $3 million (2021: gains
of $51 million) and a consideration adjustment of $40 million
received from ConocoPhillips included in 2021 other income. Further
detail can be found in note 4.
Cost of Operations
2022 2021
$ $
million million
Operating
costs
Field
operating
costs
(1) 1,087 1,003
Tariff
income (30) (27)
Total 1,057 976
Operating
costs
per
barrel
($
per
barrel) 13.9 15.2
Depreciation,
depletion
and
amortisation
(DD&A)
before
impairment
charges
Depreciation
of
oil
and
gas
properties
(cost
of
operations
only) 1,507 1,327
Depreciation
of
non-oil
and
gas
properties 38 42
Amortisation
of
intangible
assets 1 2
---------------- --------- ---------
Total 1,546 1,371
---------------- --------- ---------
DD&A
before
impairment
charges
($
per
barrel) 20.4 21.4
================ ========= =========
(1) Includes mark-to-market losses of $3 million on EUA
emissions hedges included in Other revenue (2021: gains of $51
million), excludes non-cash depreciation on non-oil and gas
assets.
Cost of operations increased to $2,845 million (2021: $2,453
million) reflecting a full year contribution from the Premier Oil
assets and the addition of the Tolmount field, partially offset by
a foreign exchange benefit from the pound sterling weakening
against the US dollar. Unit operating costs equated to $13.9/boe
(2021: $15.2/boe) with the reduction largely due to higher
production volumes.
Depreciation, depletion and amortisation (DD&A) unit
expense, which reflects the depreciation of capitalised producing
assets costs over production, was $20.4/boe (2021: $21.4/boe).
EBITDAX
EBITDAX increased to $4,011 million (2021: $2,431 million),
driven by higher production and higher commodity prices, partially
offset by higher operating costs.
2022 2021
$ $
million million
Operating
profit 2,541 640
Depreciation,
depletion
and
amortisation 1,546 1,371
Impairment/(reversals)
of
property,
plant
and
equipment (170) 117
Exploration
and
evaluation
and
new
ventures 42 50
Exploration
costs
written-off 64 255
Gain (12) -
on
disposal
Provision
for
onerous
contracts - (2)
EBITDAX 4,011 2,431
======================== ========= =========
Impairments and reversals
The Group has recognised a net pre-tax impairment reversal of
$170 million (2021: $117 million charge) which consists of three
items.
First there was a single impairment of $163 million relating to
one of our North Sea producing fields. This is due to the
contracted price we realise for our crude sales being negatively
impacted by the pricing differential between Urals and Brent crude
and a revised operating cost profile for the field. The price
provisions in the contract are currently the subject of a dispute
with the buyer.
Second, the Group has recognised impairment reversals of $251
million (2021: nil) on North Sea gas assets that were previously
impaired. This was primarily driven by higher gas price assumptions
for UK natural gas.
Finally, the Group recognised an impairment credit of $82
million (2021: $9 million charge) in respect of revisions to
decommissioning estimates on the Group's non-producing assets.
Exploration and evaluation expenditure and new ventures
During the year, the Group expensed $106 million (2021: $305
million) for exploration and appraisal activities. This includes:
exploration write-off expense of $64 million (2021: $255 million),
following a technical review of our UK exploration asset portfolio;
$42 million (2021: $50 million) related to pre-development costs of
which $28 million (2021: $14 million) was associated with our UK
CCS and electrification projects; and ongoing pre-licence
expenditure of $14 million (2021: $36 million).
Net financing costs
Finance income increased to $279 million (2021: $49 million).
This was driven by increased foreign exchange gains of $202 million
(2021: losses of $65 million shown as finance expense) reflecting
the weakening of the UK pound sterling against the US dollar. In
particular, this included unrealised foreign exchange gains arising
predominantly on the revaluation of open sterling denominated UK
gas hedges using a significantly lower sterling US dollar exchange
rate . Finance income also includes gains of $38 million (2021: $15
million) on interest rate and foreign currency derivatives.
Finance expenses amounted to $358 million (2021: $375 million).
This included interest expense incurred on debt facilities of $98
million (2021: $113 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
provisions, primarily associated with future decommissioning
obligations, of $65 million (2021: $78 million) and bank and
financing fees of $91 million (2021: $63 million). 2021 included
foreign exchange losses of $65 million as noted above.
Further detail on finance income and expense can be found in
note 6.
Earnings and taxation
Profit after tax amounted to $8 million (2021: $101 million ) ,
with increased profit before tax almost wholly offset by the
negative impact of the introduction of the EPL in the UK. This
resulted in earnings per share of $0.0 (2021: earnings $0.1) after
taking into account the weighted average number of ordinary shares
in issue of 900 million (2021: 871 million) following the share
buyback programme . Whilst the number of shares reduced during 2022
due to the share buyback programs, the weighted number of shares
increased during 2022 compared to 2021 due to the impact of the
reverse acquisition effective 1 April 2021.
During 2022 the UK Government both enacted the EPL and
subsequently increased it and extended its duration. The EPL
applies an additional 25 per cent tax on profits earned from the
production of UK oil and gas from 26 May 2022, increasing to 35 per
cent from January 2023 to March 2028, irrespective of actual market
or realised oil and gas prices.
Harbour's tax expense increased in 2022 to $ 2,454 million
(2021: $213 million), primarily driven by the introduction of the
EPL.
The tax expense is split between a current tax expense of $706
million (2021: $192 million), which includes an EPL current tax
charge of $326 million, and a deferred tax expense of $1,748
million (2021: $21 million). Of the deferred tax expense, $1,469
million relates to a one-off non-cash deferred tax charge due to
the introduction of the EPL of which $148 million reversed in the
period. This arises because the deferred UK tax position on our
balance sheet has been revalued from 40 per cent to 75 per cent
where relevant to reflect the increase in our future tax rate in
the period to March 2028. The total tax charge therefore includes a
total of $1,647 million in relation to the EPL.
The effective tax rate is 100 per cent (2021: 68 per cent)
materially higher than the blended standard UK tax rate for the
period of 55 per cent. This increase is driven by the one off
deferred tax charge associated with the introduction of the EPL
partially offset by the profits from our international assets being
subject to a lower tax rate.
Shareholder distributions
A final dividend with respect to 2021 of 11 cents per ordinary
share was proposed on 17 March 2022 and approved by shareholders at
the AGM on 11 May 2022. The dividend was paid on 18 May 2022 to all
shareholders on the register as at 8 April 2022, totalling $98
million. An interim dividend was announced on 25 August at 11 cents
per share and was paid on 19 October 2022 at a value of $93
million.
In addition to these dividend payments, the Board approved $400
million of share buybacks during 2022. During 2022, we repurchased
and cancelled 78.4 million of our shares at a cost of $361
million(1) (2021: $nil). Post period end in February 2023, the
remaining $41 million(1) of the 2022 approved share buybacks was
concluded with the repurchase and cancellation of 11.1 million
shares. As a result, the total number of shares repurchased and
cancelled under the $400 million of share buybacks was 89.5 million
shares equating to 9.7 per cent of our issued share capital.
The Board is proposing final dividend with respect to 2022 of 12
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 10 May 2023. If
approved, the dividend will be paid on 24 May 2023 to shareholders
on the register as of 14 April 2023. 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 28 April
2023.
The Board has approved a new $200 million share buyback
programme to commence shortly. It is anticipated that an
irrevocable non-discretionary agreement will shortly be entered
into with the Company's corporate brokers to execute the programme
on the Company's behalf. The purpose of the programme is to reduce
the Company's share capital and all ordinary shares purchased as
part of this programme will be cancelled. The programme will end no
later than 31 December 2023. Any purchases of ordinary shares by
the Company in relation to this announcement will be conducted in
accordance with the relevant regulations (including but not limited
to the Listing Rules) and Harbour's general authority to repurchase
shares, a renewal of which will be sought at the Company's AGM in
May.
(1) Total spend on share buybacks includes transaction fees and
foreign exchange differences applied to the Sterling denominated
shares repurchased.
Statement of Financial Position
2022 2021
$ $
million million
Assets
Total
non-current
assets,
excluding
deferred
taxes 9,032 10,273
Deferred
tax
assets
(note
7) 1,407 1,938
Total
current
assets 2,127 2,294
Total
assets 12,566 14,505
Liabilities
and
equity
Total
borrowings
net
of
transaction
fees
(note
13) 1,238 2,886
Total
decommissioning
provisions
(note
12) 4,141 5,354
Deferred
tax
liabilities
(note
7) 397 187
Lease
creditor
(note
11) 825 654
Derivative
liabilities
(note
14) 3,451 3,538
Other
liabilities 1,493 1,412
Total
liabilities 11,545 14,031
Equity 1,021 474
Total
liabilities
and
equity 12,566 14,505
Net
debt
(note
15) (704) (2,147)
=================== ========= =========
Assets
At 31 December 2022, total assets amounted to $12,566 million
(2021: $14,505 million), of which current assets were $2,127
million (2021: $2,294 million). The decrease in total assets of
$1,939 million is mainly as a result of a reduction in the deferred
tax asset (see note 7) of $531 million and a reduction in property,
plant and equipment of $1,557 million (see note 10), partially
offset by the increase in right-of-use assets of $183 million (see
note 11). The reduction in property, plant and equipment is partly
due to the reduction in the decommissioning assets of $778 million
(2021: $358 million) primarily as a result of an increase in the
risk-free rate applied to the corresponding decommissioning
provisions (see note 12).
The net deferred tax position on the balance sheet is an asset
of $1,009 million. This balance mainly reflects future tax relief
available on decommissioning of $1,565 million, cash flow hedge
derivatives of $2,452 million and tax losses of $569 million offset
by additional tax expected to be paid on property, plant and
equipment (PP&E) of $3,396 million along with deferred tax
related to overseas operations and other of $181 million.
The introduction of the EPL has resulted in a net $355 million
decrease on deferred tax asset in the balance sheet as the
increased deferred tax liability of $1,470 million associated with
PP&E which impacts the income statement is offset by the
increased deferred tax asset of $1,115 million associated with the
cash flow hedge derivatives loss in the period which flows through
the other comprehensive income statement.
Liabilities
At 31 December 2022, total liabilities amounted to $11,545
million (2021: $14,031 million). The reduction in liabilities was
mainly driven by a reduction in the decommissioning provisions by
$1,213 million, and a reduction in borrowings of $1,648 million in
relation to the reserves-based lending (RBL) facility. The
decommissioning provision reduction was primarily due to an
increase in the risk-free rate used in the estimate, as well as the
changes in cost estimates used and currency translation
adjustments; refer to note 12 for more detail.
Equity and reserves
Total equity amounted to $1,021 million (2021: $474 million)
with the increase mainly due to the gains in comprehensive income
related to gains on cash flow hedges of $269 million (2021: losses
$3,584 million) and movements in tax on cash flow hedges of $1,006
million (2021: $1,433 million) offset by currency translation
movements of $198 million (2021: $6 million), share buybacks of
$361 million and dividend payments of $192 million made in the
year. Retained earnings were marginally increased by the profit
after tax.
Net debt
As at 31 December 2022, after unamortised fees, net debt of $704
million (2021: $2,147 million) consisted of $775 million (2021:
$2,438 million) drawn on the reserves-based lending facility (RBL),
the $500 million (2021: $500 million) bond and an exploration
financing facility (EFF) of $11 million (2021: $45 million) less
unamortised deferred fees of $82 million (2021: $136 million) and
cash balances of $500 million (2021: $699 million). The decrease in
the year is mainly due to the repayments on the RBL facility.
Available liquidity, being undrawn RBL facility plus cash
balances, was $2.5 billion at the end of the year.
Derivative financial instruments
We carry out hedging activity to manage commodity price risk, to
ensure we comply with the requirements of the RBL facility and to
ensure there is sufficient funding for future investments. We have
entered into a series of fixed-price sales agreements and a
financial hedging programme for both oil and gas, consisting of
swap and option instruments. Our future production volumes are
hedged under the physical and financial arrangements in place at 31
December 2022. These are set out in the following table. Hedges
realised to date are in respect of both crude oil and natural
gas.
The current hedging programme is shown below:
Hedge position 2023 2024 2025 2026
Oil
Volume hedged (mmboe) 10.95 7.32 2.37 -
Average price hedged ($/bbl) 74.08 84.37 81.22 -
UK natural gas
Volume hedged (mmboe) 23.08 11.25 1.94 -
Average priced hedged (p/therm) 41.46 68.85 75.22 -
================================= ====== ====== ====== =====
At 31 December 2022, our financial hedging programme on
commodity derivative instruments showed a pre-tax negative
mark-to-market fair value of $3,259 million (2021: $3,506 million),
with no ineffectiveness charge to the income statement. Refer to
note 14 for more information.
Statement of cash flows (1)
2022 2021
$ $
million million
Cash
flow
from
operating
activities
after
tax 3,130 1,614
Cash
flow
from
investing
activities
-
capital
investment (634) (644)
Cash
flow
from
investing
activities
-
acquired
on
business
combinations - 97
Cash
flow
from
investing
activities
-
other 5 (24)
Operating
cash
flow
after
investing
activities 2,501 1,043
Cash
flow
from
financing
activities
(2) (396) (365)
Free
cash
flow
(3) 2,105 678
Cash
and
cash
equivalents 500 699
=============== ========= =========
(1) Table excludes financing activities related to debt principal movements.
(2) Net of interest and lease payments
(3) Free cash flow is calculated as operating cash flow less
cash flow from investing activities less interest and lease
payments and is before shareholder distributions.
Net cash from operating activities after tax amounted to $3,130
million (2021: $1,614 million). This is after tax payments of $551
million (2021: $280 million), split $513 million in the UK and $38
million overseas, and positive working capital movements of $53
million (2021: negative $607 million).
Cash flow used in investing activities on capital expenditure
was $634 million (2021: $644 million). Cash outflow from financing
activities for lease payments, interest and charges paid was $396
million (2021: $365 million).
Cash flow from financing activities includes dividends paid of
$192 million (2021: $nil) and $361 million (2021: $nil) related to
the repurchase of Harbour's own shares through the share buyback
programmes undertaken during 2022.
Cash balances were $500 million (2021: $699 million) at the end
of the period.
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.
2022 2021
$ $
million million
Additions
to
oil
and
gas
assets
(note
10) (532) (464)
Additions
to
fixtures
and
fittings,
office
equipment
&
IT
software
(note
9
and
note
10) (41) (35)
Additions
to
exploration
and
evaluation
assets
(note
9) (111) (210)
Total
capital
investment
(1) (684) (709)
Movements
in
working
capital 28 42
Capitalised
lease
payments
(note
11) 22 23
Cash
capital
expenditure
per
the
cash
flow
statement (634) (644)
============== ========= =========
(1 ) Non-IFRS measure
During the period, the Group incurred total capital expenditure
of $907 million (2021: $935 million), split capital investment $684
million (2021: $709 million) and decommissioning spend $223 million
(2021: $226 million).
The capital investment mainly consisted of operated drilling on
the J-Area at the Jade, Judy and Jill fields, Catcher development
wells and non-operated drilling programmes on the Clair Ridge
platform. The decommissioning expenditure mainly relates to
activity in the southern North Sea and Balmoral area in the UK
Central North Sea.
Principal risks
There are no significant changes to the headline principal risks
from those disclosed in the 2022 half year results.
Post balance sheet events
On 14 February 2023, the company's defined benefit pension
scheme's (the 'Scheme') trustee effected a bulk annuity 'buy in'
policy with Just Retirement Limited. This policy secures the
benefits of all the Scheme's members and eliminates mortality and
investment risk from the company's balance sheet. This decision was
made principally in light of the substantial improvement to the
Scheme's funded status over 2022 and the favourable market
conditions for such transactions. The company was not required to
pay any additional contributions to the Scheme in respect of the
annuity purchase.
Going concern
The Group monitors its capital position and its liquidity risk
regularly throughout the year to ensure it has access to sufficient
funds to meet forecast cash requirements for the period twelve
months after the approval of the accounts until March 2024. Cash
forecasts are regularly produced based on, inter alia, the Group's
latest life of field production and expenditure forecasts,
management's best estimate of future commodity prices (based on
recent forward curves, adjusted for the Group's hedging programme)
and the Group's borrowing facilities.
The Group's base case going concern assessment is based upon
management's best estimate of forward commodity price curves and
uses production in line with approved asset plans and the ongoing
capital requirements of the Group will be financed by existing RBL
and bond financing arrangements.
In line with the principal risks, sensitivity analyses have been
prepared to reflect the combined impact of reductions in crude and
UK natural gas prices of 20 per cent on unhedged production and in
the Group's production of 10 per cent throughout the going concern
period. In these combined downside scenarios applied to the base
case forecast, the Group is forecasted to have sufficient financial
headroom throughout the going concern period.
Further, reverse stress tests have been prepared reflecting
further reductions in commodity price and production parameters,
prior to any mitigation strategies, to determine what levels each
would need to reach such that either lending covenants are
breached, or financial liquidity headroom runs out. The results of
this reverse stress test demonstrated the likelihood of the fall in
price and production parameters required to cause a risk of funds
shortfall or covenant breaches is remote.
Taking the above into account the Board was satisfied that for
the going concern period, the Group was able to maintain adequate
liquidity and no covenant breaches occurred and therefore has
adopted a going concern basis for preparing the financial
statements.
Consolidated income statement
For the year ended 31 December 2022 2021
Note $ million $ million
Revenue 4 5,390.0 3,478.8
Other income 4 41.2 139.2
---------- ----------
Revenue and other income 5,431.2 3,618.0
Cost of operations 5 (2,844.8) (2,453.2)
Impairment reversal/(impairment) of property,
plant and equipment 5, 10 169.6 (117.2)
Exploration and evaluation expenses and
new ventures 5 (41.5) (49.8)
Exploration costs written-off 5 (64.4) (255.0)
Gain on disposal 5 12.1 -
General and administrative expenses (121.3) (102.5)
---------- ----------
Operating profit 5 2,540.9 640.3
Finance income 6 279.1 48.8
Finance expenses 6 (358.2) (374.6)
---------- ----------
Profit before taxation 2,461.8 314.5
Income tax expense 7 (2,453.6) (213.4)
---------- ----------
Profit for the year 8.2 101.1
========== ==========
Profit for the year attributable to:
Equity owners of the Company 8.2 101.1
Earnings per share $ cents $ cents
----------
Basic 0.9 11.6
Diluted 0.9 11.6
Consolidated statement of comprehensive income
For the year ended 31 December
2022 2021
$ million $ million
Profit for the year 8.2 101.1
Other comprehensive profit/(loss)
Items that may be subsequently reclassified
to income statement:
Fair value gains/(losses) on cash flow hedges 269.1 (3,583.8)
Tax credit on cash flow hedges 1,005.6 1,433.2
Pension actuarial losses on long term employee
benefit plans (0.3) -
Exchange differences on translation (198.0) (5.7)
------------ ------------
Other comprehensive profit/(loss) for the
period, net of tax 1,076.4 (2,156.3)
Total comprehensive profit/(loss) for the
year 1,084.6 (2,055.2)
============ ============
Total comprehensive profit/(loss) attributable
to:
============ ============
Equity owners of the Company 1,084.6 (2,055.2)
============ ============
Consolidated balance sheet
2 021
As at 31 December 2022 restated
Note $ million $ million
Assets
Non-current assets
Goodwill 1,327.1 1,327.1
Other intangible assets 9 880.0 873.7
Property, plant and equipment 10 5,690.2 7,246.7
Right-of-use assets 11 734.7 551.5
Deferred tax assets 7 1,406.5 1,938.4
Other receivables 298.0 263.0
Other financial assets 14 102.7 10.1
---------- -----------
Total non-current assets 10,439.2 12,210.5
---------- -----------
Current assets
Inventories 142.9 211.4
Trade and other receivables 1,403.2 1,342.2
Other financial assets 14 80.8 41.8
Cash and cash equivalents 499.7 698.7
---------- -----------
Total current assets 2,126.6 2,294.1
---------- -----------
Total assets 12,565.8 14,504.6
========== ===========
Equity and liabilities
Equity
Share capital 171.1 171.1
Share premium - 1,504.6
Other reserves (606.2) (1,276.8)
Retained earnings 1,456.4 74.6
---------- -----------
Total equity 1,021.3 473.5
========== ===========
Non-current liabilities
Borrowings 13 1,216.6 2,823.7
Provisions 12 3,933.7 5,022.6
Deferred tax 7 397.2 187.1
Trade and other payables 18.8 32.3
Lease creditor 11 603.8 489.2
Other financial liabilities 14 1,279.1 1,373.6
---------- -----------
Total non-current liabilities 7,449.2 9,928.5
---------- -----------
Current liabilities
Trade and other payables 1,251.2 1,235.3
Borrowings 13 21.5 62.3
Lease creditor 11 220.8 165.1
Provisions 12 231.6 358.6
Current tax liabilities 198.7 116.8
Other financial liabilities 14 2,171.5 2,164.5
---------- -----------
Total current liabilities 4,095.3 4,102.6
---------- -----------
Total liabilities 11,544.5 14,031.1
---------- -----------
Total equity and liabilities 12,565.8 14,504.6
========== ===========
Consolidated statement of changes in equity
For the year ended 31 December
Cash Costs
flow of
Capital hedge hedging Currency
Share Share Merger redemption reserve reserve translation Retained Total
capital premium(3) reserve(3) reserve (1) (1) reserve earnings equity
$ million $ million $ million $ million $ million $ million $ million $ million $ million
At 1 January
2022 171.1 1,504.6 677.4 8.1 (2,062.1) 1.5 98.3 74.6 473.5
Profit for the
year - - - - - - - 8.2 8.2
Other
comprehensive
income 1,286.1 (11.4) (198.0) (0.3) 1,076.4
---------- ----------- ----------- ----------- ---------- ---------- ------------ ---------- ----------
Total
comprehensive
income - - - - 1,286.1 (11.4) (198.0) 7.9 1,084.6
Purchase and
cancellation
of own shares - - - - - - - (360.6) (360.6)
Share-based
payments - - - - - - - 36.9 36.9
Capital
restructuring - (1,504.6) (406.1) - - - - 1,910.7 -
Purchase of
ESOP Trust
Shares - - - - - - - (21.6) (21.6)
Dividend paid - - - - - - - (191.5) (191.5)
---------- ----------- ----------- ----------- ---------- ---------- ------------ ---------- ----------
At 31 December
2022 171.1 - 271.3 8.1 (776.0) (9.9) (99.7) 1,456.4 1,021.3
========== =========== =========== =========== ========== ========== ============ ========== ==========
At 1 January
2021 0.1 910.0 - - 80.2 9.8 104.0 (36.8) 1,067.3
Profit for the
period - - - - - - - 101.1 101.1
Other
comprehensive
loss - - - - (2,142.3) (8.3) (5.7) - (2,156.3)
---------- ----------- ----------- ----------- ---------- ---------- ------------ ---------- ----------
Total
comprehensive
loss (2,142.3) (8.3) (5.7) 101.1 (2,055.2)
Shares issued
in settlement
of D loan
notes - 134.7 - - - - - - 134.7
Reverse
takeover 171.0 (527.2) 635.9 8.1 - - - - 287.8
Settlement of
Premier's
debt (2) - 987.1 41.5 - - - - - 1,028.6
Share-based
payments - - - - - - - 13.4 13.4
Purchase of
ESOP Trust
Shares - - - - - - - (3.1) (3.1)
At 31 December
2021 171.1 1,504.6 677.4 8.1 (2,062.1) 1.5 98.3 74.6 473.5
========== =========== =========== =========== ========== ========== ============ ========== ==========
(1) Disclosed net of deferred tax
(2) Debt settlement relates to the issuance of shares in partial
settlement of Premier's debt.
(3) Share premium and merger reserve balances recategorised to
retained earnings following capital reduction effective 3 August
2022.
Consolidated statement of cash flows
For the year ended 31 December 2022 2021
Note $ million $ million
Net cash inflow from operating activities 15 3,129.8 1,614.2
--------- ---------
Investing activities
Expenditure on exploration and evaluation
assets (127.0) (176.5)
Expenditure on property, plant and equipment 12 (476.5) (437.4)
Expenditure on non-oil and gas intangible
assets (29.7) (30.0)
Cash acquired on business combinations - 97.4
Receipts for sub-lease income 10.4 7.4
Payments relating to disposal of oil and
gas properties (5.9) -
Expenditure on business combinations - deferred
consideration (19.9) (46.0)
Finance income received 20.0 14.1
Net cash outflow from investing activities (628.6) (571.0)
--------- ---------
Financing activities
Repurchase of shares (360.6) -
Proceeds from new borrowings - reserves
based lending facility 13 - 1,617.5
Proceeds from new borrowings -bond 13 - 500.0
Proceeds from new borrowings - exploration
financing facility 13 11.5 45.9
Lease liability payments 11 (254.0) (160.4)
Repayment of short-term debt arising on
business combination 13 - (1,276.5)
Repayment of hedging liabilities arising
on business combination - (48.5)
Repayment of reserves based lending facility 13 (1,662.5) (697.5)
Repayment of junior debt 13 - (400.0)
Repayment of exploration financing facility 13 (38.6) (14.7)
Repayment of financing arrangement 13 (15.4) (9.3)
Redemption of loan notes 13 - (135.7)
Purchase of ESOP Trust shares (21.6) (3.1)
Interest paid and bank charges (142.0) (204.9)
Dividends paid 16 (191.5) -
Net cash outflow from financing activities (2,674.7) (787.2)
--------- ---------
Net (decrease)/increase in cash and cash
equivalents (173.5) 256.0
Net foreign exchange difference (25.5) (2.7)
Cash and cash equivalents at 1 January 698.7 445.4
--------- ---------
Cash and cash equivalents at 31 December 499.7 698.7
========= =========
Notes to the financial statements
1. Corporate 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 4(th) Floor, Saltire Court,
20 Castle Terrace, Edinburgh, EH1 2EN, United Kingdom.
The consolidated financial statements of Harbour Energy plc
('the Company') and all its subsidiaries ('the Group') for the year
ended 31 December 2022 were authorised for issue by the Board of
Directors on 8 March 2023.
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. Significant accounting policies
Basis of preparation
The consolidated financial statements have been prepared on a
going concern basis in accordance with UK-adopted International
Accounting Standards (IAS) in conformity with the requirements of
the Companies Act 2006. The analysis used by the Directors in
adopting the going concern basis considers the various plans and
commitments of the Group as well as various sensitivity and reverse
stress test analyses. The results from the 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 0.1 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.
In October 2020, Harbour Energy Limited entered into an
agreement with Premier Oil plc ('Premier') regarding an all-share
merger between Premier and Harbour Energy Limited's subsidiary,
Chrysaor Holdings Limited ('Chrysaor'). Under the terms of the
merger, Premier legally acquired Chrysaor through the issuance of
consideration shares whilst Chrysaor was the acquiror for
accounting purposes, primarily as a result of its ability to
appoint the Board of the enlarged group. The transaction completed
on 31 March 2021, whereupon Premier, being the legal acquirer and
accounting acquiree, changed its name from Premier Oil plc to
Harbour Energy plc.
The consolidated financial statements provide comparative period
information with respect to the prior year but this only includes
nine months of Premier contribution compared to a full 12 months
contribution for the year ended 31 December 2022. The financial
information for the year ended 31 December 2022 does not constitute
statutory accounts as defined in sections 435 (1) and (2) of the
Companies Act 2006. Statutory accounts for the year ended 31
December 2021 have been delivered to the Registrar of Companies and
those for 2022 will be delivered following the Company's annual
general meeting. The auditor has reported on these accounts; their
report was unqualified. Their report did not include a reference to
any other matters to which the auditor drew attention by way of
emphasis of matter and did not contain a statement under section
498 (2) or (3) of the Companies Act 2006.
This preliminary announcement is consistent with the audited
financial statements of the Group for the year-ended 31 December
2022. It is anticipated that the full Annual Report and Financial
Statements will be published on the Company's website during March
2022 ( www.harbourenergy.com ). It is anticipated that the Annual
General Meeting will be held on 10 May 2023.
Accounting Policies
The accounting policies adopted in the preparation of the 2022
consolidated financial statements are consistent with those adopted
and disclosed in Harbour's 2021 Annual Report and Accounts. A
number of amendments to existing standards and interpretations were
effective from 1 January 2022 but had no impact on the half-year
financial statements. The Group has not early adopted any standard,
interpretation or amendment that has been issued but is not yet
effective.
Basis of consolidation
The consolidated financial statements comprise the financial
statements of the Company and its subsidiaries as at 31 December
2022. 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.
Prior Year Adjustment
Other financial liabilities - commodity derivatives within
current liabilities as at 31 December 2021 included a number of
financial instruments which had matured on the last day of the
financial year for which the related liability should have been
classified within trade and other payables. The relevant amounts
have therefore been reclassified to trade and other payables which
is also held within current liabilities. There was no impact on any
of the other primary statements. Each of the affected financial
statement line items has been restated and the impact is summarised
in the following table.
Balance sheet As previously Adjustments As restated
at 31 December reported $ million $ million
2021 $ million
Other financial
liabilities - commodity
derivatives (note
14) (2,526.2) 361.7 (2,164.5)
-------------- ------------ ------------
Trade and other
payables (873.6) (361.7) (1,235.3)
-------------- ------------ ------------
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 2021 Annual Report
and Accounts. Disclosure regarding the judgements and estimates
made in assessing the impact of climate change and the energy
transition are detailed below.
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 accordingly. Management recognises there is
a general high level of uncertainty about the speed and scale of
impacts which, together with limited historical information,
provides significant challenges in the preparation of forecasts and
plans with a range of possible future scenarios.
The Group's strategic ambition is to achieve Net Zero by 2035
through several opportunities, including operational improvements,
UK offshore electrification, UK carbon capture and storage (CCS)
and the eventual cessation of production of mature fields. Where
the Group cannot reduce its Scope 1 and 2 emissions, it will invest
in 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 impairment
assessment, going concern and viability, deferred tax
recoverability) includes project costs related to carbon, capture
and storage; and certain limited electrification and reduction of
Scope 1 and 2 GHG emissions initiatives. Emissions reduction
incentives are part of staff remuneration and annual bonus schemes.
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.
As a result, 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 financial statements.
Estimates adopted in the preparation of the financial statements
reflect management's best estimate of future market conditions
where, in particular, commodity prices can be volatile.
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 curve 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. It is recognised that the reality of the
nature of progress of energy transition will bring greater levels
of disruption and volatility than these external scenarios expect
and do not represent management's current best estimate.
Management's current best estimate , which was derived from
consideration of a range of considered economic forecast, 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
recoverable amount of property, plant and equipment and goodwill.
In the current period, the Harbour scenario real long-term
commodity price assumptions, when testing for impairment, were
$65/bbl (2021: $65/bbl) and 65p/therm (2021: 60p/therm) for Brent
crude and UK NBP gas, respectively. The real long-term price
assumptions for the UK regulatory price of carbon are GBP80 /tonne,
being $100/tonne at $:GBP1.25 foreign exchange rate, (2021:
GBP55/$74/tonne) and voluntary offsets $25/tonne used, with
sensitivities run at $100/tonne (2021: $100/tonne). Sensitivity
analysis using a carbon price of $100/tonne indicates that material
impairments would not arise. Such assumptions are inherently
uncertain and may ultimately differ from the actual amounts.
During 2022 there was a net pre-tax impairment credit of $170
million comprising: impairment on a single CGU asset $163 million,
impairments reversals on North Sea assets $250 million and
decommissioning provision reductions $83 million. In 2021, certain
impairments were recognised as a result of underlying reservoir
performance.
Sensitivities on the impairment of property, plant and equipment
and goodwill have been prepared using various 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 and impairments sensitivities have been prepared at an
average -10 per cent and +10 per cent to the Harbour scenario
average crude and selected published climate change price curves.
Sensitivity analysis on carbon price $100/tonne indicates that
impairments would not have a material impact on the financial
statements.
The sensitivity scenarios described below are price curves only
and the modelling 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.
-- Harbour scenario base price curve for crude oil used for
impairment testing
-- NGFS Current Policies reflects high physical risks and low transition risks
-- NGFS Delayed Transition reflects low physical risks and high transition risks
-- IEA Net Zero 2050 reflects low physical risks and low
transition risks
The graph above shows the crude oil price curves for the period
to 2050 for the Harbour scenario, NGFS Current Policies, NGFS
Delayed Transition and IEA Net Zero 2050. There are no climate
change price curves published by NGFS or the IEA for UK NBP gas.
All the scenario price curves are dependent on factors covering
supply, demand, economic and geopolitical events and therefore are
inherently uncertain and subject to significant volatility and
hence unlikely to reflect the future outcome.
The results of the sensitivities are as follows and show the
impact on the balance sheet carrying values.
$ million Carrying Crude oil
value
-10% +10% NGFS NGFS IEA Net
to Harbour to Current Delayed Zero 2050
scenario Harbour Policies Transition
scenario
--------- ------------ ---------- ---------- ------------ -----------
Property,
plant and
equipment 5,690 (57) - - - (355)
--------- ------------ ---------- ---------- ------------ -----------
Goodwill 1,327 - - - - -
--------- ------------ ---------- ---------- ------------ -----------
The sensitivity results show that under the -10 per cent to
Harbour scenario (oil and gas commodity prices reduced from 1
January 2023) an impairment of $57 million would arise on a single
North Sea CGU. The +10 per cent to Harbour scenario (oil and gas
commodity prices increased from 1 January 2023), NGFS Current and
Delayed scenarios show no incremental impairments as these
scenarios are all favourable to the Harbour scenario. Furthermore,
under these three scenarios, no reversal of any historic impairment
is triggered as there have been no prior crude oil-price related
impairments. Under the IEA Net Zero 2050 scenario there would be an
impairment in property, plant and equipment of $355 million with
goodwill not impacted given sufficient value headroom.
Property, plant and equipment - depreciation and expected useful
lives
The energy transition has the potential to reduce the expected
useful lives of assets and consequently accelerate depreciation
charges. 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
known 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 $417
million and $162 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.
The energy transition may accelerate the decommissioning of
producing assets and therefore increase the carrying value of
provisions. The Group currently expects to incur decommissioning
costs over the next 40 years, the majority of which are anticipated
to be incurred between the next 10 to 20 years. Currently, the
timing of decommissioning expenditures have 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 2022 2021
$ million $ million
Revenue
North Sea 5,082.1 3,268.2
International 307.9 210.6
----------- -----------
Total Group sales revenue 5,390.0 3,478.8
Other income
North Sea 40.9 139.0
International 0.3 0.2
----------- -----------
Total Group revenue and other income 5,431.2 3,618.0
----------- -----------
Operating profit
North Sea 2,388.4 699.3
International 152.5 (59.0)
----------- -----------
Group operating profit 2,540.9 640.3
Finance income 279.1 48.8
Finance expenses (358.2) (374.6)
----------- -----------
Profit before income tax 2,461.8 314.5
Income tax expense (2,453.6) (213.4)
----------- -----------
Profit for the financial year 8.2 101.1
=========== ===========
Balance sheet
Segment assets
North Sea 11,346.2 13,325.8
International 1,219.6 1,178.8
----------- -----------
Total assets 12,565.8 14,504.6
=========== ===========
Segment liabilities
North Sea (10,937.3) (13,379.6)
International (607.2) (651.5)
----------- -----------
Total liabilities (11,544.5) (14,031.1)
=========== ===========
Other information
Capital additions
North Sea 576.2 640.7
International 108.6 68.4
----------- -----------
Total capital additions 684.8 709.1
=========== ===========
Depreciation, depletion and amortisation
North Sea 1,470.4 1,299.8
International 75.4 71.2
----------- -----------
Total depreciation, depletion and amortisation 1,545.8 1,371.0
=========== ===========
Exploration and evaluation expenses and
new ventures
North Sea 33.5 45.4
International 8.0 4.4
----------- -----------
Total exploration and evaluation expenses
and new ventures 41.5 49.8
=========== ===========
Exploration costs written-off
North Sea 71.6 121.1
International (7.2) 133.9
Total exploration costs written-off 64.4 255.0
=========== ===========
Exploration costs written-off of $64.4 million is net of a $5.7
million credit related to a decrease in the decommissioning
provisions in the North Sea (note 12) and includes a $7.0 million
credit related to a change to the decommissioning estimate in the
Falkland Islands business unit (2021: $6.3 million relating to the
effect of changes in decommissioning provisions on oil and gas
intangible assets previously written-off).
4. Revenue from contracts with customers and other income
2022 2021
$ million $ million
Type of goods
Crude oil sales 2,791.9 2,023.4
Gas sales 2,321.5 1,264.0
Condensate sales 238.3 163.6
--------- ---------
Total revenue from contracts with customers
(1) 5,351.7 3,451.0
Tariff income 30.0 27.2
Other revenue 8.3 0.6
--------- ---------
Total revenue from production activities 5,390.0 3,478.8
Other income (2) 41.2 139.2
Total revenue and other income 5,431.2 3,618.0
========= =========
(1) Revenues from contracts with customers of $8,536.5 million
(2021: $4,968.2 million) include crude oil sales of $3,544.7
million (2021: $2,278.1 million) and gas sales of $4,753.5 million
(2021: $2,526.5 million). This was prior to realised hedging losses
in the period of $752.8 million (2021: $254.7 million) on crude oil
and $2,432.0 million (2021: $1,262.5 million) on gas sales.
(2) Other income mainly represents $20.3 million partner
recoveries related to lease obligations (2021: $26.0 million), mark
to market losses on EUA emissions hedges of $2.6 million (2021:
gain of $51.0 million) and $16.7 million in respect of Research and
Development Expenditure credits (2021: $17.5 million). Other income
in 2021 included a receipt from ConocoPhillips in relation to an
adjustment to consideration relating to Chrysaor's purchase of the
ConocoPhillips UK business in 2019 (2021: $40.0 million).
Approximately 84 per cent (2021: 84 per cent) of the revenues
were attributable to sales to energy trading companies of the Shell
group.
5. Operating profit
2022 2021
$ million $ million
Cost of operations
Production, insurance and transportation costs 1,114.2 1,085.5
Gas purchases 36.6 28.4
Royalties 5.0 3.8
Depreciation of oil and gas assets (note 10) 1,318.4 1,204.1
Depreciation of right-of-use oil and gas assets
(note 11) 218.6 153.9
Capitalisation of IFRS 16 lease depreciation
on oil and gas assets (note 11) (29.9) (30.7)
Other cost of operations - (0.5)
Onerous contract provision (note 12) - (2.3)
Amortisation of capacity rights (note 9) 1.0 1.6
Remeasurement of royalty valuation - (0.5)
Remeasurement - loss on termination of lease - 0.3
Movement in over/underlift balances and hydrocarbon
inventories 180.9 9.6
Total cost of operations 2,844.8 2,453.2
========= =========
Impairment (reversal)/expense of property, plant
and equipment (note 10) (87.3) 108.7
Impairment (gain)/loss due to (decrease)/increase
in decommissioning provisions on oil and gas
tangible assets (note 12) (82.3) 8.5
Exploration costs written-off (note 9) (1) 64.4 255.0
Exploration and evaluation expenditure and new
ventures (2) 41.5 49.8
(Gain)/loss on disposal (3) (12.1) 0.1
General and administrative expenses
Depreciation of right-of-use non-oil and gas
assets (note 11) 11.2 10.5
Depreciation of non-oil and gas assets (note
10) 5.4 5.5
Amortisation of non-oil and gas intangible assets
(note 9) 21.1 26.1
Other administrative costs 83.6 60.4
Total general and administrative expenses 121.3 102.5
========= =========
Auditors' remuneration
Audit fees
Fees payable to the Company's auditor for the
Company's Annual Report 2.6 3.1
Audit of the Company's subsidiaries pursuant
to legislation 0.6 0.5
Non audit fees (5)
Other services pursuant to legislation - interim
review 0.2 0.3
Other services (6) 0.8 0.4
--------- ---------
5. Operating profit (continued)
(1) Exploration costs written-off of $64.4 million includes a
credit of $7.0 million related to a change to the decommissioning
estimate in the Falkland Islands business unit.
(2) Exploration and evaluation expenditure and new ventures of
$41.5 million (2021: $49.8 million) includes $28.4 million (2021:
$14.4 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 $13.1 million (2021 $35.4 million) of ongoing
pre-licence costs.
(3) The gain on disposal of $12.1 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) Expenses related to both short-term and low value lease
arrangements are considered to be immaterial for reporting
purposes.
(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 or financial statement preparations is not permitted, as
are various other services that could give rise to conflicts of
interest or other threats to the auditor's objectivity that cannot
be reduced to an acceptable level by applying safeguards.
(6) Other services in 2022 primarily relate to reporting
accountant services provided by EY. In 2021 this also included
services in respect of the merger or other corporate transactions.
The Audit and Risk Committee concluded that shareholder value was
best served by appointing our auditors for this work.
6. Finance income and finance expenses
2022 2021
Finance income $ million $ million
Bank interest 10.2 0.9
Other interest and finance gains(1) 20.0 3.2
IFRS 9 modification impact - 13.9
Lease finance income 1.7 3.2
Finance income on deferred revenue - 1.2
Realised gains on interest rate swaps 6.5 -
Realised gains on foreign exchange forward
contracts 0.5 10.0
Gains on derivatives (2) 38.2 14.5
Foreign exchange gains (3) 202.0 1.9
--------- ---------
Total finance income 279.1 48.8
========= =========
Finance expenses
Interest payable on reserves based lending 71.1 101.6
Interest payable on bond 27.3 5.7
Interest payable on loan notes - 5.6
Other interest and finance expenses(4) 11.7 16.6
Lease interest (note 11) 25.1 22.3
Realised losses on interest rate swaps - 2.4
Losses on derivatives (5) 48.0 14.6
Finance expense on deferred revenue 19.9 -
Foreign exchange losses - 65.2
Bank and financing fees (6) 91.0 63.4
Unwinding of discount on decommissioning
and other provisions (note 12) 65.1 78.0
--------- ---------
359.2 375.4
Finance costs capitalised during the year
(7) (1.0) (0.8)
--------- ---------
Total finance expense 358.2 374.6
========= =========
(1) Other interest and finance gains includes $16.0 million
(2021: $1.9 million) related to an update to the amount recognised
under the decommissioning liability agreement.
(2) Gains on derivatives mainly relates to mark to market gains
on interest rate and foreign currency derivatives.
(3) Significant unrealised foreign exchange gains which consist
mainly of unrealised gains arising from revaluation of open gas
hedges denominated in pound sterling.
(4) Other interest includes an $9.5 million charge (2021: $11.6
million) which represents interest under a financing arrangement
(note 13).
(5) Losses on derivatives relate to changes in the fair value of
an embedded derivative within one of the Group's gas contracts
(2021: $14.6 million).
(6) Bank and financing fees include an amount of $54.9 million
(2021: $38.9 million) relating to the amortisation of arrangement
fees and related costs capitalised against the Group's long-term
borrowings (note 13).
(7) The amount of finance costs capitalised was determined by
applying the weighted average rate of finance costs applicable to
the borrowings of the Group of 4.4 per cent to the expenditures on
the qualifying assets (2021: 3.7 per cent).
7. Income tax
The major components of income tax expense for the years ended
31 December 2022 and 2021 are:
2022 2021
$ million $ million
Current income tax expense
UK corporation tax 671.7 202.2
Overseas tax 53.5 (5.2)
Adjustments in respect of prior years (19.4) (4.9)
Total current income tax expense 705.8 192.1
---------- ----------
Deferred tax expense
UK corporation tax 302.1 7.7
UK Energy Profits Levy 1,469.5 -
Overseas tax (7.5) (10.3)
Adjustments in respect of prior years (16.3) 23.9
Total deferred tax expense 1,747.8 21.3
---------- ----------
Total tax expense reported in the income statement 2,453.6 213.4
========== ==========
The tax credit in the statement of comprehensive
income is
as follows:
Tax credit on cash flow hedges (1,005.6) (1,433.2)
========== ==========
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 2022 and 2021 is, as
follows:
2022 2021
$ million $ million
Profit before income tax 2,461.8 314.5
--------- ---------
At the Group's statutory income tax rate
of 55.0% (2021: 40.0%) 1,354.0 125.8
Effects of:
Expenses/ (income) not deductible/ (taxable)
for tax purposes (11.7) 56.8
Interest not deductible for supplementary
charge and Energy Profits Levy 53.1 13.1
Adjustments in respect of prior years (35.8) 19.0
Movement in unrecognised deferred tax assets (72.2) 27.4
Deferred Energy Profits Levy 1,469.2 -
Impact of different tax rates (190.3) 4.0
Expenses not deductible for Energy Profits
Levy 8.0 -
Energy Profits Levy investment allowance (81.4) -
Investment allowance (39.3) (32.7)
--------- ---------
Total tax expense reported in the consolidated
income statement at the effective tax rate
of 100% (2021: 68%) 2,453.6 213.4
========= =========
The effective tax rate for the year was 100 per cent, compared
to 68 per cent for 2021.
The tax expense/(credit) 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% (2021: 30%), a supplementary charge of 10% (2021: 10%),
and with effect from 26 May 2022, the Energy Profits Levy (EPL) of
25% to give an overall tax rate of 65% (2021: 40%). As the EPL was
introduced part way through the financial year a blended average
rate of 55% has been 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 EPL will increase
to a rate of 35% from 25% with effect from 1 January 2023 and
consequently the headline rate will increase next year to 75%. The
Energy Profits Levy at the 35% rate will be in place until 31 March
2028.
Deferred tax
The principal components of deferred tax are set out in the
following tables:
2022 2021
$ million $ million
Deferred tax assets 1,406.5 1,938.4
Deferred tax liabilities (397.2) (187.1)
---------- ----------
Total deferred tax 1,009.3 1,751.3
========== ==========
The origination of and reversal of temporary differences are, as
shown in the next table, related primarily to movements in the
carrying amounts and tax base values of expenditure and the timing
of when these items are charged and/or credited against accounting
and taxable profit.
7. Income tax (continued)
Deferred tax (continued)
Accelerated Fair value
capital of
allowances Decommissioning Losses derivatives Other Overseas Total
$ million $ million $ million $ million $ million $ million $ million
------------ ----------------- ----------- ------------- ----------- ----------- -----------
As at 1 January
2021 (2,650.5) 1,640.7 - (57.1) 51.5 (16.0) (1,031.4)
Deferred tax
expense 385.9 (178.2) (216.1) 3.6 (26.8) 10.3 (21.3)
Comprehensive
income - - - 1,433.2 - - 1,433.2
Foreign
exchange 13.5 (13.6) - 4.0 (1.1) 1.9 4.7
Additions from
business
combinations
and joint
arrangements (569.0) 564.0 1,530.6 8.4 15.2 (183.1) 1,366.1
As at 31
December 2021 (2,820.1) 2,012.9 1,314.5 1,392.1 38.8 (186.9) 1,751.3
Deferred tax
expense (657.7) (361.7) (745.2) 49.0 (39.7) 7.5 (1,747.8)
Comprehensive
income - - - 1,005.6 1,005.6
Foreign
exchange 82.2 (85.9) (0.2) 5.0 (1.8) 0.9 0.2
------------ ----------------- ----------- ------------- ----------- ----------- -----------
As at 31
December 2022 (3,395.6) 1,565.3 569.1 2,451.7 (2.7) (178.5) 1,009.3
============ ================= =========== ============= =========== =========== ===========
7. Income tax (continued)
The Group's deferred tax assets as at 31 December 2022 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 will increase to a rate of 35% from 25% with effect from
1 January 2023. The increase in rate was substantively enacted on
30 November 2022. The EPL will be 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.
This has resulted in a one-off deferred tax charge to the income
statement of $1,469.2 million and a one-off deferred tax credit
arising on unrealised derivative balances in Other Comprehensive
Income of $1,005.5 million. The net impact on the deferred tax
asset at the end of the period as a result of the EPL is a decrease
in the deferred tax asset of $463.7 million.
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 2022 of approximately $201.7 million (2021: $343.1
million) in respect of ring fence losses, $111.1 million (2021:
$104.4 million) in respect of ring fence investment allowance and
$807.2 million (2021: $741.5 million) in respect of non-ring fence
losses.
The Group also has unrecognised tax losses of approximately
$156.9 million (2021: $212.8 million) in respect of its
international operations. These losses include amounts of $30.3
million which will expire, primarily within 5 years and $13.8
million expiring within 10 years.
The overseas deferred tax relates mainly to temporary
differences associated with fixed asset balances.
No deferred tax liabilities have been provided on unremitted
earnings of overseas subsidiaries, because due to the application
of withholding reliefs under international double taxation treaties
and dividend exemptions under UK and Netherlands legislation no
additional taxation is expected to arise on future
distribution.
Legislation was introduced in UK Finance Act 2021 to increase
the main rate of UK corporation tax for non-ring fence profits from
19 per cent to 25 per cent from 1 April 2023. This change does not
have a material impact on the Group as the UK profits are primarily
subject to the UK ring fence tax rate.
8. Earnings per share (EPS)
Basic EPS is calculated by dividing the profit after tax
attributable to ordinary shareholders of the Group by the weighted
average number of ordinary shares in issue during the year.
Diluted EPS is calculated by dividing the profit after tax
attributable to ordinary shareholders by the weighted average
number of ordinary share in issue during the year plus the weighted
average number of ordinary shares that would be issued on
conversion of all the dilutive potential ordinary shares into
ordinary shares.
The following table reflects the income and share data used in
the basic and diluted EPS calculations:
2022 2021
million million
Earnings for the year ($ millions)
Earnings for the purpose of basic earnings per
share 8.2 101.1
Effect of dilutive potential ordinary shares - -
Earnings for the purpose of diluted earnings
per share 8.2 101.1
======= =======
Number of ordinary shares (millions)
Weighted average number of ordinary shares for
the purpose of
basic earnings per share (1) 899.8 871.2
Dilutive potential ordinary shares (2) 12.3 1.3
Weighted average number of ordinary shares for
the purpose of
diluted earnings per share 912.1 872.5
======= =======
Earnings per share ($ cents)
Basic 0.9 11.6
======= =======
Diluted 0.9 11.6
======= =======
(1) During the current period 78.4 million ordinary shares were
repurchased as part of the share buyback programme.
(2) Excludes certain share options outstanding at 31 December
2022 as their option price was greater than market price.
9. Other intangible assets
Non-oil
and gas Capacity
Oil and assets rights
gas assets (3) (4) Total
$ mi
Cost $ million $ million $ million llion
At 1 January 2021 391.3 94.9 10.3 496.5
Additions during the year 210.0 30.2 - 240.2
Additions from business combinations
and joint arrangements 596.7 0.4 - 597.1
Transfers to property, plant
and equipment (139.5) - - (139.5)
Increase in decommissioning
asset (note 12) 10.4 - - 10.4
Prior capitalised costs expensed - (4.7) - (4.7)
Unsuccessful exploration written-off (255.0) - - (255.0)
Currency translation adjustment (0.5) (1.4) (0.1) (2.0)
------------ ---------- ---------- --------
At 31 December 2021 813.4 119.4 10.2 943.0
Additions during the year 111.0 30.7 - 141.7
Transfers to property, plant
and equipment (29.0) - - (29.0)
Decrease in decommissioning
asset (note 12) (1) (11.8) - - (11.8)
Unsuccessful exploration written-off
(2) (64.4) - - (64.4)
Currency translation adjustment (2.5) (12.5) (1.4) (16.4)
At 31 December 2022 816.7 137.6 8.8 963.1
------------ ---------- ---------- --------
Amortisation
At 1 January 2021 - 34.8 7.6 42.4
Charge for the year - 26.1 1.6 27.7
Currency translation adjustment - (0.7) (0.1) (0.8)
------------ ---------- ---------- --------
At 31 December 2021 - 60.2 9.1 69.3
Charge for the year - 21.1 1.0 22.1
Currency translation adjustment - (7.0) (1.3) (8.3)
At 31 December 2022 - 74.3 8.8 83.1
------------ ---------- ---------- --------
Net book value
At 31 December 2021 813.4 59.2 1.1 873.7
At 31 December 2022 816.7 63.3 - 880.0
============ ========== ========== ========
(1) A decrease to decommissioning assets of $11.8 million (2021:
increase of $10.4 million) was made during the year as a result of
an update to decommissioning estimates (note 12).
(2) The exploration write-off of $64.4 million (2021: $255.0
million), which relates to costs associated with licence
relinquishments and uncommercial well evaluations, is net of a $5.7
million credit related to a decrease in decommissioning provisions
in the North Sea (note 12) and a $7.0 million credit related to a
change to the decommissioning estimate in the Falkland Islands
business unit (2021: $6.3 million relating to the effect of changes
in decommissioning provisions on oil and gas intangible assets
previously written-off).
(3) Non-oil and gas assets relate primarily to Group IT
software.
(4) The capacity rights represent National Transmission System
(NTS) entry capacity at Bacton and Teesside acquired as part of the
business combination completed in 2017. These rights, which have
been amortised on a contracted volume basis, are now fully
amortised.
10. Property, plant and equipment
Fixtures
and fittings
Oil and & office
gas assets equipment Total
Cost $ million $ million $ million
At 1 January 2021 9,996.0 22.8 10,018.8
Additions during the year 464.5 4.4 468.9
Additions from business combinations
and joint arrangements 1,814.3 4.2 1,818.5
Transfers from intangible assets 139.5 - 139.5
Disposals - (0.3) (0.3)
Decrease in decommissioning
asset (note 12) (357.8) - (357.8)
Currency translation adjustment (34.5) (0.3) (34.8)
------------ -------------- ----------
At 31 December 2021 12,022.0 30.8 12,052.8
Additions (1) 532.4 10.7 543.1
Transfers from intangible assets 29.0 - 29.0
Decrease in decommissioning
asset (note 12) (2) (778.8) - (778.8)
Currency translation adjustment (369.0) (3.2) (372.2)
At 31 December 2022 11,435.6 38.3 11,473.9
------------ -------------- ----------
Accumulated depreciation
At 1 January 2021 3,480.2 16.2 3,496.4
Charge for the year 1,204.1 5.5 1,209.6
Impairment 117.2 - 117.2
Disposals - (0.1) (0.1)
Currency translation adjustment (16.6) (0.4) (17.0)
------------ -------------- ----------
At 31 December 2021 4,784.9 21.2 4,806.1
Charge for the year 1,318.4 5.4 1,323.8
Net impairment reversal (3) (169.6) - (169.6)
Currency translation adjustment (174.4) (2.2) (176.6)
At 31 December 2022 5,759.3 24.4 5,783.7
------------ -------------- ----------
Net book value:
At 31 December 2021 7,237.1 9.6 7,246.7
============ ============== ==========
At 31 December 2022 5,676.3 13.9 5,690.2
============ ============== ==========
Included within property, plant and equipment additions of
$543.1 million (2021: $468.9 million) are associated cash flows of
$476.5 million (2021: $437.4 million) and non-cash flow movements
of $66.6 million (2021: ($31.5 million)), represented by a $44.2
million increase in capital accruals (2021: $9.0 million increase)
and $22.4 million of capitalised lease depreciation (2021: $22.5
million).
A decrease in the decommissioning assets of $778.8 million
(2021: $357.8 million) was made during the year as a result of both
new obligations and an update to the decommissioning estimates
(note 12).
During the year, the Group recognised a net pre-tax impairment
credit of $169.6 million (post-tax $49.8 million) (2021: impairment
charge of $117.2 million; post-tax $70.3 million) comprising a
pre-tax impairment reversal of $250.5 million (2021: $ nil) and a
pre-tax impairment credit of $82.3 million (2021: $8.5 million
charge) in respect of revisions to decommissioning estimates on the
Group's non-producing assets with no remaining net book value (see
note 12). This is net of a pre-tax impairment charge representing a
write-down of property, plant and equipment assets of $163.2
million (2021: $108.7 million).
The impairment reversal was driven by a higher forward curve and
long term price assumption for gas resulting in reversals of $250.5
million covering two cash generating groups in the North Sea
business unit.
The impairment to property, plant and equipment of $163.2
million, arises primarily from a single CGU in the UK North Sea,
driven primarily due to the contracted price realised for crude
sales being negatively impacted by the pricing differential between
Urals and Brent crude, which is currently subject to dispute with
the buyer, and also a revised operating cost profile for the field.
Impairments on property, plant and equipment are reversible in the
future.
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 14). 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
2026, thereafter inflated at 2.5 per cent per annum. The long-term
commodity prices used were $65 per barrel for crude and 65p per
therm for gas.
Production volumes - 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 expenditure 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. Decreases to the long-term oil
and gas prices from 1 January 2026 specified above would result in
a further post-tax impairment of $44.9 million. A 10 per cent
increase in the long-term oil and gas price deck would reduce the
post-tax impairment charge by $44.9 million. 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 post-tax
impairment of $17.6 million, and a one per cent decrease in the
post-tax discount rate would reduce the post-tax impairment charge
by $19.1 million.
Sensitivity analyses indicate that reductions or increases in
the long-term oil and gas prices of 10 per cent or a one per cent
increase or decrease in the post-tax discount rate would not have
resulted in a different impairment reversal.
11. Leases
This note provides information for leases where the Group is a
lessee.
Balance sheet
Right-of-use assets
Land Drilling Offshore
and buildings rigs FPSO facilities Equipment Total
Cost $ million $ million $ million $ million $ million $ million
At 1 January 2021 66.0 129.9 - - 3.2 199.1
Additions during the
year - 29.0 - - 15.6 44.6
Additions from business
combinations and joint
arrangements 41.1 - 525.6 - 1.2 567.9
Cost revisions/remeasurements - (3.7) (15.7) - (1.3) (20.7)
Disposals (5.4) - - - - (5.4)
Currency translation
adjustment (1.4) (2.5) - - (0.5) (4.4)
--------------- ---------- ---------- ------------ ---------- ----------
At 31 December 2021 100.3 152.7 509.9 - 18.2 781.1
Additions during the
year (1) - - - 338.0 - 338.0
Cost revisions/remeasurements 3.3 33.6 52.7 (3.8) 3.4 89.2
Disposals (6.6) - - - - (6.6)
Currency translation
adjustment (9.6) (17.4) - - (1.6) (28.6)
At 31 December 2022 87.4 168.9 562.6 334.2 20.0 1,173.1
--------------- ---------- ---------- ------------ ---------- ----------
Accumulated depreciation
At 1 January 2021 11.0 54.3 - - 1.6 66.9
Charge for the year 11.6 44.8 102.1 - 5.9 164.4
Currency translation
adjustment (0.3) (1.3) - - (0.1) (1.7)
--------------- ---------- ---------- ------------ ---------- ----------
At 31 December 2021 22.3 97.8 102.1 - 7.4 229.6
Charge for the year 11.8 42.5 107.4 61.1 7.0 229.8
Disposals (6.4) - - - - (6.4)
Currency translation
adjustment (1.8) (11.8) - - (1.0) (14.6)
At 31 December 2022 25.9 128.5 209.5 61.1 13.4 438.4
--------------- ---------- ---------- ------------ ---------- ----------
Net book value
At 31 December 2021 78.0 54.9 407.8 - 10.8 551.5
At 31 December 2022 61.5 40.4 353.1 273.1 6.6 734.7
=============== ========== ========== ============ ========== ==========
(1) Additions of $338.0 million related to the Tolmount offshore
facilities were made to the right-of-use assets during the year
(2021: total additions of $612.5 million arose primarily from
business combinations of $567.9 million) and $42.7 million from a
new drilling rig contract.
Right-of-use liabilities 2022 2021
$ million $ million
At 1 January 654.3 140.9
Additions 338.0 42.7
Additions from business combinations and joint
arrangements - 637.8
Re-measurement 88.9 (5.0)
Finance costs charged to income statement (note
6) 25.1 22.3
Finance costs charged to decommissioning provision
(note 12) 0.6 0.7
Disposals (0.4) (5.1)
Lease payments (254.0) (160.4)
Currency translation adjustment (27.9) (19.6)
--------- ---------
At 31 December 824.6 654.3
========= =========
Classified as:
Current 220.8 165.1
Non-current 603.8 489.2
--------- ---------
Total lease liabilities 824.6 654.3
========= =========
The significant portion of the Group's lease liabilities
represent lease arrangements for FPSO vessels on the Catcher and
Chim Sáo assets, 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 2022 2021
$ million $ million
Land and buildings - non-oil and gas assets 10.8 10.5
Land and buildings - oil and gas assets 1.0 1.1
Drilling rigs 42.5 44.8
Offshore facilities 61.1 -
FPSO 107.4 102.1
Equipment - non oil and gas assets 0.4 -
Equipment - oil and gas assets 6.6 5.9
--------- ---------
229.8 164.4
Capitalisation of IFRS 16 lease depreciation
(1)
Drilling rigs (25.9) (27.2)
Equipment (4.0) (3.5)
Depreciation charge included within consolidated
income statement 199.9 133.7
========= =========
(1) Of the $29.9 million (2021: $30.7 million) capitalised IFRS
16 lease depreciation, $22.4 million (2021: $22.5 million) has been
capitalised within property, plant and equipment and $7.5 million
(2021: $8.2 million) within provisions (note 12).
2022 2021
$ million $ million
Lease interest (included in Finance expenses
- note 6) 25.1 22.3
========== ==========
The total cash outflow for leases in 2022 was $254.0 million
(2021: $160.4 million).
12. Provisions
Decommissioning
provision Other Total
$ million $ million $ million
At 1 January 2021 4,197.1 13.9 4,211.0
Additions 17.1 1.0 18.1
Additions from business combinations
and joint arrangements 1,683.0 34.5 1,717.5
Changes in estimates - decrease
to oil and gas tangible decommissioning
assets (381.0) - (381.0)
Changes in estimates - increase
to oil and gas intangible decommissioning
assets 14.3 - 14.3
Changes in estimate - credit to
income statement - (2.3) (2.3)
Changes in estimate on oil and
gas tangible assets
- debit to income statement 8.5 - 8.5
Changes in estimate on oil and
gas intangible assets - credit
to income statement (6.3) - (6.3)
Amounts used (225.9) (9.2) (235.1)
Interest on decommissioning lease (0.7) - (0.7)
Depreciation, depletion & amortisation
on decommissioning right-of-use
leased asset (8.2) - (8.2)
Release of royalty provision - (10.2) (10.2)
Unwinding of discount 78.0 - 78.0
Currency translation adjustment (22.2) (0.2) (22.4)
--------- --------- ---------
At 31 December 2021 5,353.7 27.5 5,381.2
Additions 24.4 - 24.4
Changes in estimates - decrease
to oil and gas tangible decommissioning
assets (720.9) - (720.9)
Changes in estimates - decrease
to oil and gas intangible decommissioning
assets (6.1) - (6.1)
Changes in estimate - credit to
income statement - (1.2) (1.2)
Changes in estimate on oil and
gas tangible assets
- credit to income statement (82.3) - (82.3)
Changes in estimate on oil and
gas intangible assets - credit
to income statement (5.7) - (5.7)
Amounts used (222.6) (2.3) (224.9)
Disposal (9.0) - (9.0)
Interest on decommissioning lease (0.6) - (0.6)
Depreciation, depletion & amortisation
on decommissioning right-of-use
leased asset (7.5) - (7.5)
Unwinding of discount 65.1 - 65.1
Currency translation adjustment (247.2) - (247.2)
At 31 December 2022 4,141.3 24.0 4,165.3
========= ========= =========
Classified within:
Non-current Current
liabilities liabilities Total
$ million $ million $ million
At 31 December 2021 5,022.6 358.6 5,381.2
============= ============= ==========
At 31 December 2022 3,933.7 231.6 4,165.3
============= ============= ==========
Decommissioning provision
All of the $24.4 million decommissioning provision additions
relate to oil and gas tangible assets (2021: $14.7 million related
to oil and gas tangible assets, and $2.4 million related to oil and
gas intangible assets.
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 (2021: 2.0 per cent per annum)
and discounted at a risk-free rate of between 3.5 per cent and 3.7
per cent (2021: 0.9 per cent and 1.8 per cent) reflecting a 6-month
(2021: 24-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 $23.5 million (2021: $25.3 million), where the Group
operates a service, severance and compensation pay scheme under a
collective labour agreement with the local workforce. Other
provisions at 31 December 2021 also included a $2.3 million onerous
contract provision in respect of the termination cost of the rig
which had been operating on the Schiehallion field, which has now
been fully settled. The onerous contract had no impact on the
income statement in the year.
13. Borrowings and facilities
The Group's borrowings are carried at amortised cost:
2022 2021
$ million $ million
Reserves based lending (RBL)
facility 702.3 2,312.0
Bond 491.3 489.5
Exploration finance facility
(EFF) 10.5 44.6
Other loans 34.0 39.9
--------- ---------
Total borrowings 1,238.1 2,886.0
========= =========
Classified within
Non-current liabilities 1,216.6 2,823.7
Current liabilities 21.5 62.3
--------- ---------
Total borrowings 1,238.1 2,886.0
========= =========
Interest of $6.2 million (2021: $17.4 million) on the RBL, bond
and EFF had accrued by the balance sheet date and has been
classified within accruals.
The key terms of the RBL facility are:
-- term matures 23 November 2027.
-- facility size of $4.1 billion (with $0.75 billion accordion
option).
-- debt availability currently at $2.75 billion.
-- debt availability to be redetermined on an annual basis
-- interest at USD LIBOR plus a margin of 3.25 per cent, rising
to a margin of 3.5 per cent from November 2025
-- a margin adjustment linked to carbon-emission reductions
-- liquidity and leverage covenant tests
-- a syndication group of 19 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 has a tenor of five years to maturity. The coupon was set
at 5.50 per cent and interest is payable semi-annually.
Since 2019, the Group has been operating within an exploration
finance facility, currently for NOK 1 billion, in relation to
part-financing the exploration activities of Harbour Energy Norge
AS. At the balance sheet date, the amount drawn down on the
facility was NOK 104 million/$10.5 million (2021: NOK 396
million/$44.9 million).
During the year $54.9 million (2021: $38.9 million) of
arrangement fees and related costs have been amortised and are
included within financing costs. 2021 also included a $13.9 million
modification gain following a maturity extension of the RBL debt
prior to the completion of the merger in March 2021.
At 31 December 2022, $81.5 million of arrangement fees and
related costs remain capitalised (2021: $136.4 million), of which
$20.2 million are due to be amortised within the next 12 months
(2021: $43.6 million).
At the balance sheet date, the outstanding RBL balance excluding
incremental arrangement fees and related costs was $775.0 million
(2021: $2,437.5 million). As at 31 December 2022, $1,972.0 million
remained available for drawdown under the RBL facility (2021: $884
million). The Group has facilities to issue up to $1.5 billion of
letters of credit, of which $966 million was in issue as at 31
December (2021: $796 million), mainly in respect of future
abandonment liabilities.
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, in addition to three
annual instalments of $9.0 million commencing on 1 December 2024,
if required.
The table below details the change in the carrying amount of the
Group's borrowings arising from financing cash flow.
$ million
Total borrowings as at 1 January 2021 2,161.4
Repayment of RBL (697.5)
Repayment of junior debt (400.0)
Short-term debt arising on business combination (2,219.3)
Repayment of debt - equity allocation to
borrowings 942.8
Repayment of debt - cash allocation to
borrowings 1,276.5
Conversion of D loan notes to equity (134.7)
IFRS 9 modification gain (13.9)
Repayment of financing arrangement (9.3)
Repayment of EFF loan (14.7)
Proceeds from drawdown of borrowing facilities 1,617.5
Proceeds from EFF loan 45.9
Proceeds from issue of bond 500.0
Loan notes redemption (135.7)
Arrangement fees and related costs on RBL
paid and capitalised (77.2)
Arrangement fees and related costs on bond
capitalised (10.9)
Arrangement fees and related costs on EFF
loan capitalised (0.4)
Currency translation adjustment on EFF
loan (0.6)
Loan notes interest capitalised 5.6
Financing arrangement interest payable 11.6
Amortisation of arrangement fees and related
costs 38.9
----------
Total borrowings as at 31 December 2021 2,886.0
Repayment of RBL (1,662.5)
Repayment of financing arrangement (15.4)
Repayment of EFF loan (38.6)
Proceeds from EFF loan 11.5
Currency translation adjustment on EFF
loan (7.3)
Financing arrangement interest payable 9.5
Amortisation of arrangement fees and related
costs 54.9
----------
Total borrowings as at 31 December 2022 1,238.1
==========
14. Other financial assets and liabilities
The Group held the following financial instruments at fair value
at 31 December 2022. 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 is level 3 in the IFRS 13 hierarchy.
31 December 2021
31 December 2022 restated
Assets Liabilities Assets Liabilities
Current $ million $ million $ million $ million
Measured at fair value through
profit and loss
Foreign exchange derivatives 6.0 (0.1) 0.9 (2.2)
Interest rate derivatives 24.3 - 3.3 -
Fair value of embedded derivative
within gas contract - (57.0) - (11.5)
Carbon swaps - - 36.6 (15.6)
------------ -------------- ---------- ------------
30.3 (57.1) 40.8 (29.3)
Measured at fair value through
other comprehensive income
Commodity derivatives 50.5 (2,114.4) 1.0 (2,135.2)
50.5 (2,114.4) 1.0 (2,135.2)
Total current 80.8 (2,171.5) 41.8 (2,164.5)
------------ -------------- ---------- ------------
Non-current
Measured at fair value through
profit and loss
Interest rate derivatives 18.2 - 8.3 -
------------ -------------- ---------- ------------
18.2 - 8.3 -
Measured at fair value through
other comprehensive income
Commodity derivatives 84.5 (1,279.1) 1.8 (1,373.6)
84.5 (1,279.1) 1.8 (1,373.6)
------------ -------------- ---------- ------------
Total non-current 102.7 (1,279.1) 10.1 (1,373.6)
------------ -------------- ---------- ------------
Total current and non-current 183.5 (3,450.6) 51.9 (3,538.1)
============ ============== ========== ============
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 Level Level Level
2 3 2 3
As at 31 December 2022 $ million $ million $ million $ million
Fair value of embedded derivative
within gas contract - - (57.0) -
Commodity derivatives 135.0 - (3,393.5) -
Foreign exchange derivatives 6.0 - (0.1) -
Carbon swaps - - - -
Interest rate derivatives 42.5 - - -
Total fair value 183.5 - (3,450.6) -
=========== =========== =============== ==============
Financial assets Financial liabilities
Level Level Level Level
2 3 2 3
As at 31 December 2021 as
restated $ million $ million $ million $ million
Fair value of embedded derivative
within gas contract - - (11.5) -
Commodity derivatives 2.8 - (3,508.8) -
Foreign exchange derivatives 0.9 - (2.2) -
Carbon swaps 36.6 - (15.6) -
Interest rate derivatives 11.6 - - -
Total fair value 51.9 - (3,538.1) -
=========== =========== =============== ==============
There were no transfers between fair value levels in the year.
The movements in the year associated with financial assets and
liabilities measured in accordance with level 3 of the fair value
hierarchy are shown below:
Financial assets Financial liabilities
2022 2021 2022 2021
Level 3 $ million $ million $ million $ million
Fair value as at 1 January - 9.7 - -
Additions from business combinations
and joint arrangements - (10.2) - (4.2)
Gains and (losses) recognised
in the income statement - 0.5 - 4.2
Fair value as at 31 December - - - -
========= ========= ===================== =========
Fair value movements recognised in the income statement on
financial instruments are shown below.
2022 2021
$ $
million million
Income included in the income statement
Warrants - 4.2
Remeasurement of royalty valuation - 0.5
- 4.7
========= =========
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.
2022 2021
Book value Fair value Book value Fair value
$ million $ million $ million $ million
Bond (491.3) (446.4) (489.5) (483.0)
========== ========== ========== ==========
The fair value of the bond is within level 2 of the fair value
hierarchy and has been estimated by discounting future cash flows
by the relevant market yield curve at the balance sheet date. The
fair values of other financial instruments not measured at fair
value including cash and short-term deposits, trade receivables,
trade payables and floating rate borrowings equate approximately to
their carrying amounts.
Cash flow hedge accounting
The Group uses a combination of fixed price physical sales
contracts and cash-settled fixed price commodity swaps and options
to manage the price risk associated with its underlying oil and gas
revenues. As at 31 December 2022, 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 2022 2023 2024 2025 2026
Oil volume hedged (thousand bbls) 10,950 7,320 2,373 -
------- ------ ------ -----
Weighted average hedged price ($/bbl) 74.08 84.37 81.22 -
------- ------ ------ -----
Gas volume hedged (million therms) 1,339 652 113 -
------- ------ ------ -----
Weighted average hedged price (p/therm) 41.46 68.85 75.22 -
------- ------ ------ -----
As at 31 December 2022, 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 $3,516.7 million (2021: $3,868.2 million) and net
unrealised pre-tax losses of $3,184.6 million (2021: $3,454.2
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 2022, net deferred pre-tax losses of
$2,367.9 million (2021: $2,495.9 million) are expected to be
released to the income statement within one year.
Interest Rate Benchmark Reform (IBOR)
From 1 January 2022, publication of most LIBOR settings ended
(including Sterling LIBOR). All IBORs were replaced with
alternative reference rates with the exception of US LIBOR.
After 30 June 2023 US LIBOR will cease publication and will be
replaced by SOFR (Secured overnight financing rate). The Group has
variable rate RBL borrowings that currently reference US LIBOR,
which are partially hedged by interest rate swaps that are also
linked to US LIBOR. The RBL agreement has an automatic trigger to
transition to SOFR after 30 June 2023, and a similar arrangement
has been agreed in principle with the interest rate swap
counterparties to reduce any future impact on the financial
statements after transition.
The following table shows the financial instruments held by the
Group as at 31 December 2022 which are referenced to US LIBOR that
will transition to SOFR by 30 June 2023.
RBL borrowings financial liabilities Nominal value ($ millions)
USD 1M LIBOR 475.0
USD 6M LIBOR 300.0
775.0
Derivatives
Interest rate swaps USD 6M LIBOR 544.6
The nominal values in the table above also represent the
carrying values net of unamortised deferred fees of the RBL as at
31 December 2022.
15. Notes to the statement of cash flows
Net cash flows from operating activities consist of:
2022 2021
$ million $ million
Profit before taxation 2,461.8 314.5
Adjustments to reconcile profit before tax
to net cash flows:
Finance cost, excluding foreign exchange 358.2 309.4
Finance income, excluding foreign exchange (77.1) (48.8)
Depreciation, depletion and amortisation 1,545.8 1,371.0
Fair value movement in unrealised carbon
swaps 2.6 -
Net impairment of property, plant and equipment (169.6) 117.2
Taxes paid (551.5) (279.8)
Share based payments 16.5 8.4
Decommissioning payments (217.0) (244.8)
Onerous contract provision - (2.3)
Exploration costs written-off 64.4 255.0
Write-off of non-oil and gas assets - 4.7
Pre-merger costs - 7.0
Onerous contract payments (2.3) (9.2)
Increase in royalty consideration receivable - (0.5)
(Gain)/loss on termination of IFRS 16 lease (0.2) 0.3
(Gain)/loss on disposal (12.1) 0.1
Movement in realised cash flow hedges not
yet settled (104.3) 361.6
Unrealised foreign exchange (gain)/loss (237.9) 57.3
Working capital adjustments:
Decrease/(increase) in inventories 65.0 (13.0)
Increase in trade and other receivables (75.7) (607.4)
Increase in trade and other payables 63.2 13.5
Net cash inflow from operating activities 3,129.8 1,614.2
========= =========
Reconciliation of net cash flow to movement in net
borrowings
2022 2021
$ million $ million
Proceeds from drawdown of borrowing facilities - (1,617.5)
Proceeds from issue of bond - (500.0)
Short-term debt arising on business combination - 2,219.3
Repayment of debt - equity allocation to
borrowings - (942.8)
Repayment of debt - cash allocation to borrowings - (1,276.5)
Conversion of D loan notes to equity - 134.7
Proceeds from EFF loan (11.5) (45.9)
Repayment of RBL facility 1,662.5 697.5
Repayment of junior debt - 400.0
Loan notes redemption - 135.7
IFRS 9 modification gain - 13.9
Repayment of EFF loan 38.6 14.7
Repayment of financing arrangement 15.4 9.3
Arrangement fees and related costs capitalised - 88.5
Financing arrangement interest payable (9.5) (11.6)
Amortisation of arrangement fees and related
costs capitalised (54.9) (38.9)
Currency translation adjustment on EFF loan 7.3 0.6
Loan notes interest capitalised - (5.6)
--------- ---------
Movement in total borrowings 1,647.9 (724.6)
Movement in cash and cash equivalents (199.0) 253.3
--------- ---------
Decrease/(increase) in net borrowings in
the year 1,448.9 (471.3)
Opening net borrowings (2,187.3) (1,716.0)
Closing net borrowings (738.4) (2,187.3)
========= =========
Analysis of net borrowings
2022 2021
$ million $ million
Cash and cash equivalents 499.7 698.7
RBL facility (702.3) (2,312.0)
Bond (491.3) (489.5)
EFF loan (10.5) (44.6)
--------- ---------
Net debt (704.4) (2,147.4)
Financing arrangement (34.0) (39.9)
Closing net borrowings (738.4) (2,187.3)
========= =========
16. Related party disclosures
Transactions between the Company and its subsidiaries, which are
related parties, have been eliminated on consolidation and are not
disclosed in this note.
In late 2021, the Company agreed a secondment agreement with EIG
to second two employees, familiar with Harbour's business and
assets, to provide additional support and expertise for Harbour for
an initial period of six months from 1 December 2021. The
secondment agreement provided that the secondees would work for
Harbour on a substantially full-time basis which could be
terminated or extended with the agreement of the parties. In May
2022, the Company and EIG agreed to terminate the agreement for one
secondee and to extend the second for a further period which was
subsequently terminated before the end of the year.
Harbour Energy's Viking CCS (formerly V Net Zero), the CO(2)
capture, transport and storage network, 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 recently begun
the necessary engineering design to connect West Burton B to the
high-capacity Viking CCS storage sites located deep beneath the
Southern North Sea.
Compensation of key management personnel of the Group
Remuneration of key management personnel, including Directors of
the Group, is shown below.
2021
2022 (1)
$ $
million million
Salaries and short-term employee benefits 14.6 18.6
Payments made in lieu of pension contributions 0.8 0.7
Termination benefits 0.4 -
Pension benefits - -
15.8 19.3
========= =========
(1) 2021 data includes remuneration of key management personnel
for the Chrysaor Holdings Group in the three months to 31 March
2021.
17. Distributions made and proposed
A final dividend of 11 cents per ordinary share in relation to
the year ended 31 December 2021 was paid on 18 May 2022 pursuant to
shareholder approval received on 11 May 2022.
Pursuant to shareholder approval received on 11 May 2022 an
interim dividend of 11 cents per ordinary share in relation to the
half year ended 30 June 2022 was paid on 19 October 2022.
2022 2021
$ million $ million
Cash d ividends on ordinary shares declared
and paid:
Final dividend for 2021: 11 cents per share
(2020: no dividend) 98.3 -
Interim dividend for 2022: 11 cents per
share 93.2 -
191.5 -
========= =========
Proposed dividends on ordinary shares:
Final dividend for 2022: 12 cents per share
(2021: 11 cents per share) 100.0 -
========= =========
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.
18. Events after the reporting period
On 14 February 2023, the Scheme's trustee effected a bulk
annuity 'buy in' policy with Just Retirement Limited. This policy
secures the benefits of all the Scheme's members and eliminates
mortality and investment risk from the Company's balance sheet.
This decision was made principally in light of the substantial
improvement to the Scheme's funded status over 2022 and the
favourable market conditions for such transactions. The Company was
not required to pay any additional contributions to the Scheme in
respect of the annuity purchase.
Glossary
-- 2C Best estimate of contingent resources
-- 2P Proven and probable reserves
-- AGM Annual general meeting
-- bbl Barrel
-- boe Barrel of oil equivalent
-- CCS Carbon capture and storage
-- CGU Cash generating unit
-- Chrysaor Chrysaor Holdings Limited and subsidiaries
-- 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
-- ESG Environmental, social and governance
-- EUA European Union Allowance
-- FEED Front End Engineering & Design
-- FPSO Floating production storage offtake vessel
-- FVLCD Fair value less cost of disposal
-- GHG Greenhouse gas emissions
-- IAS International Accounting Standards
-- IEA International Energy Agency
-- IFRSs International Financial Reporting Standards
-- kboepd Thousand of barrels of oil equivalent per day
-- kgCO(2) e Kilograms of carbon dioxide equivalent
-- LIBOR London inter-bank offered rate
-- mmboe Million barrels of oil equivalent
-- mscf Thousand standard cubic feet
-- mt Million tonnes
-- mtpa Million tonnes per annum
-- NBP Natural gas prices
-- NGFS Network for Greening the Financial System
-- NOK Norwegian krone
-- NTS National Transmission System
-- PP&E Property, plant and equipment
-- Premier Premier Oil plc and subsidiaries
-- RBL Reserves based lending
-- SOFR Secured Overnight Financing Rate
-- Tcf Trillion cubic feet
-- Therm Unit of UK natural gas
-- WACC Weighted average cost of capital
-- USD US dollar
Non-IFRS measures
Harbour uses certain measures of performance that are not
specifically defined under IFRS or other generally accepted
accounting principles (GAAP). These non-IFRS measures, which are
presented within the Financial review, are defined below:
-- Capital investment : Depicts how much the Group has spent on
purchasing fixed assets in order to further its business goals and
objectives. It is a useful indicator of the Group's organic
expenditure on oil and gas assets, and exploration and appraisal
assets, incurred during a period.
-- DD&A per barrel : Depreciation and amortisation of oil
and gas properties for the period divided by working interest
production. This is a useful indicator of ongoing rates of
depreciation and amortisation of the Group's producing assets.
-- EBITDAX : Earnings before tax, interest, depreciation and
amortisation, impairments, remeasurements, onerous contracts and
exploration expenditure. This is a useful indicator of underlying
business performance.
-- Free cash flow : Operating cash flow less cash flow from
investing activities less interest and lease payments.
-- GHG intensity: Reported on a gross operated basis and excluding offsets.
-- Leverage ratio: Net debt/ last twelve months EBITDAX.
-- Liquidity: The sum of cash and cash equivalents on the
balance sheet and the undrawn amounts available to the Group on our
principal facilities. This is a key measure of the Group's
financial flexibility and ability to fund day-to-day
operations.
-- Net debt : Total reserves based lending facility, bond and
Exploration financing facility (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 .
-- Total capital expenditure: Capital investment 'additions' per
notes 9 and 10 plus decommissioning expenditure 'amounts used' per
note 12
Group reserves and resources
Oil and gas 2P reserves and 2C resources
North Sea(1) International(1) Total(1)
Oil, Oil, Oil,
NGLs Gas Total NGLs Gas Total NGLs Gas Total
------- ------ --------- ------- ----- ----------- ------- ------ ---------
mmbbls bcf mmboe(2) mmbbls bcf mmboe(2) mmbbls bcf mmboe(2)
------- ------ --------- ------- ----- ----------- ------- ------ ---------
2P reserves (working interest)
1 January 2022 232 1,208 461 11 85 27 243 1,293 488
------- ------ --------- ------- ----- ----------- ------- ------ ---------
Revisions(3) 17 (89) 1 (1) (10) (3) 16 (99) (2)
------- ------ --------- ------- ----- ----------- ------- ------ ---------
Production (36) (183) (71) (1) (18) (5) (38) (202) (76)
------- ------ --------- ------- ----- ----------- ------- ------ ---------
31 December
2022 213 936 390 9 57 19 221 993 410
------- ------ --------- ------- ----- ----------- ------- ------ ---------
2P reserves (entitlement)(4)
31 December
2022 213 936 390 7 44 15 220 980 405
------- ------ --------- ------- ----- ----------- ------- ------ ---------
2C resources (working interest)
1 January 2022 220 516 309 116 208 151 336 724 460
------- ------ --------- ------- ----- ----------- ------- ------ ---------
Revisions,
additions,
relinquishments(5) (78) (155) (105) 21 449 99 (57) 295 (5)
------- ------ --------- ------- ----- ----------- ------- ------ ---------
31 December
2022 142 361 204 137 657 250 279 1,019 455
------- ------ --------- ------- ----- ----------- ------- ------ ---------
Notes:
1. North Sea consists of the UK and Norway. International
consists of Indonesia, Vietnam and Mexico. 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 2022 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 2022
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.
2. 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.
3. 2P reserves revisions are accounted for by a downward
revision of the Group's estimate of the Tolmount field 2P reserves
based on the production performance of the field, partially offset
by the sanction of further activity, including the Talbot field
development and for a further well in the Greater Britannia
Area.
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. Movement in 2C resource reflects the addition of the Timpan
gas discovery in Indonesia, offset by the movement of some volumes
to 2P reserves, some revisions and some UK licence
relinquishments.
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 405 mmboe as at 31
December 2022.
Because of rounding, some totals may not agree exactly with the
sum of their component parts.
CO(2) storage capacity
31 December 2022 31 December 2021
2C resources (million 300 -
tonnes)(1)
----------------- -----------------
1. Volumes reflect internal estimates. Harbour commissioned ERCE
to complete a Competent Person's Report of the Storage Capacity of
the Viking CCS project to the Society of Petroleum Engineers (SPE)
Storage Resources Management System (SRMS) standard, and to audit
Harbour's 2C storage resource estimate. This audit process has
confirmed Harbour's estimate of 300 million tonnes of 2C storage
resource for the Viking CCS project is fair and reasonable.
[1] 2021 GHG intensity has been restated in line with our
emissions reporting boundaries which were updated in 2022.
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END
FR MZGGFGLKGFZG
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March 09, 2023 02:00 ET (07:00 GMT)
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