REG - Hurricane Energy PLC - Full-year Results 2022
26/05/2023 07:00
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RNS Number : 7402A Hurricane Energy PLC 26 May 2023
26 May 2023
Hurricane Energy plc
("Hurricane", the "Company", or the "Group")
Full-year Results 2022
Hurricane Energy plc, the UK based oil and gas company, announces its
full-year results for the period ended 31 December 2022.
Highlights
Financial results
· Revenues of $310.8 million from six liftings of Lancaster crude
(2021: $240.5 million from seven liftings)
· Cash production costs of $37.4/bbl (2021: $28.2/bbl)
· Generated $175.9 million of free cash flow†, equivalent
to $56.9/bbl (2021: $135.7 million, $36.2bbl)
· Profit after tax for the period of $108.7 million (2021: $18.2
million)
· Net free cash† of $121.4 million (31 December 2021: $51.5
million)
· Full bond repayment made in July 2022 of outstanding Convertible
Bonds leaving the Company debt free
Operations
· Production within guidance with average daily rate of 8,500 bopd
(2021: 10,300 bopd)
· Excellent operational uptime of 97%, covering planned and unplanned
events
· Crude oil sales of 3.2 Mbbls sold across six cargoes in 2022
· Agreement reached in March 2022 with Bluewater for an extension to
the Bareboat Charter for the Aoka Mizu FPSO
· Following technical reassessment, the Greater Warwick Area (GWA) was
relinquished in July 2022 by the GWA Joint Venture
Corporate
· In February 2022, Philip Wolfe took over from John Wright as
Chairman, followed by Juan Morera being appointed as a shareholder nominated
Non-Executive Director in March 2022
· In May and July 2022, Linda Beal and Robin Allan respectively were
appointed to the board as Independent Non-Executive Directors
· In November 2022, following receipt of an unsolicited bid for the
Company valuing each share at 7.7p which the Board concluded should not be
recommended to shareholders, the Company launched a Formal Sale Process , the
results of which were announced post period
Post Period
· In March, following the FSP process, the Board recommended an
acquisition of the entire issued, and to be issued, share capital of the
Company by Prax Exploration & Production PLC, to be effected by means of a
Scheme of Arrangement under Part 26 of the Companies Act 2006 (the Scheme),
valuing each share at up to 12.5 pence in total
· Shareholder and applicable regulatory approvals for the recommended
acquisition were received in May 2023
· The Court Sanction Hearing to consider the Scheme is scheduled for 7
June 2023. The Scheme remains subject to certain other conditions, including
sanction by the Court at the Court Sanction Hearing and the delivery of a copy
of the Court Order to the Registrar of Companies. Subject to the Scheme
receiving the sanction of the Court, the delivery of a copy of the Court Order
to the Registrar of Companies and the satisfaction (or, where applicable, the
waiver) of the other Conditions set out in Part III of the Scheme Document,
the Scheme is expected to become effective on 8 June 2023.
Antony Maris, CEO of Hurricane, commented:
"2022 has been both very challenging and a highly successful year for
Hurricane, whilst also an extraordinarily volatile period for our sector.
During the year, the importance of domestic energy security was exacerbated by
the terrible events in Ukraine and by the subsequent concerns over energy
supplies across Europe resulting in surging commodity prices.
The resulting high oil price early in the year, combined with outstanding
operational performance at the Company's Lancaster field, significantly
strengthened Hurricane's finances. Alongside this, working closely with our
FPSO operator, we delivered superb uptime performance and produced towards the
upper end of our annual production guidance. The field has now produced more
than 15 million barrels.
The delivery of a technically skilled and commercially efficient, debt-free
Company enhanced our industry reputation and attracted outside investor
interest.
All this is a great credit to the team's ability and commitment which, given
the challenges of the last few years in particular, have delivered full value
and a great return for Shareholders."
†Designates a non-IFRS measure. See Appendix B to this announcement for
definition and reconciliation to nearest equivalent statutory IFRS measures.
Contacts:
Hurricane Energy plc +44 (0)1483 862 820
Antony Maris, Chief Executive Officer
communications@hurricaneenergy.com (mailto:communications@hurricaneenergy.com)
Stifel Nicolaus Europe Limited +44 (0)20 7710 7600
Nominated Adviser & Joint Corporate Broker
Callum Stewart / Jason Grossman
Investec Bank plc +44 (0)20 7597 5970
Joint Corporate Broker
Chris Sim / Jarrett Silver / Charles Craven
Vigo Consulting +44 (0)20 7390 0230
Public Relations
Patrick d'Ancona / Ben Simons
hurricane@vigoconsulting.com (mailto:hurricane@vigoconsulting.com)
About Hurricane
Hurricane has a 100% interest in and operates the Lancaster field,
the UK's first field to produce from a fractured basement reservoir.
Visit Hurricane's website at www.hurricaneenergy.com
(http://www.hurricaneenergy.com/)
Inside Information
This announcement contains inside information as stipulated under the market
abuse regulation (EU no. 596/2014). Upon the publication of this announcement
via regulatory information service this inside information is now considered
to be in the public domain.
Competent Person
The technical information in this release has been reviewed by Antony Maris,
Chief Executive Officer, who is a qualified person for the purposes of the AIM
Guidance Note for Mining, Oil and Gas Companies. Mr Maris is a petroleum
engineer with more than 35 years' experience in the oil and gas industry. He
has a B.Sc.(Eng.) Petroleum Engineering (Hons) from the Imperial College of
Science and Technology (University of London), Royal School of Mines
A.R.S.M., and an MBA from Kingston Business School.
Standard
Reserves and Contingent Resource estimates for the Lancaster field contained
in this announcement have been prepared in accordance with the Petroleum
Resource Management System guidelines endorsed by the Society of Petroleum
Engineers, World Petroleum Congress, American Association of Petroleum
Geologists and Society of Petroleum Evaluation Engineers.
Chairman's Statement
Dear shareholder,
I am pleased to present the 2022 annual report for Hurricane Energy, the first
year of my chairmanship.
2022 was a busy and important year for Hurricane, and 2023 to date has been
transformational for the Company, as we hope to complete the recommended
acquisition of Hurricane by Prax Exploration & Production PLC (Prax) (a
wholly-owned subsidiary of State Oil Limited) imminently.
The terrible events in Ukraine provided a volatile backdrop for the energy
sector throughout 2022, with sharp movements in commodity prices and an
enhanced focus on security of energy supply. The imposition by the UK
government of the Energy Profits Levy only added to the sense of instability
for the sector.
Operationally and commercially 2022 was a strong year for the Company.
Production averaged 8,500 bopd from the Lancaster field with uptime of 97%. In
July 2022 we were able to pay off our outstanding convertible bonds, as a
result of the excellent operational performance at the field, combined with
strong oil prices. In May we welcomed Linda Beal to the Board, followed
shortly thereafter with Robin Allan joining us in July. Both joined as
Independent Non-Executive Directors, and have contributed superbly to our
discussions since their arrivals in what has been a busy time for the Board.
Having repaid our debt and established a firmer footing, the Company
considered its options in terms of increasing production at Lancaster.
However, despite many months of engagement we did not receive the requisite
comfort from the regulator, the NSTA, required for the very material
investment proposed.
In November 2022, following receipt of an unsolicited bid for the Company
valuing each share at 7.7p which the Board concluded should not be recommended
to shareholders, and with our largest investor, Crystal Amber, being clear
that they wished to monetise their holding in Hurricane and would not support
an investment-led growth strategy, the Board launched a Formal Sale Process.
This thorough and exhaustive process culminated in the Board recommending an
offer from Prax. Should the Scheme be sanctioned by the Court, I believe
Hurricane has an exciting future as part of the wider Prax organisation.
During what has been an exciting but also challenging period, I would like to
thank our staff, the Board and our advisors for their continuing hard work
during a particularly busy and uncertain time for the Company.
Philip Wolfe
Chairman
25 May 2023
Chief Executive Officer's Review
"A year of continued strong delivery"
Introduction
2022 has been both highly challenging and a highly successful year for
Hurricane, whilst also an extraordinarily volatile period for our sector.
During the year, the importance of domestic energy security was exacerbated by
the terrible events in Ukraine and by the subsequent concerns over energy
supplies across Europe resulting in surging commodity prices. In addition, the
introduction of the Energy Profits Levy in the UK, followed by a slow decline
in product prices back to levels seen at the start of the year, contributed to
the challenges faced by an industry with long term investment cycles.
The resulting high oil price early in the year, combined with outstanding
operational performance at the Company's Lancaster field, significantly
strengthened Hurricane's finances, and led to the full repayment in July 2022
of the outstanding Convertible Bonds. This represented a major milestone for
our Company.
Alongside this, working closely with our FPSO operator, we delivered superb
uptime performance and produced towards the upper end of our annual production
guidance. The field has now produced more than 15 million barrels.
With Hurricane finally underpinned by firm financial foundations, debt-free
and with significant cash in hand, we devoted more time to addressing the
future of the Company, prioritising the best investment opportunities that
could add significant value for shareholders. This, however, attracted
attention from outside investors at a time when our largest shareholder had
also indicated its desire to monetise the value of its shareholding and that
it would not support an investment-led growth strategy.
Following an unsolicited offer for the Company, the Board decided to launch a
Formal Sale Process (FSP), which, at the end of a thorough and exhaustive
process, delivered an offer from Prax Exploration & Production PLC (Prax).
The Court hearing to sanction the Scheme resulting from that offer is
scheduled for 7 June 2023.
Operational review
Greater Lancaster Area (GLA)
The year saw a very strong operational performance by the Aoka Mizu FPSO at
the Company's Lancaster field. The field has performed well, delivering on
average 8,500 barrels of oil per day during the year- towards the upper end of
our 2022 production guidance. The anticipated natural decline coupled with
increased water cut, offset by high uptime, informed production levels, and
these factors are expected to play their part in future field performance.
During the period there were six cargo liftings totalling 3.2 million barrels
delivering revenues of $310.8 million.
Over a two-day period in May the Company conducted several flow performance
tests on the P7z well that involved temporarily reducing the flow rate from
the P6 well. The data obtained will be useful in refining production forecasts
for P6. In September the planned annual maintenance shutdown was carried out
on the Aoka Mizu with production being successfully restarted ahead of the
originally anticipated timeframe.
As a condition of the approval from the Regulator for below bubble point
production, renewed production, flare, and vent consents are applied for on an
ongoing three-monthly basis. During December 2021, the well gauge pressure
reached and declined below bubble point. No production issues arising from
reaching bubble point have been observed to date. The Company continues to
monitor this closely and has continued to receive the required consents from
the Regulator on a three-monthly basis.
Management's production guidance for the full calendar year 2023 is 5,900 -
7,100 bopd. This assumes FPSO production planned uptime of 96.5% and
production from the P6 well alone on artificial lift via an electrical
submersible pump (ESP). Guidance also includes the impact of an annual
maintenance shutdown, anticipated to occur during Q3 2023.
Hurricane concluded positive negotiations with Bluewater (Aoka Mizu) B.V.
(Bluewater), the owner of the Aoka Mizu FPSO, with regards to an extension and
announced in March 2022 that it had signed a contract with Bluewater for an
extension to the Bareboat Charter beyond the original expiry date of 4 June
2022.
The key terms of the extension are:
1. The charter was extended to cover the remaining economic life of the
Lancaster field.
2. Either party can give six months' notice to terminate the charter.
3. The existing day rate and tariff for the vessel remained at $75,000
per day and 8% of revenue respectively.
4. Hurricane agreed to establish a secured deposit account of up to
$18.7 million for the benefit of Bluewater to cover the costs associated with
the day rate for the six- month notice period and decommissioning in respect
of the vessel.
This was an important step forward. It was key that Hurricane and Bluewater
found a mutually acceptable deal to enable the Company to continue production
beyond repayment of the Convertible Bonds.
Alongside ongoing production operations, the Company evaluated the possibility
of drilling an additional production well, the P8 well. Although first
discussed with the Regulators in 2021, in early 2022, when the Company
recognised that not only would it clear its debt but also potentially have
sufficient funds to both fully cover the cost of a new well in Lancaster and
also its other operational requirements, we engaged with the Regulators
concerning the unique challenges Hurricane faces.
The originally approved development plan included flaring as the approved gas
disposal mechanism and, under the NSTA approval of the amendment to this plan,
allowed for production below the bubble point.
The Company has worked hard to reduce its emissions and had significant
success in achieving reductions through the combined hard work and efforts of
our team and Bluewater. Hurricane is fully cognisant of the increased scrutiny
and oversight in this area and continues to look at ways of further reducing
our overall environmental footprint, where it is economically and commercially
viable to do so. However, being fully aware of the challenge concerning flare
volumes and the impact that any additional production would have, the Company
worked tirelessly with both OPRED and the NSTA to address the environmental
impact of new investment.
We believe that the project is consistent with the requirements placed upon
Hurricane to maximise economic recovery as part of the OGA Strategy's Central
Obligation 2a. Whilst the project would lead to a short-term increase in
emissions, we also believe we are fully aligned with the OGA Strategy's
Central Obligation 2b, which is to assist the Secretary of State in meeting
the country's Net Zero targets.
Interaction on this latter point has been detailed, and rightly both
challenging and highly scrutinised. The situation Hurricane faces is that the
retrofitting of a new gas export or disposal system to the existing
development is technically challenging, with a high capex requirement. The
expected recovery of gas from an additional well, including the benefit of the
extended life of the field, was such that the economics of the investment were
below the threshold considered appropriate for Hurricane to commit to such a
project.
We are fully aware of the challenge the NSTA faces in terms of the interaction
between the competing objectives of maximising economic recovery whilst
reducing emissions. The Company therefore offered that all incremental
emissions from the new well (including those associated with the extension of
the life of the field) would be covered by verifiable carbon offsetting.
The informal feedback from the NSTA during the six months of interaction was
that, even where there is no technical and economically viable solution to
mitigate the emissions that is reasonable in the circumstances, then the NSTA
still may or may not grant the consents when requested.
The project and the level of financial commitments are of major significance
to the Company, particularly given the risk associated with continued
performance of the existing single well. Therefore, whilst the Company
believes the proposed P8 project would be within the regulatory guidance, the
Board has concluded that, in the absence of any comfort from the Regulator,
the additional financial commitments to offshore equipment suppliers and the
associated financial risk of proceeding with P8 was too great.
Greater Warwick Area (GWA) & Halifax
In April, the GWA Joint Venture (JV) announced that it had reassessed its
understanding of the Greater Warwick area, evaluated both the basement and the
Mesozoic potential of the JV's licences, and considered all options for
further appraisal and routes to possible development.
In June, Hurricane reported that it had determined that further appraisal and
development costs to reach an economic development on the Warwick discovery
within the remaining licence term was not feasible for the Company. Further to
discussions with the Company's JV partner, Spirit Energy, the JV therefore
decided to relinquish the Warwick P2294 licence area. This was in addition to
the previously announced decision to relinquish the Lincoln P1368(S) licence
sub area.
In addition, in September 2022 the Company determined that the costs required
to further evaluate the Halifax licence (P2308) and the low likelihood of a
successful economic development meant that the right next step was to
relinquish the licence. As with the GWA licences, there was no reasonable
expectation that the P2308 licence could generate any near-term cash
realisation, and therefore voluntarily relinquishing the licence at that time
allowed the Company to focus its time and financial resources on alternative
and more attractive opportunities. All previously capitalised costs relating
to Halifax have already been impaired and therefore no further impairments
were required.
We have delivered all the required information and data to the Regulator and
these assets have been relinquished. Activities to close down the JV are
ongoing, and this is anticipated to be completed during 2023.
Decommissioning Activities
In early 2022, in accordance with the provisions of the Petroleum Act 1998 and
related guidance, Hurricane and Bluewater submitted for the consideration of
the Secretary of State for Business, Energy and Industrial Strategy, a draft
Decommissioning Programme for the Lancaster Field FPSO. The draft was
published to allow interested parties to be consulted on such decommissioning
proposals well in advance of forecast cessation of production operations.
Health and Safety
In 2022 Hurricane delivered excellent HSE performance with no Lost Time
Incidents or Recordable Incidents throughout the year, and no spills to sea
and no loss of containment events. The Lost Time Incident Frequency Rate
(LTIFR) for 2022 was nil compared to 1.71 for 2021 and 1.29 for 2020 (figures
are per million man-hours).
Throughout the year, the impact of COVID-19 on our operations reduced
significantly through the effectiveness of the Government's vaccination
programme and relaxation of Government and Health Protection COVID-19
Guidelines. Two occupational illness cases were recorded where occupational
transmission of COVID-19 occurred. We retained offshore COVID-19 testing
capability, the ability to quarantine positive cases and repatriate confirmed
positive COVID-19 cases to shore via our Central Medical Emergency Dispatch
(CMED) aviation provider. Where there have been any suspected or confirmed
cases offshore, medics have acted promptly to ensure anyone affected was
isolated and treated in conjunction with advice from Bluewater's topside
doctor. Dedicated Aviation Contractor CMED flights, with attendant paramedics
were retained to repatriate suspected or confirmed COVID-19 cases back to
shore for further assessment and treatment where necessary. We are pleased to
report that COVID-19 did not adversely affect safe operations throughout the
year.
Key activities undertaken throughout the year included continued safe
production from the Lancaster Field with Bluewater's Aoka Mizu FPSO,
completion of our annual planned maintenance shutdown for safety and
production critical maintenance, completion of the Deep Cygnus subsea
inspection, repair and maintenance (IRM) scope in August 2022 and successful
recovery of a fishing net left at the location of the Whirlwind well head.
This enabled completion of the seabed clearance at Whirlwind 205/21-5. All
this work was completed without incident.
ESG
Despite the challenges the year has provided, Environmental, Social and
Governance ("ESG") remains a key area of scrutiny in the Company. In June
2022, Hurricane published its third standalone ESG report, covering the
approach to ESG and performance across its operations for the 2021 calendar
year.
During 2022, our Scope 1 greenhouse gas emissions were 110,576 tonnes CO₂e,
or 35.8 kg/bbl on an intensity basis. This compared with 139,584 tonnes
CO₂e, or 37.2 kg/bbl in 2021, and 210,884 tonnes CO₂e and 41.5 kg/bbl in
2020.
These emissions meet the OEUK Scope 1 definition and include CO₂ as well as
other greenhouse gases specified by the Kyoto Protocol. These figures are
based on Intergovernmental Panel on Climate Change's (IPCC) Fifth Assessment
report.
Currently, associated gas production from the Lancaster EPS is partially used
as fuel gas for the Aoka Mizu FPSO, with the remainder flared under the
consent within the approved Field Development Plan Addendum. We remain fully
cognisant of the increased scrutiny and oversight in this area and are
committed to continuing to look at ways of further reducing this figure and
our overall environmental footprint in 2023 and beyond where it is
economically and commercially viable to do so.
Reserves and resources
Since 2021, following the complete re-evaluation of the Lancaster field and
its performance, the Company has been consistently in line with its production
guidance, announced annually, and its cost base has been very stable year on
year, rising mainly as a result of inflationary pressures.
This demonstrates an excellent understanding of what we have and how to
extract it safely, efficiently and at the best value. In addition, based on
our performance and interaction with them, the NSTA has agreed, without the
need for a lengthy process to amend the formal Field Development Plan, to
increase the pressure below the bubble point we can produce to - up to 600 psi
from 300 psi.
This change in our depletion management regime and the incorporation of the
oil volumes potentially present in the Victory and Rona sandstones, which
onlap the Lancaster field, has allowed the transfer to Reserves of some of our
Contingent Resources and to extend field life.
Hurricane elected to retain ERC Equipoise Limited (ERCE) to update its
Competent Person's Report (CPR) on the Reserves and Contingent Resources of
the Lancaster field, published on 16 March 2023 with an effective date of 31
December 2022, which included an asset valuation by ERCE. Their estimates of
Lancaster field Reserves and the Contingent Resources are detailed in the
tables below.
While the latest CPR shows an increase in the reserves, these reserves will
largely be produced in the "tail" so are low contributors to value. We will
continue to review trends in production decline, pressure, and water cut that
may impact future production and the level of reserves.
In the ERCE CPR, ERCE has evaluated the Reserves for the field, assuming the
effective date of 31 December 2022. The estimates of Reserves and the economic
limit in each case are summarised in the table below.
Hurricane Gross Reserves Net Attributable Reserves
100% and operator 1P 2P 3P 1P 2P 3P
Reserves (MMstb) 4.1 6.6 10.3 4.1 6.6 10.3
Economic Limit Dec-2024 Feb-2026 Nov-2027 Dec-2024 Feb-2026 Nov-2027
A summary of the movements in net attributable 2P Reserves as compared to the
previous CPR (effective date of 31 December 2021) is as follows:
Net attributable 2P Reserves (MMbbl)
At 31 December 2021 5.8
Produced volumes in 2022 (3.1)
Change in assumptions and economic life 3.9
At 31 December 2022 6.6
ERCE has also updated its estimates of 2C Resources (Development Unclarified),
which require further drilling to convert to Reserves. These are set out in
the table below:
Hurricane Gross Contingent Resources Net Attributable Contingent Resource
100% 1C 2C 3C 1C 2C 3C
Lancaster (MMstb) (MMstb) (MMstb) (MMstb) (MMstb) (MMstb)
8.3 31.6 82.7 8.3 31.6 82.7
New Business Opportunities
In addition to considering investing further in the Lancaster Field, the
Company has been actively pursuing potential opportunities outside the
Company's current asset base.
Focusing on the UKCS, the Company has continued to evaluate a number of farm
in opportunities, acquisitions and mergers. Hurricane's management and staff
have extensive experience in both oil and gas, through all stages of the asset
life-cycle, and therefore the scope covered a range of new oil and gas
investment opportunities. Should the Prax transaction complete, we will
continue to look for both asset and corporate level opportunities that will
help diversify our asset base, deliver value to shareholders, and strengthen
the Company for the future.
Despite the volatility in commodity prices, and the uncertainties these
create, Hurricane believes that its strong balance sheet, technical and
operational expertise, and proven track record of capital project delivery
offer a strong competitive advantage among its peer group.
Formal Sale Process
Following receipt of an unsolicited offer in mid-2022 and after a period of
engagement with the offeror, Hurricane received a follow-up offer from that
offeror which the Hurricane Board concluded should not be recommended to
Hurricane Shareholders. Thereafter, on 2 November 2022, Hurricane announced
the initiation of a FSP, to establish whether there was a bidder prepared to
offer a value that the Hurricane Board considered to be attractive, relative
to the standalone prospects of Hurricane as a publicly traded company and
accordingly one that should be recommended to all Hurricane Shareholders. The
Board appointed Stifel Nicolaus Europe Limited as its independent financial
adviser with regards to the FSP.
The FSP was marketed to a wide audience of potential acquirors with an
interest in acquiring assets on the UK Continental Shelf. This process
culminated in the Board recommending an offer from Prax Exploration &
Production PLC, (a wholly-owned subsidiary of State Oil Limited) which is a
leading, British headquartered, international integrated and diversified
midstream and downstream energy group. Full details of the recommended offer
were published in the Scheme Document on 6 April 2023 and are available on
Hurricane's website.
Reduction of Capital
Alongside the FSP, the Company also committed, that if the FSP did not result
in a transaction, to commence a significant capital return programme with up
to $70 million to be returned to shareholders in Q1 2023, upon completion of
a Reduction of Capital.
The High Court approved the Reduction of Capital on 31 January 2023 with the
sealed court order subsequently filed with the Registrar of Companies. This
completed the Reduction of Capital process, allowing the Company to make
capital returns to shareholders and supporting the FSP.
People and operations
This year has been another challenging one and I would also like to express my
thanks to all our colleagues for their hard work, professionalism, and
dedication. Hurricane's operational delivery since start-up of the Lancaster
field has been first class. What would normally be many months of work on the
technical review and development options screening was compressed into a much
shorter timeframe without compromising on rigour or quality. The understanding
of the field's performance has grown as has our rebuilding an excellent
working relationship with the regulator, who recently commended Hurricane for
excellent performance.
Since 2021, following the complete re-evaluation of the field and its
performance, the Company has been consistently in line with its production
guidance, announced annually, and its cost base has been very stable year on
year through the hard work of the team to reduce and remove cost pressures,
rising mainly as a result of macro-inflationary pressures.
Following the Government's relaxation of COVID-19 precautionary measures, we
reopened the office in February 2022, returning to a hybrid working
arrangement preserving some measure of home working. However, we have not
forgotten the lessons learnt from the pandemic where we actively encouraged
flexible working recognising that employees may have responsibility for
childcare, home schooling, family members as well as other obligations. We
continue to look at what works best as greater pressures for more interactive
office-based work grows.
Outlook
When I joined Hurricane, my priority, working closely with the senior team,
was to focus on creating value for shareholders despite the huge technical and
financial challenges we faced. The offer from Prax shows how well we, as a
team, have done.
Technically, we have demonstrated excellent operational understanding and
found ways to improve recovery despite the financial limitations.
Commercially, we have cleared our debt, provided a firm financial footing for
assessing future opportunities and kept control of our costs despite
inflationary pressures.
All this has built an excellent reputation across our industry and attracted
outside investors wanting to take advantage of what could we bring to them.
Antony Maris
Chief Executive Officer
25 May 2023
Chief Financial Officer's Review
"A year of continued recovery and consolidation"
Highlights
2022 2021
Production 3,089 Mbbl 3,748 Mbbl
Production rate* 8,500 bopd 10,300 bopd
Sales volumes 3,226 Mbbl 3,576 Mbbl
Revenue $310.8m $240.5m
Average sales price realised $96.3/bbl $67.3/bbl
Cash production cost per barrel† $37.4/bbl $28.2/bbl
Free cashflow† $175.9m $135.7m
Net free cash† $121.4m $51.5m
Net debt† NIL $27.0m
Underlying profit before tax† $113.6m $10.8m
Statutory profit after tax $108.7m $18.2m
* Rounded to nearest 100 bopd
† Non-IFRS measures. See Appendix B to the Financial Statements for
definition and reconciliation to nearest equivalent statutory IFRS measures.
Overview
2022 was a year of continued recovery and consolidation for Hurricane. The
first half of 2022 was an extraordinarily volatile period for our sector due
to surging oil prices, exacerbated by the terrible events in Ukraine. Oil
prices in the second half of 2022, whilst lower than the levels seen earlier
in the year remained above $80 per barrel on a near continuous basis. The
high oil price for the year, combined with excellent operational uptime of the
Aoka Mizu FPSO at the Lancaster field, has continued to strengthen Hurricane's
finances.
Over 3.2 million barrels of Lancaster crude were sold across six cargoes,
generating $310.8 million revenue. This increase compared to 2021 is thanks to
the strong oil prices seen in 2022 compared to 2021 which have helped to
offset the impact of the lower level of production. This, combined with a
continued focus on low operating costs and excellent production efficiency of
99%, produced free cashflow† of $175.9 million. Cash capex† in the year
was $10.3 million.
Hurricane completed its repayment of Convertible Bonds during the year, with a
final payment of $78.5 million being made in July 2022. At 31 December 2022,
Hurricane was debt free with a net free cash† balance of $121.4m.
Although uncertainties remain, with oil prices still supportive and a debt
free position, Hurricane is in a strong financial position.
Revenue
Revenue recognised for the year was $310.8 million (2021: $240.5 million),
with an average realised price of $96.3/bbl (2021: $67.3/bbl) across 6 cargoes
comprising 3.2 million barrels (2021: 7 cargoes comprising 3.6 million
barrels). Whilst the average Dated Brent price for the year was $101.3/bbl,
under the sales and marketing agreement Hurricane has in place with BP, the
sale of Lancaster crude is priced by reference to the average of either the
Dated Brent price of first or last five days in the month of lifting (at the
buyer's option, declared by the 20(th) of the month). This arrangement means
that the reference Dated Brent price for a cargo is typically lower than the
spot price at the time of lifting. The lower number of cargoes reflects not
only the declining rate of production, but also, where possible, maximising
cargo sizes in 2022 to minimise transportation costs per barrel.
The average netback to the contractual Brent price was $2.7/bbl (2021:
$2.7/bbl), representing the discount or premium offered by the refinery
purchasing the crude, BP's marketing fee, and the freight and port costs
incurred by the buyer in transporting Lancaster crude to its ultimate
destination. The excellent FPSO uptime achieved means that Hurricane has
continued to sell all cargoes on time, within specification and contractual
terms, maintaining our reputation as a reliable producer. The sales
arrangement with BP means that Hurricane receives cash for a sale typically
within five days of the lifting occurring.
Cost of sales
Total cost of sales was $173.4 million, including $81.9 million of DD&A.
Cash production costs† were $115.4 million (2021: $105.8 million),
equivalent to $37.4 per barrel (2021: $28.2/bbl).
Excluding the revenue-linked incentive tariff, cash production costs per
barrel increased from $22.8/bbl in 2021 to $29.3/bbl in 2022. This increase
per barrel was driven by lower average production rates in 2022 as well as
cost inflation. With a cost base that is largely fixed (i.e. not linked to
production rates), natural decline in production and inflationary cost
pressures, we expect cash production costs per barrel to increase during 2023;
although we continue to look for cost savings internally and with our key
contractors where possible.
Impairment of intangible assets and GWA licences
The overall strategic intent of the GWA Joint Venture has previously been the
exploration and appraisal of the GWA licence areas, to assess hydrocarbon
resource and commercially producible reserves, with the aim of producing
reserves and ultimately identifying a fit for purpose field development in
line with the GWA Joint Venture objectives and MER UK.
Hurricane together with its joint venture partner Spirit Energy has determined
that further appraisal and development costs to reach an economic development
on the discoveries in the GWA area within the remaining licence terms is not
feasible, and the licences for P1368(S) (Lincoln asset) and P2294 (Warwick
asset) were therefore relinquished in July 2022.
In anticipation of the licence Lincoln P1368(S) relinquishment, the carrying
value of the Lincoln assets was fully impaired in 2021, resulting in an
impairment charge of $54.3 million in that year. The GWA Joint Venture
decision to surrender the Warwick P2294 licence subarea gives rise to an
impairment charge of $4.1 million for the current year and the carrying value
of the Warwick assets has therefore now also been fully impaired.
The aim going forward into 2023 is to bring the GWA JV to an orderly
conclusion, with the main activity being the ongoing storage and disposal of
joint property.
FPSO lease
In March 2022, Hurricane announced it had concluded an agreement with
Bluewater to extend the charter of the Aoka Mizu FPSO beyond June 2022. The
key terms of the agreement included:
· either party can give six months' notice to terminate the charter;
· the existing day rate and tariff for the vessel remains at $75,000
per day and 8% of revenue respectively; and
· Hurricane agrees to establish a secured deposit account of up to
$18.7 million for the benefit of Bluewater to cover the costs associated with
the day rate for the six-month notice period and decommissioning in respect of
the vessel.
The revised agreement therefore gives Hurricane the security and flexibility
to cover production from the Lancaster field for its remaining economic life,
which is forecast to be until August 2025. For the purposes of accounting for
the lease under IFRS 16, the lease term as been re-assessed to this date. This
has resulted in an increase in the lease liability and corresponding lease
asset.
Convertible Bond and debt management
During the second half of 2021, Hurricane completed a series of Convertible
Bond buybacks leaving an amount of $78.5 million outstanding at 31 December
2021. This amount was repaid in July 2022, resulting in Hurricane now being in
a debt free position.
Net debt and net free cash evolution:
The above chart shows net free cash of $52 million at 31 December 2021 which,
after deducting Convertible Bond debt of $79 million shows a net debt position
of $27 million at that date. Further to the payment of remaining element of
the Convertible Bond debt in July 2022, the net debt position was cleared.
Other profit and loss
Net general and administrative costs (G&A) before non-cash items reduced
from $23.6 million in 2021 to $8.7 million in 2022. This decrease was
primarily due to significant expenditures having been incurred on the proposed
financial restructuring during 2021, as well as the Group implementing cost
saving measures such as the right-sizing of headcount (via recruitment freezes
and targeted redundancies) by the end of that year.
Cashflow
Net free cash† bridge
1. Including transaction costs
† Non-IFRS measure. See Appendix B to the Financial Statements for
definition and reconciliation to nearest equivalent statutory IFRS measure(s).
The Group ended the year with $121.4 million of net free cash†, an increase
of $69.9 million from the position of $51.5 million at 31 December 2021.
Free cash flow† for the year was $175.9 million (2021: $135.7 million),
equivalent to $56.9/bbl (2021: $36.2/bbl), driven by higher average realised
Brent prices offset by the increase in day rate payable (from $25,000 to
$75,000 per day) for the Aoka Mizu charter which became effective from June
2021. Cash capex† in the period was $10.3 million.
Restricted funds
As of 31 December 2022, the Group held $60.8 million of cash within restricted
funds, relating to decommissioning security arrangements and amounts set aside
to cover costs associated with the FPSO lease.
At the start of the year, the Group held £28.0 million ($37.8 million) in
trust as security for its decommissioning liability on the Lancaster field,
which includes the cost of abandoning the production wells, subsea
infrastructure and related FPSO costs. During the year, an additional £5.7
million was placed into Trust following a request from the Regulator as a
result of increases to the Group's decommissioning estimates. At 31 December
2022, a total of £33.7 million ($40.6 million) was held in trust as
decommissioning security for the Lancaster EPS.
Included within restricted cash, cash equivalents and liquid investments is
$20.2 million (2021: $7.9 million) set aside in relation to the Aoka Mizu FPSO
bareboat charter. This amount was established and classified as restricted
cash following the agreement in March 2022 to extend the FPSO lease. Under the
terms of the contract, the Group is required to ring-fence amounts to ensure
it could meet its liability to the lessor if the contract is terminated by the
Group or the lessor. The $20.2 million amount consists of an original amount
of $18.7m originally agreed with the lessor on extension of the lease in March
2022, with an additional $1.5 million subsequently being agreed to be set
aside.
Tax
The Group recognised a total net tax charge for 2022 of $1.7 million.
Included in the net tax charge for the period is a tax charge of $6.2 million
relating to the Energy (Oil and Gas) Profits Levy Act 2022 (EPL), which was
introduced and took effect for profits generated from 26 May 2022 onwards at a
rate of 25%.
Offsetting the EPL charge is a credit of $4.6 million representing amounts
received in respect of R&D claims during 2022. Hurricane previously made
claims for R&D tax credits in respect of financial years 2019 and 2020,
including via the surrender of some brought forward tax losses, being R&D
spend related to increasing reservoir understanding of fractured basement and
optimising productivity and reserves recovery.
Tax losses
Due to the nature of the Group's business, it has accumulated significant tax
losses since incorporation. The Group has $214.5 million of ring-fenced
trading losses (including certain RDEC credits) and other allowances and
supplementary charge losses and investment allowances of $629.8 million, which
have no expiry date and would be available for offset against future trading
profits, and $333.1 million of capital allowances available against future
ring-fenced trading profits. The estimated value of these losses and
allowances at prevailing tax rates, including the Group's pre-trading
expenditure, future decommissioning costs and non-ring fence losses, is $428.3
million. See note 6.3 in the Financial Statements for further information.
Access to these losses and allowances is likely to be severely restricted at
the point at which trading activities end (which would include a permanent
cessation of production from the Lancaster EPS). Furthermore, in the event of
any corporate transaction, access to the brought forward losses may be
restricted if trade was deemed negligible at the point of a change in control
or there was deemed to be a major change in the nature or conduct of the
entity's trading activities. Furthermore, at prevailing oil prices, the Group
will continue to utilise its existing ring fence losses as the Lancaster EPS
generates taxable profits.
Going concern
The Directors have considered both the going concern and longer-term prospects
of the Group, and have a reasonable expectation that the Group will continue
in operational existence throughout the going concern period. For further
details and analysis, see the Going Concern section of the Strategic Report.
Richard Chaffe
Chief Financial Officer
25 May 2023
Going concern and the Group's longer-term prospects
Going concern
The Group's business activities, together with the factors likely to affect
its future development, performance and position are set out in this Strategic
Report. The Group ended the year with $199.1 million of cash and cash
equivalents, of which $138.4 million was unrestricted. After adjusting for
working capital items, net free cash† at 31 December 2022 was $121.4
million. The Group's most significant long-term liabilities are committed
lease liabilities in respect of the Aoka Mizu FPSO, following the final
repayments in respect of the Convertible Bond having been made in July 2022.
Further details of the financial position of the Group, its cash flows and
liquidity position are described in the Chief Financial Officer's Review; with
the Group's off- and on-balance sheet commitments set out in notes 2.7 and 5.3
of the Group Financial Statements. In addition, note 5.8 to the Group
Financial Statements includes the Group's objectives, policies and processes
for managing its capital; and note 4.4 includes the Group's objectives
concerning its financial risk management objectives; details of its financial
instruments; and its exposures to credit, market and liquidity risk.
The Group monitors its capital position and its liquidity risk regularly
throughout the year, with cashflow models and forecasts regularly produced and
refreshed based on production profiles, latest estimates of oil prices,
operating and G&A budgets, working capital assumptions, movements to and
from restricted funds, and the Group's debt repayments. Sensitivities are run
to reflect different scenarios including changes in reservoir performance,
movements in oil price and changes to the timing and/or quantum of capital
expenditure projects.
Assessment of going concern
Whilst each of the Principal Risks, which will be outlined in the 2022 Annual
Report, has a potential impact on the business, the Directors' assessment of
going concern focused on those that are the most critical to the Group's
prospects, which are considered to be:
· Production delivery risks;
· FPSO and third-party infrastructure risks; and
· Oil price volatility
The Group's base case going concern assessment assumed the following:
· average Dated Brent oil price of $75/bbl in 2023 and $73/bbl in 2024;
· no sanctioned capital or development projects;
· continued use of the Aoka Mizu FPSO throughout the assessment period;
and
· production from the P6 well alone in line with approved guidance and
the production profiles consistent with the most recent CPR
· a return of cash by the Company to its shareholders in the form of
either
o a dividend of £103 million being paid to shareholders following the
agreement reached on the terms of a recommended acquisition of the Company's
entire issued ordinary share capital by Prax Exploration & Production PLC
(the terms and details of the recommended offer are set out in the Scheme
Document, with completion of the acquisition being subject to court sanction)
o in event that the above acquisition is not completed, a return of $70
million to its shareholders
Under the base case scenario, the Group had sufficient headroom for a period
of at least 12 months to fund ongoing working capital requirements.
Sensitivity analyses were also undertaken to reflect the following:
· a reduction to the forecast oil price curve of $20/bbl; and
· a 20% reduction to forecast production rates
Under the sensitivity cases above, both individually and in aggregate, the
Group is projected to have sufficient cash to continue operating for a period
of at least 12 months.
Reverse stress tests were also prepared to reflect additional adverse
reductions in oil price and production to determine at what price or rate each
would need to reduce to such that the Group would not have sufficient cash to
continue operating for a period of at least 12 months. In the opinion of
management, the likelihood of such a fall in price and/or production rate that
would give rise to an inability to continue to operate over this period is
remote.
Conclusion
As a result of the going concern assessment presented above, the Directors
have a reasonable expectation that, taking into consideration the current
macroeconomic situation, the Group has adequate resources to continue in
operational existence throughout the going concern period.
Therefore, the Directors continue to adopt the going concern basis of
accounting in preparing these consolidated financial statements and the
financial statements do not include the adjustments that would result if the
Group were unable to continue as a going concern.
Assessment of the Group's longer-term prospects
The longer-term prospects of the Group are driven by its strategy and business
model, whilst factoring in the Group's principal risks and uncertainties.
Assessment of the business is performed over a number of different time
periods for differing reasons, which include an annual budget cycle (with
reforecasts made as appropriate during the year) and a long-term corporate
model which incorporates the latest annual budget and provides forecast cash
flow detail, where appropriate, on a field-by-field basis along with cash
flows incurred and generated at a corporate level. These forecasts take into
account the level of unrestricted cash and cash equivalents at the latest
practicable date of preparation of this review, together with the forecast
cash flow generation from the Lancaster EPS (based on expected production
rates and oil prices as outlined above).
Extending the base case assessment (using average Dated Brent oil prices of
$75/bbl in 2023 and $73/bbl in 2024), and on the key assumption that neither
the Group nor Bluewater exercises their respective termination options over
the bareboat charter of the Aoka Mizu FPSO earlier, the Group is projected to
continue generating positive cashflows from operations until approximately the
third quarter of 2025.
As the Group is able to exit the FPSO charter giving six-months notice and
incurring no termination penalties, it has additional flexibility should oil
price and/or production rate give rise to a significantly shorter than
expected remaining economic life of the Lancaster EPS, or other factors mean
the EPS was operating significantly below break-even level. Furthermore, the
Group has placed significant funds in Trust as security to cover estimated
decommissioning liabilities for the EPS and FPSO.
Hurricane Energy plc
Group Financial Statements 2022
Group Statement of Comprehensive Income
Year ended Year ended
Notes 31 Dec 2022 31 Dec 2021
$'000 $'000
Revenue 2.1 310,776 240,540
Cost of sales 2.2 (173,421) (173,125)
Gross profit 137,355 67,415
(9,355) (26,749)
General and administrative expenses 3.3
Gain on revision of lease term 5.2 - 49,125
Impairment of oil and gas assets 2.3 - -
Change in decommissioning estimates on fully impaired assets 2.5 1,032 (1,972)
Impairment of intangible exploration and evaluation assets and exploration 2.4 & 4.3 (4,234) (54,280)
expense written off
Operating profit 124,798 33,539
Finance income 3.2 1,174 27
Finance costs 3.2 (15,623) (30,656)
Net gain on repurchase of Convertible Bonds 5.1 - 17,201
Fair value gain / (loss) on Convertible Bond embedded derivative 5.1 27 (1,901)
Profit before tax 110,376 18,210
Tax 6.1 (1,715) 26
Total comprehensive profit for the year
108,661 18,236
Cents
Cents
Earnings per share - basic and diluted 3.1 5.46
0.92
All results arise from continuing operations.
Group Statement of Financial Position
Notes 31 Dec 2022 31 Dec 2021
$'000 $'000
Non-current assets
Intangible exploration and evaluation assets 2.4 − 3,830
Oil and gas assets 2.3 99,593 98,296
Other non-current assets 7.2 1,044 1,373
Deferred tax assets 6.2 − 104
Cash and cash equivalents 4.1 60,754 −
Liquid investments 4.1 − 37,783
161,391 141,386
Current assets
Inventory 2.2 26,430 27,488
Trade and other receivables 4.2 3,675 2,591
Cash and cash equivalents 4.1 138,383 76,792
168,488 106,871
Total assets 329,879 248,257
Current liabilities
Trade and other payables 4.3 (15,887) (18,843)
Lease liabilities 5.2 (27,612) (13,880)
Convertible Bond liability 5.1 − (77,373)
Convertible Bond embedded derivative 5.1 − (27)
Tax liabilities 6.1 (3,617) −
(47,116) (110,123)
Non-current liabilities
Lease liabilities 5.2 (39,878) (1,910)
Decommissioning provisions 2.5 (47,057) (49,346)
(86,935) (51,256)
Total liabilities (134,051) (161,379)
Net assets 195,828 86,878
Equity
Share capital 5.4 2,885 2,885
Share premium 822,458 822,458
Share option reserve 5.5 23,321 23,321
Own shares reserve 5.6 (556) (845)
Foreign exchange reserve 5.7 (90,828) (90,828)
Accumulated deficit (561,452) (670,113)
Total equity 195,828 86,878
The Financial Statements of Hurricane Energy plc were approved by the Board
and authorised for issue on 25 May 2023. They were signed on its behalf by:
Antony Maris, Chief Executive Officer
Group Statement of Changes in Equity
Share Foreign
Share Share option Own shares exchange Accumulated
capital premium reserve reserve reserve deficit Total
$'000 $'000 $'000 $'000 $'000 $'000 $'000
At 1 January 2021 2,885 822,458 21,443 (923) (90,828) (688,349) 66,686
Total comprehensive profit for the year − − − − − 18,236 18,236
Share-based payments − − 1,878 78 − − 1,956
At 31 December 2021 2,885 822,458 23,321 (845) (90,828) (670,113) 86,878
Total comprehensive profit for the year − − − − − 108,661 108,661
Share-based payments − − − 289 − − 289
At 31 December 2022 2,885 822,458 23,321 (556) (90,828) (561,452) 195,828
Group Cash Flow Statement
Year ended Year ended
Notes 31 Dec 2022 31 Dec 2021
$'000 $'000
Cash flows from operating activities
Operating profit 124,798 33,539
Adjustments for:
Depreciation of property, plant and equipment 2.3 82,184 98,099
Change in decommissioning estimates on fully impaired assets 2.5 (1,032) 1,972
Impairment of intangible exploration and evaluation assets and exploration
expense written off
2.4 & 4.3 4,234 54,280
Gain on revision of lease term 5.2 − (49,125)
Impairment of other right-of-use assets 7.2 − 719
Share-based payment charge 3.3 289 1,956
Expenditure on proposed financial restructuring − 15,903
Decommissioning spend 2.5 (277) (4,824)
Operating cash flow before working capital movements 210,196 152,519
Movement in receivables (2,365) 579
Movement in payables (3,909) 5,356
Movement in crude oil, fuel and chemicals inventories 2.2 2,087 (11,410)
Cash used in operating activities 206,009 147,044
Energy Profits Levy paid (2,582) −
Net cash inflow from operating activities 203,427 147,044
Cash flows from investing activities
Interest received 1,174 27
Movement in liquid investments 34,739 (15,530)
Expenditure on oil and gas assets (8,328) (6,618)
Expenditure on other fixed assets − (2)
Expenditure on intangible exploration and evaluation assets (699) (2,782)
Movement in spares and supplies inventories 2.2 (1,029) (4,793)
R&D tax refund 4,588 −
Net cash used in investing activities 30,445 (29,698)
Cash flows from financing activities
Repurchases of Convertible Bond principal for cancellation 5.1 − (130,346)
Convertible bond principal repayment 5.1 (78,515) −
Transaction costs 5.1 (5) (1,311)
Convertible Bond interest paid 5.1 (4,416) (17,372)
Lease repayments 5.2 (27,837) (18,596)
Interest and other finance charges paid (13) (34)
Expenditure on proposed financial restructuring − (15,903)
Net cash used in financing activities (110,786) (183,562)
Net increase / (decrease) in cash and cash equivalents 123,086 (66,216)
Cash and cash equivalents at beginning of year 4.1 76,792 143,703
Net increase / (decrease) in cash and cash equivalents 123,086 (66,216)
Effects of foreign exchange rate changes (741) (695)
Cash and cash equivalents at end of year 4.1 199,137 76,792
Notes to the Group Financial Statements
for the year ended 31 December 2022
Section 1. General information and basis of preparation
Hurricane Energy plc is a public company, limited by shares, incorporated and
domiciled in the United Kingdom and registered in England and Wales under the
Companies Act 2006 (registered company number 05245689). The nature of the
Group's operations and its principal activity is exploration, development and
production of oil and gas reserves on the UK Continental Shelf.
1.1 Basis of preparation and consolidation
The Financial Statements have been prepared under the historical cost
convention (except for derivative financial instruments which have been
measured at fair value) in accordance with UK-adopted International Accounting
Standards in conformity with the requirements of the Companies Act 2006 and in
accordance with the requirements of the AIM Rules.
The Group Statement of Comprehensive Income and related notes represent
results from continuing operations, there being no discontinued operations in
the years presented.
The consolidated Financial Statements incorporate the Financial Statements of
the Company and entities controlled by the Company (its subsidiaries) made up
to 31 December each year. Control is achieved when the Company:
· has power over the investee;
· is exposed, or has rights, to variable returns from its involvement
with the investee; and
· has the ability to use its power to affect its returns.
All intragroup transactions, balances, income and expenses are eliminated on
consolidation.
The Group's joint arrangement with Spirit Energy Limited (Spirit) is accounted
for as a joint operation (where the parties have rights to the assets and
obligations for the liabilities of that arrangement). As such, in relation to
its interests in the joint operation, the Group recognises its assets,
liabilities, revenues and expenses of the joint operation, including its share
of any jointly held or incurred assets, liabilities, revenues and expenses.
These have been incorporated in the Financial Statements under the relevant
headings. Details of this joint operation are set out in note 2.6.
In the opinion of the directors, the operations of the Group comprise one
segment of business, being oil and gas exploration, development and production
together with related activities in only one geographical area, the UK
Continental Shelf.
1.2 Going concern
The Financial Statements have been prepared in accordance with the going
concern basis of accounting. The forecasts and projections made in adopting
the going concern basis take into account forecasts over oil prices,
production rates, operating and G&A expenditure, and committed and
sanctioned capital expenditure. In addition, sensitivity and reverse stress
test analyses have been considered. Further details on the going concern
assessment undertaken are outlined in the Going Concern section of the
Strategic Report which confirms the directors have a reasonable expectation
that, taking into consideration the current macroeconomic situation, the Group
has adequate resources to continue in operational existence throughout the
going concern period. Therefore, the directors continue to adopt the going
concern basis of accounting in preparing these consolidated financial
statements and the financial statements do not include the adjustments that
would result if the Group were unable to continue as a going concern.
1.3 Significant events and changes in the period
The financial performance and position of the Group was significantly affected
by the following events and changes during the year:
· Significant increase in revenue versus the prior year due to the
continued strong recovery in crude oil prices;
· Fully repaying the remaining $78,515,000 Convertible Bond debt plus
$1.5 million of accrued interest (note 5.1);
· An increase in the lease liabilities and right-of-use assets
relating to the Aoka Mizu FPSO resulting from a renegotiation of the bareboat
charter of the Aoka Mizu FPSO and increase in the lease term assumption
against a background of higher oil prices, consistent performance on Lancaster
and a change to the expected cessation of production (CoP) date from June 2024
to August 2025 (notes 2.3 and 5.2); and
· Impairments of intangible exploration and evaluation assets of $5.7
million following the decision to relinquish the Lincoln (P1368(S)) and
Warwick (P2294) licences during the period. The exploration and evaluation
assets within Halifax licence P2308 have been fully impaired in the year (note
2.4.1).
For further discussion about the Group's performance and financial position,
see the Chief Executive Officer's Review and Chief Financial Officer's Review.
1.4 Foreign currencies and translation
These consolidated Financial Statements are presented in US Dollars, which is
the Company's functional and presentation currency, and rounded to the nearest
thousand unless otherwise stated. The functional currency is the currency of
the primary economic environment in which the Group operates, as a significant
proportion of expenditure and all of its current revenue is priced in US
Dollars. All trading entities within the Group have a US Dollar functional
currency.
Transactions in foreign currencies are recorded at the rates of exchange
ruling at the transaction dates. Monetary assets and liabilities are
translated into US Dollars at the exchange rate ruling at the balance sheet
date, with a corresponding charge or credit to the Group Statement of
Comprehensive Income.
The principal rates of exchange used were:
US Dollar / Pounds Sterling 31 Dec 2022 31 Dec 2021
Year-end rate 1.21 1.35
Average rate 1.24 1.38
Upon disposal or liquidation of a subsidiary, any cumulative exchange
differences recognised in equity as a result of previous changes in the
functional currency of that subsidiary are recycled to the Group Statement of
Comprehensive Income .
1.5 New and amended standards adopted by the Group
The Group has applied new accounting standards, amendments and interpretations
for the first time:
· Property, Plant and Equipment: Proceeds before Intended Use -
Amendments to IAS 16
· Onerous Contracts - Cost of Fulfilling a Contract - Amendments to
IAS 37
· Annual Improvements to IFRS Standards 2018-2020, and
· Reference to the Conceptual Framework - Amendments to IFRS 3
The Group also applied the following amendments early:
· Disclosure of Accounting Policies - Amendments to IAS 1 and IFRS
Practice Statement 2.
The adoption of the changes and amendments above has not had any material
impact on the disclosure or on the amounts reported in the Financial
Statements, nor are they expected to significantly affect future periods.
1.6 New and amended accounting standards not yet adopted
A number of other new and amended accounting standards and interpretations
have been published that are not mandatory for the Group's financial year
ended 31 December 2022, nor have they been early adopted. These standards and
interpretations are not expected to have a material impact on the Group's
consolidated Financial Statements.
1.7 Critical accounting judgements and key sources of estimation uncertainty
In the application of the Group's accounting policies, the directors are
required to make judgements, estimates and assumptions about the carrying
amounts of assets and liabilities that are not readily apparent from other
sources. The estimates and associated assumptions are based on historical
experience and other factors that are considered to be relevant. Actual
results may differ from these estimates.
The estimates and underlying assumptions are reviewed on an ongoing basis.
Revisions to accounting estimates are recognised in the period in which the
estimate is revised if the revision affects only the period, or in the period
of the revision and future periods if the revision affects both current and
future periods.
The following are critical judgements, apart from those involving estimations
(which are dealt with separately below), that the directors have made in the
process of applying the Group's accounting policies and that have the most
significant effect on the amounts recognised in the Financial Statements:
· identification of impairment indicators for Lancaster field oil and
gas assets (note 2.3);
· identification of impairment indicators for intangible exploration
and evaluation assets (note 2.4);
· recognition of deferred tax assets (section 6);
· lease term of the Aoka Mizu FPSO (note 5.2); and
· quantum of decommissioning provision to be recognised (note 2.5)
The key assumptions concerning the future, and other key sources of estimation
uncertainty at the balance sheet date that may have a significant risk of
causing a material adjustment to the carrying amount of assets and liabilities
within the next financial year, are:
· estimated future cash flows of oil and gas assets used for
impairment testing (note 2.3)
· estimation of hydrocarbon Reserves and Contingent Resources
(section 2);
· estimation of future taxable profits against which to recognise
deferred tax assets (section 6).
The Convertible bond was repaid in full during the year and so there is no
longer considered to be a key source of estimation uncertainty contained in
the valuation of the Convertible bond embedded derivative (note 5.1) at 31
December 2022.
1.7.1 Impact of climate change and energy transition on critical judgements
and estimates
Climate change and the transition to a low carbon economy were considered in
preparing these consolidated Financial Statements. In particular, the energy
transition is likely to impact future oil and gas prices which in turn may
affect the recoverable amount of the Group's oil and gas assets. The estimate
of future cash flows from oil and gas assets, which includes management's best
estimate of future oil prices, is considered a key source of estimation
uncertainty. In developing these price assumptions, consideration was given to
a range of forecasts, including ones that were described as being consistent
with achieving the 2015 COP 21 Paris Agreement goal to limit temperature rises
to well below 2 degrees Celsius (the 'Paris compliant scenarios') and ones
based on pledges announced by governments to date. Further details of the key
assumptions in this area have been provided in note 2.3.1, including
sensitivity analysis outlining the impact on the impairment charge of using
higher or lower oil price assumptions to management's best estimate of oil
prices. The oil price forecast used in the impairment assessment (disclosed in
note 2.3.1) is estimated to be broadly aligned with forecasts consistent with
pledges announced by governments to date; however, under current forecasts and
with no further investment, the Group's oil and gas assets are likely to be
fully depreciated within three years, during which timeframe it is expected
that global demand for oil will remain robust. Accordingly, the impact of
climate change on expected useful lives of the Group's current assets is not
considered to be a significant judgement or estimate.
In addition to oil and gas assets, climate change could adversely impact the
future development or viability of exploration and evaluation (E&E)
prospects. The existence of impairment triggers for E&E assets is
considered a critical accounting judgement, with further details of
impairments recorded in the year and the amounts that remain capitalised at
year end provided in note 2.4.
Section 2. Oil and gas operations
Accounting policies applicable to this section as a whole
Commercial reserves
Commercial Reserves are proved and probable oil and gas Reserves, which are
defined as the estimated quantities of crude oil, natural gas and natural gas
liquids which geological, geophysical and engineering data demonstrate with a
specified degree of certainty to be recoverable in future years from known
reservoirs and which are considered to be economically viable. Proved and
probable reserve estimates are based on a number of underlying assumptions
including oil and gas prices, future costs, oil and gas in place and reservoir
performance, which are inherently uncertain. There should be a 50% statistical
probability that the actual quantity of Reserves will be more than the amount
estimated as proven and probable Reserves and a 50% statistical probability
that it will be less. However, the amount of Reserves that will be ultimately
recovered from any field cannot be known with certainty until the end of the
field's life.
Critical judgements and key sources of estimation uncertainty applicable to
this section
Key source of estimation uncertainty - estimation of hydrocarbon Reserves and
Contingent Resources
Hydrocarbon Reserves and Contingent Resources are those hydrocarbons that can
be economically extracted from the Group's oil and gas assets. The Group's
Reserves and Contingent Resources have been estimated based on information
compiled by independent qualified persons, using standard recognised
evaluation techniques. Inputs provided by management to the independent
qualified persons include geological and reservoir information (as updated
from data obtained through operation of a field), operating costs and
decommissioning estimates. These inputs are challenged by the independent
qualified persons and validated against analogue reservoirs, actual historical
reservoir and production performance, and the costs of running and
decommissioning similar fields and installations.
Changes to Reserves estimates may significantly impact the financial position
and performance of the Group. This could include a significant change in the
depreciation charge for oil and gas assets, provisions for decommissioning,
the results of any impairment testing performed and the recognition and
carrying value of any deferred tax assets.
The estimated quantity of remaining proved plus probable Reserves (2P
Reserves) at 31 December 2022 in respect of the Lancaster EPS was
independently assessed in March 2023 as being 6.6 MMbbl.
2.1 Revenue
Accounting policy
Revenue from contracts with customers is recognised when the Group satisfies
its performance obligation of transferring control of oil to a customer.
Transfer of control is usually concurrent with both transfer of title and the
customer taking physical possession of the oil, which is determined by
reference to the contract and relevant Incoterms. These performance
obligations are satisfied at a point in time.
The amount of revenue recognised is measured at the transaction price, which
is determined primarily by reference to quoted market prices at or around the
time of lifting. Where final pricing terms are only available after delivery
(e.g. using quoted prices or other information such as discharge quantity that
can only be determined after the time of sale), revenue is initially
recognised based on relevant prices at the time of sale on a provisional basis
and subsequently adjusted. This variable consideration element is deemed
highly probable not to result in a significant reversal of revenue as changes
in pricing arising from post-sale adjustments are resolved within a short
period of time following delivery and are not considered to be material.
All revenue is derived from contracts with customers and is comprised of only
one category and geographical location, being the sale of crude oil from the
Lancaster EPS. All sales were made to one external customer, being BP Oil
International Limited.
Year ended Year ended
31 Dec 2022 31 Dec 2021
$'000 $'000
Oil sales 310,776 240,540
Revenue from contracts with customers 310,776 240,540
Cargoes sold 6 7
Sales volumes (thousand bbl) 3,226 3,576
Average sales price realised ($/bbl) $96.3/bbl $67.3/bbl
2.2 Cost of sales and inventory
Accounting policy
Crude oil inventories
Crude oil inventories are held at the lower of cost and net realisable value.
The cost of crude oil is the cost of production, including direct labour and
materials, depreciation and an appropriate portion of fixed overheads
allocated based on normal operating capacity of the production facilities,
determined on a weighted average cost basis. Net realisable value of crude oil
is based on the market price of similar crude oil at the balance sheet date
and costs to sell, adjusted if the sale of inventories after that date gives
additional evidence about its net realisable value.
The cost of crude oil is expensed in the period in which the related revenue
is recognised.
For other inventories, cost is determined on a weighted average basis (for
fuel and chemicals) or a specific identification basis (for spares and
supplies), including the cost of direct materials and (where applicable)
direct labour and a proportion of overhead expenses. Items are classified as
spares and supplies inventory where they are either standard parts, easily
resalable or available for use on non-specific campaigns, and as oil and gas
assets or intangible exploration and evaluation assets where they are
specialised parts intended for specific projects. Net realisable value is
determined by an estimate of the price that could be realised through resale
or scrappage based on its condition at the balance sheet date.
Included within cost of sales are costs relating to emissions trading schemes.
Provision is made at the end of each period for the cost of allowances
required to cover carbon emissions made in the emission reporting period to
date. The estimated cost of allowances required is based on the weighted
average cost per unit of emissions expected to be incurred for the compliance
period, calculated as the carrying amount of any allowances held plus the cost
of meeting the expected shortfall (using the market price at the balance sheet
date), divided by the expected total number of units of emissions for the
compliance period. The provision is held on the Statement of Financial
Position within trade and other payables until settled by the delivery of
emissions certificates. Allowances granted free of charge are held at nil
cost, with any gain on sale of free allowances granted recognised at the time
of sale.
Cost of sales
Year ended Year ended
31 Dec 2022 31 Dec 2021
Note $'000 $'000
Operating costs 63,182 65,688
Depreciation of oil and gas assets - owned 2.3 55,212 94,200
Depreciation of oil and gas assets - leased 2.3 26,652 3,405
Movement in crude oil inventory 3,553 (10,622)
Variable lease payments 5.2 24,822 20,454
173,421 173,125
Inventory
31 Dec 2022 31 Dec 2021
$'000 $'000
Crude oil 9,760 13,313
Fuel and chemicals 3,590 2,124
Spares and supplies 13,080 12,051
26,430 27,488
The amount of crude oil inventory recognised as an expense in the year was
$142.7 million (2021: $140.6 million).
2.3 Oil and gas assets
Accounting policies
Oil and gas assets are stated at cost less accumulated depreciation and any
provision for impairment.
Oil and gas assets - cost
Oil and gas assets are accumulated generally on a field-by-field basis and
represent the cost of developing the commercial Reserves discovered and
bringing them into production, together with the intangible exploration and
evaluation asset expenditures incurred in finding commercial Reserves
transferred from intangible exploration and evaluation assets.
The cost of oil and gas properties also includes directly attributable staff
and related overhead expenditure, which is allocated via the Group's time
writing process, capitalised borrowing costs and the cost of provisions for
future restoration and decommissioning.
Right-of-use assets (leased assets) are initially measured at cost, which
comprises the initial measurement of the lease liability (see note 5.2), plus
any lease payments made prior to lease commencement, initial direct costs
incurred and the estimated cost of restoration or decommissioning, less any
lease incentives received. Right-of-use assets are presented within property,
plant and equipment on the Statement of Financial Position.
Oil and gas assets - depreciation
Oil and gas properties are depreciated from the commencement of production on
a unit-of-production basis. This is the ratio of oil production in the period
to the estimated Reserves base, which is the best estimate of proved plus
probable Reserves (2P Reserves), at the end of the period, plus the production
in the period. Costs used in the unit-of-production calculation comprise the
net book values of producing assets, taking into account future development
expenditures necessary to bring those Reserves into production. Where the
carrying value of oil and gas assets has been impaired by using an expected
cash flow approach, the equivalent expected future development costs and
expected Reserves and Contingent Resources base are taken into account when
determining the depreciation rate.
Impairment
An impairment test is performed whenever events and circumstances arising
during the development or production phase indicate that the carrying value of
an oil and gas property may exceed its recoverable amount.
The carrying value is compared against the expected recoverable amount of the
asset, generally by reference to the present value of the future net cash
flows expected to be derived from production of commercial Reserves. The
cash-generating unit applied for impairment test purposes is generally the
field, except that a number of field interests may be grouped as a single
cash-generating unit where the cash inflows of each field are interdependent.
Any impairment identified is charged to the Group Statement of Comprehensive
Income. Where conditions giving rise to an impairment subsequently reverse,
the effect of the impairment charge is also reversed as a credit to the Group
Statement of Comprehensive Income, net of any depreciation that would have
been charged since the impairment.
Leased Owned Total
Note $'000 $'000 $'000
Cost
At 1 January 2021 101,821 784,558 886,379
Additions − 4,572 4,572
Remeasurement of lease liability (18,212) − (18,212)
Changes to decommissioning estimates 2.5 1,961 1,514 3,475
At 31 December 2021 85,570 790,644 876,214
Additions − 8,785 8,785
Remeasurement of lease liability 5.2 75,897 − 75,897
Changes to decommissioning estimates (851) (1,520) (2,371)
At 31 December 2022 160,616 797,909 958,525
Depreciation and impairment
At 1 January 2021 (80,204) (598,148) (678,352)
Depreciation charge for the year (3,405) (94,200) (97,605)
Provision for impairment (1,961) − (1,961)
At 31 December 2021 (85,570) (692,348) (777,918)
Depreciation charge for the year (26,653) (55,212) (81,865)
Changes to decommissioning estimates expensed 851 − 851
At 31 December 2022 (111,372) (747,560) (858,932)
Carrying amount at 31 December 2021 − 98,296 98,296
Carrying amount at 31 December 2022 49,244 50,349 99,593
Oil and gas assets held under leases comprise solely the Aoka Mizu FPSO
bareboat charter, which commenced in May 2019. During 2021, this lease term
was reassessed, resulting in a decrease in the leased asset (including
decommissioning asset) value to nil. As the reduction of lease asset value in
2021 included reducing the decommissioning asset value to nil, changes to the
decommissioning estimates in the year of $(1.0) million have been expensed in
full resulting in $nil impact to the leased asset. On 25 March 2022, the Group
agreed an extension to the charter to cover the remaining economic life of the
Lancaster field (see note 5.2).
Included within the cost of owned oil and gas assets is $42.8 million of
capitalised borrowing costs (2021: $42.8 million)
The total amount of depreciation charged to oil and gas assets and other fixed
assets was $82.2 million (2021: $98.1 million).
2.3.1 Impairment of oil and gas assets
Critical judgement - identification of impairment indicators for oil and gas
assets
The asset balance relating to the Lancaster field held within property, plant
and equipment is subject to an impairment assessment under IAS 36 'Impairment
of Assets', whereby the Group is required to consider if there are any
indicators of impairment. The judgement as to whether there are any indicators
of impairment takes into consideration a number of internal and external
factors, including: changes in estimated commercial Reserves; significant
adverse changes to production versus previous estimates of management; changes
in estimated future oil and gas prices; changes in estimated future capital
and operating expenditure to develop and produce commercial Reserves; the
market capitalisation of the Group falling and remaining significantly below
the net book value of assets; and any indications that discount rates likely
to be applied by market participants in assessing the asset's recoverable
amount may have increased.
If an impairment indicator exists, an impairment test, which compares carrying
value to the asset's recoverable amount (being the higher of value in use and
fair value less cost to sell), is required to be carried out.
Critical judgements and key source of estimation uncertainty - estimated
future cash flows of oil and gas assets used for impairment testing
The Group assesses its assets and cash-generating units (CGUs) in each
reporting period to determine whether any indicators of impairment exist.
Where indicators exist, a formal impairment test is undertaken to estimate the
recoverable amount (which is the higher of fair value less costs of disposal
(FVLCD) and value in use (VIU)). For the Lancaster field, the recoverable
amount was based on VIU.
In making these estimates, a judgement has been made that the agreement on 25
March 2022 for the extension to the Aoka Mizu lease will allow Lancaster EPS
operations to continue until such time as the estimated economic limit is
reached (August 2025 based on the forecasts for production, oil price and
operating costs).
These estimates and assumptions are subject to significant risk and
uncertainty, and therefore changes to external factors and internal
developments and plans can significantly impact these projections, which could
lead to additional impairments or reversals in future periods. Sensitivity
analysis to some of these estimates and assumptions are outlined below.
The trigger for the impairment test was the comparison of net assets of the
Group at 31 December 2022 versus the market value of the Group based on the
share price on that date. The recoverable amount was determined based on
management's best estimate of value in use, using key assumptions, judgements
and estimates as outlined below.
The key assumptions used within each cash flow projection are based on best
estimates using past experience, latest internal technical analysis and
external factors, and include:
· production forecasts in line with those included in the 2023 ERCE
CPR as published on the Company's website at www.hurricaneenergy.com; and
· Dated Brent oil price assumptions (in real terms) of $82/bbl
average for 2023, $77/bbl in 2024 and $74/bbl in 2025 (being forecasts of
future oil prices extant as at 31 December 2022, as required by IAS 36);
· operating cost assumptions based on latest budgets, contracts and
information from key suppliers;
· the extension to the Aoka Mizu FPSO charter agreed on 25 March 2022
will allow production to continue until August 2025 (being the estimated
economic limit for the P6 well alone based on the forecasts for production,
oil price and operating costs as outlined above), and an assumption that
neither party exercises their respective termination option that would result
in an end to the charter prior to that point; and
· a pre-tax real discount rate of 8.0%.
These estimates and assumptions are subject to risk and uncertainty, and
therefore changes to external factors and internal developments and plans have
the ability to significantly impact these projections, which could lead to
additional impairments or future reversals in future periods.
The results of the impairment test were that no impairment charge was
necessary.
The estimated impairment charge that would be recognised as a result of
changes to some of these key estimates and assumptions made (in isolation) is
as follows:
Impairment charge
$m
Oil price assumption:
$5/bbl decrease to price curve
-
$10/bbl decrease to price curve -
Forecast production rates:
5% decrease -
10% decrease -
Cessation of production and FPSO charter end date
October 2023 32.0
December 2023 17.8
The sensitivities disclosed are considered in isolation and a result of
changing only one variable.
A $10/bbl decrease to the forecast oil price is considered to be reasonably
possible based on oil price volatility, and a 10% decrease to forecast
production rates are considered to be reasonably possible based on experienced
uptime and production levels.
2.4 Intangible exploration and evaluation assets
Accounting policy
The Group follows the successful efforts method of accounting for oil and gas
exploration and evaluation activities (intangible exploration and evaluation
assets) as permitted by IFRS 6 'Exploration for and Evaluation of Mineral
Resources'.
Pre-licence costs, which relate to costs incurred prior to having obtained the
legal right to explore an area, are charged directly to the Group Statement of
Comprehensive Income within operating expenses as they are incurred.
Once a licence has been awarded, all licence fees and exploration and
appraisal costs relating to that licence are initially capitalised in well,
field or specific exploration cost centres as appropriate pending
determination. These costs include directly attributable staff and related
overhead expenditure, which is allocated to assets via the Group's timewriting
process. Expenditure incurred during the various exploration and appraisal
phases is then written off unless commercial Reserves have been established or
the determination process has not been completed.
When commercial Reserves have been found and a field development plan has been
approved, the net capitalised costs incurred to date in respect of those
Reserves are transferred into a single field cost centre and reclassified as
oil and gas properties within property, plant and equipment (subject to an
impairment test before reclassification). Subsequent development costs in
respect of the Reserves are capitalised within oil and gas properties.
If there are indicators of impairment (examples of which include the
surrender, expiry or expected non-renewal of a licence; a lack of planned or
budgeted substantive expenditure for a particular field; insufficient
commercially viable Reserves resulting in a discontinuation of development;
and data existing which indicates that the carrying amount of an asset is
unlikely to be fully recovered either from successful development or sale), an
impairment test is performed comparing the carrying value with its recoverable
amount, being the higher of value in use (calculated as the estimated
discounted future cash flows based on management's expectations of future oil
and gas prices, production and costs) and its estimated fair value less costs
to sell. Capitalised costs which are subsequently written off are classified
as operating expenses.
The Group may enter into farm-out arrangements, whereby it assigns an interest
in Reserves and future production to another party (the farmee). For farm-outs
of assets that are in the exploration and evaluation stage, the Group does not
recognise any consideration in respect of the farmee's committed or expected
carry but continues to hold its remaining interest at the previous cost of the
full interest, less any cash consideration received from the farmee upon
entering the arrangement.
Year ended Year ended
31 Dec 2022 31 Dec 2021
Note $'000 $'000
At 1 January 3,830 55,390
Additions 1,878 5,235
Provision for impairment and exploration expenditure written off 2.4.1 (5,705) (54,280)
Changes to decommissioning estimates 2.5 (3) (2,515)
At 31 December − 3,830
Intangible exploration and evaluation assets represent the Group's share of
the cost of licence interests and exploration and evaluation expenditure
within its remaining Halifax licence (P2308) in the West of Shetland area,
following the relinquishment of Lincoln (licence P1368(S)) and Warwick
(licence P2294). The exploration and evaluation assets within Halifax licence
P2308 have been fully impaired in the year.
Additions during the period primarily comprised licence fees, geological and
other subsurface studies undertaken, and capitalised time writing costs.
2.4.1 Impairment and write-off of intangible exploration and evaluation assets
Critical judgement - identification of impairment indicators for intangible
exploration and evaluation assets
Intangible exploration and evaluation assets are assessed for impairment when
circumstances suggest that the carrying amount may exceed its recoverable
value. This judgement is made with reference to the impairment indicators
outlined in note 2.4 above.
The directors have fully considered and reviewed the potential value of
licence interests, including carried forward exploration and evaluation
expenditure. The directors have considered the Group's tenure to its licence
interests, its plan for further exploration and evaluation activities in
relation to these and the likely opportunities for realising the value of the
Group's licences, either by farm-out or by development of the assets.
An impairment charge of $0.1 million has been recognised against the full
carrying amount of exploration and evaluation expenditure attributable to the
Halifax asset on licence P2308 as the 2022 CPR did not attribute any Reserves
or Contingent Resources to Halifax, and the Group has no plans or budgets for
substantive expenditure on further exploration or evaluation on this licence.
An impairment charge of $5.6 million has been recognised against the full
carrying amount of exploration and evaluation expenditure attributable to the
Greater Warwick Area (GWA) comprising the Lincoln asset (licence P1368(S)) and
the Warwick asset (licence P2294) both of which have now been relinquished.
2.5 Decommissioning provisions
Accounting policy
Provisions for decommissioning are recognised in full when wells have been
suspended or facilities have been installed. A corresponding amount equivalent
to the provision is also recognised as part of the cost of either the related
oil and gas exploration and evaluation asset or property, plant and equipment
as appropriate. The amount recognised is the estimated cost of
decommissioning, discounted to its net present value, and is reassessed each
year in accordance with local conditions and requirements. Changes in the
estimated timing of decommissioning or decommissioning cost estimates are
dealt with prospectively by recording an adjustment to the provision, and a
corresponding adjustment to the related asset. Where the related asset is
fully impaired, the corresponding adjustment is recognised in profit and loss.
The unwinding of the discount on the decommissioning provision is classified
within finance costs.
Year ended Year ended
31 Dec 2022 31 Dec 2021
Note $'000 $'000
At 1 January 49,346 61,141
Net new provisions and changes in estimates (2,557) (1,921)
Utilised in year (277) (9,894)
Unwinding of discount 3.2 545 20
At 31 December 47,057 49,346
Of which:
Current − -
Non-current 47,057 49,346
47,057 49,346
Restricted funds held in respect of decommissioning:
Restricted cash 4.1 40,594 -
Liquid investments 4.1 − 37,783
40,594 37,783
The provisions for decommissioning relate to the costs required to
decommission the Lancaster EPS installations and the costs required to clean,
remove and restore the Aoka Mizu FPSO at the end of the charter term. The
decommissioning provision has been classified as non-current in line with the
assumptions made for impairment testing of oil and gas assets, which assumes a
cessation of production of the Lancaster field and expected incurrence of
decommissioning costs in August 2025; being the estimated point at which the
EPS becomes uneconomic absent any incremental development (2021: June 2024).
Estimated costs are discounted at a rate of 3.58% and an annual inflation rate
of 6.35% has been assumed.
Changes in estimates in the period have arisen from a change to the expected
cessation of production date, changes in the assumed discount rate, changes in
foreign exchange rates and increases to the assumed inflation rate.
Of the total net new provisions and changes in estimates, $1.52 million was
recorded as non-cash reductions to oil and gas assets, and $1.04 million
charged directly to the Group Statement of Comprehensive Income (as they
related to changes in estimates on fully impaired assets and right-of-use
assets).
The utilisation of provisions during the period related to the final costs
associated with the plugging and abandonment of the Lincoln-14 well, and the
Lancaster 4Z wells which were undertaken in 2021.
2.6 Joint operations
In September 2018 the Group entered into a joint operation with Spirit to
share costs and risks associated with GWA in exchange for granting Spirit a
50% interest in the Group's P1368(S) and P2294 licences. The phased work
programme was intended to comprise a planned tie-back of a GWA well to the
Aoka Mizu FPSO, together with host modifications to the vessel and a gas
export tie-in to the West of Shetland Pipeline System (WOSPS). Hurricane was
fully carried up to a gross cost of $180.6 million for the first phase of this
activity, with costs in excess of the carry amount having been shared on a
50:50 basis.
With effect from 6 March 2020, a new cost allocation framework was implemented
whereby the joint operation builds-out only the equipment and materials
required to for a single-well tie-back to the Aoka Mizu FPSO. These long-lead
items are currently being held in storage. As part of this framework, the
Group can elect to continue to build-out long-lead items related to the tie-in
of the Aoka Mizu FPSO to the WOSPS on a sole risk basis as part of GLA
activities.
In H1 2022 the joint operation agreed to surrender the Lincoln (P1368(S)) and
the Warwick (P2294) licences. The P1368(S) licence was relinquished on 11 July
2022, and the P2294 licence was relinquished on 18 July 2022. Before the joint
operation is formally concluded, there remain a number of operational and
administrative matters to complete. The Group currently acts as operator of
the joint operation and will continue to do so until these matters are
concluded.
Amounts due from and to the joint operation partner are shown in notes 4.2 and
4.3 respectively.
Further details on the activities and progress of the joint operation are
described in the Strategic Report.
2.7 Capital Commitments
As at the balance sheet date, the Group had the following outstanding
contractual and other commitments:
31 Dec 2022 31 Dec 2021
$'000 $'000
Contractual commitments in respect of oil and gas assets 490 1,201
Contractual commitments in respect of exploration and evaluation assets 26 821
Commitments shown above are net of amounts expected to be funded by the
Group's joint operation partner.
Section 3. Group Statement of Comprehensive Income
3.1 Earnings per share
Year ended Year ended
31 Dec 2022 31 Dec 2021
$'000 $'000
Profit attributable to holders of Ordinary Shares in the Company used in 108,661 18,236
calculating basic earnings per share (being profit after tax)
Add back impact of:
Convertible Bond - interest expense − -
Convertible Bond - fair value gain − -
Profit attributable to holders of Ordinary Shares in the Company used in 108,661 18,236
calculating diluted earnings per share
Number Number
Weighted average number of Ordinary Shares used in calculating basic earnings 1,990,423,900 1,989,927,148
per share
Potential dilutive effect of:
Convertible Bond − -
Weighted average number of Ordinary Shares and potential Ordinary Shares used 1,990,423,900 1,989,927,148
in calculating diluted earnings per share
Cents Cents
Basic earnings per share 5.46 0.92
Diluted earnings per share 5.46 0.92
In 2022 and 2021, the potential impact of the conversion feature included
within the Convertible Bond was antidilutive as their conversion to Ordinary
Shares would have increased earnings per share. At 31 December 2022 the
Convertible Bonds had been fully repaid.
The inclusion of contingently issuable shares in the calculation of diluted
earnings per share had no impact due to the immaterial quantum of awards
outstanding at 31 December 2022.
3.2 Finance income and costs
Year ended Year ended
31 Dec 2022 31 Dec 2021
$'000 $'000
Interest income on cash, cash equivalents and liquid investments 1,174 27
Net foreign exchange gains − -
Finance income 1,174 27
Convertible Bond interest expense (note 5.1) (5,558) (24,810)
Interest on lease liabilities (note 5.2) (3,873) (4,412)
Other interest expense and bank charges (476) (217)
Net foreign exchange losses (5,171) (1,197)
Unwinding of discount on decommissioning provisions (note 2.5) (545) (20)
Finance costs (15,623) (30,656)
Net finance costs (14,449) (30,629)
3.3 General and administrative expenditure
Year ended Year ended
31 Dec 2022 31 Dec 2021
$'000 $'000
Wages and salaries 7,699 9,939
Social security costs 1,034 1,226
Defined contribution pension costs 410 689
Staff costs 9,143 11,854
Non-staff costs 7,293 22,958
Gross general and administrative expenditure before recharges 16,436 34,812
Capitalised into oil and gas assets (2,229) (3,025)
Capitalised into intangible exploration and evaluation assets 648 (3,456)
Included within cost of sales (6,109) (4,752)
Net general and administrative expenditure before non-cash items 8,746 23,579
Non-cash general and administrative costs:
Net share-based payment charge 289 1,956
Depreciation of other fixed assets and other right-of-use assets 320 495
Impairment of other right of use assets − 719
General and administrative expenditure 9,355 26,749
Number Number
Average number of employees 34 55
Details of directors' remuneration are provided in the Remuneration Report
(note 7.3)
3.4 Share Based Payments
Accounting policy
The Share Incentive Plan (SIP) Trust is a separately administered
discretionary trust whose assets mainly comprise shares in the Company. Own
shares held by the SIP Trust are deducted from shareholders' funds and held at
historical cost until they are sold to employees to satisfy share incentive
plans. The assets, liabilities, income and costs of the SIP Trust are included
in both the Company's and the consolidated Financial Statements.
During 2022 the Group operated a share-based payment plan being the Company's
HMRC-approved SIP. The Group recognised a total charge of $0.3 million in
respect of share-based payments in 2022.
During 2021, the Group operated a number of share-based payment plans,
including several Performance Share Plans (PSPs), the Value Creation Plan
(VCP) and the Company's HMRC-approved SIP. The Group recognised a total charge
of $2.0 million in respect of share-based payments in 2021. All PSP awards
lapsed unvested in November 2021 and all VCP awards lapsed unexercised upon
expiry in November 2021, and therefore there were no performance-based share
awards or options outstanding at 31 December 2021.
Section 4. Cash, working capital and financial instruments
Accounting policies applicable in general to this section
Financial assets and financial liabilities are recognised on the Group's
Statement of Financial Position when the Group becomes party to the
contractual provisions of the instrument.
Fair value
Fair value is the price that would be received to sell an asset or paid to
transfer a liability in an orderly transaction between market participants at
the measurement date. All assets and liabilities, for which fair value is
measured or disclosed in the Financial Statements, are categorised within the
fair value hierarchy, described as follows, based on the lowest-level input
that is significant to the fair value measurement as a whole:
Level 1 - quoted (unadjusted) market prices in active markets for identical
assets or liabilities;
Level 2 - valuation techniques for which the lowest-level input that is
significant to the fair value measurement is directly or indirectly
observable; and
Level 3 - valuation techniques for which the lowest-level input that is
significant to the fair value measurement is unobservable.
Financial assets
Financial assets are initially recognised at fair value, and subsequently
measured at amortised cost, less any allowances for losses using the expected
credit loss model, being the difference between all contractual cash flows
that are due to the Group in accordance with the contract and all the cash
flows that the Group expects to receive.
Financial liabilities
Financial liabilities are classified as either financial liabilities at fair
value through profit and loss (FVTPL) or as other financial liabilities. The
Group derecognises financial liabilities when, and only when, the Group's
obligations are discharged or cancelled, or they expire. Upon derecognition,
the difference between the consideration paid to extinguish the liability and
the carrying value of the liability at time of derecognition is recognised as
a gain in the Group Statement of Comprehensive Income , net of any direct
transaction costs.
Financial liabilities are classified at FVTPL when the financial liability is
either held for trading or it is designated at FVTPL. A financial liability is
classified as held for trading if it has been incurred principally for the
purpose of repurchasing it in the near term or is a derivative that is not a
designated or effective hedging instrument.
Financial liabilities at FVTPL are measured at fair value, with any gains or
losses arising on changes in fair value recognised in profit or loss. The net
gain or loss recognised in profit or loss incorporates any interest paid on
the financial liability.
Other financial liabilities, including borrowings, are initially measured at
fair value, net of transaction costs and are subsequently measured at
amortised cost using the effective interest method, with interest expense
recognised on an effective yield basis.
The effective interest method is a method of calculating the amortised cost of
a financial liability and of allocating interest expense over the relevant
period. The effective interest rate is the rate that exactly discounts
estimated future cash payments through the expected life of the financial
liability, or, where appropriate, a shorter period, to the net carrying amount
on initial recognition.
Derivatives (other than embedded derivatives)
Derivatives are initially recognised at fair value at the date a derivative
contract is entered into and are subsequently remeasured to their fair value
at each balance sheet date. The resulting gain or loss is recognised in the
Group Statement of Comprehensive Income immediately. The Group does not
currently designate any derivatives as hedging instruments.
A derivative with a positive fair value is recognised as a financial asset
whereas a derivative with a negative fair value is recognised as a financial
liability. A derivative is presented as non-current if the remaining maturity
of the instrument is more than 12 months and it is not expected to be realised
or settled within 12 months.
Other derivatives are presented as current assets or current liabilities.
4.1 Cash and cash equivalents and liquid investments
Accounting policy
Cash includes cash on hand and cash with banks and financial institutions.
Cash equivalents are short-term, highly liquid investments that are readily
convertible to known amounts of cash with three months or less remaining to
maturity from the date of acquisition and that are subject to an insignificant
risk of change in value.
Liquid investments are defined as short-term investments in fixed-term deposit
accounts of between 3- and 12-months' maturity.
Cash and cash equivalents, and liquid investments, include amounts held in
escrow or other reserved accounts that are contractually restricted to be used
only for certain payments or transactions, and where the approval process for
release of those funds is perfunctory, e.g. for dispersal to certain
independent third parties for work undertaken as part of the Group's
operations. Such amounts are classified as non-current if the payment or
transaction is not expected to be realised or settled within 12 months.
31 Dec 2022 31 Dec 2021
Restricted Unrestricted Total Restricted Unrestricted Total
$'000 $'000 $'000 $'000 $'000 $'000
Current cash and cash equivalents − 138,383 138,383 7,934 68,858 76,792
Non-current cash and equivalents 60,754 − 60,754 - - -
Cash and cash equivalents (per Cash Flow Statement) 60,754 138,383 199,137 7,934 68,858 76,792
Liquid investments − − − 37,783 - 37,783
Total cash and cash equivalents and liquid investments 60,754 138,383 199,137 45,717 68,858 114,575
The carrying amounts of cash and cash equivalents and liquid investments are
considered to be materially equivalent to their fair values.
The movement in restricted and unrestricted cash, cash equivalents and liquid
investments is as follows:
Year ended 31 Dec 2022 Year ended 31 Dec 2021
Restricted Unrestricted Total Restricted Unrestricted Total
$'000 $'000 $'000 $'000 $'000 $'000
At 1 January 45,717 68,858 114,575 51,603 114,911 166,514
Operating cash flows 206,688 206,688 - 147,970 147,970
Change in Lancaster EPS decommissioning security arrangements 7,749 (7,749) − 15,530 (15,530) -
Capital expenditure and other investing cash flows - (15,095) (15,095)
− (4,614) (4,614)
Financing cash flows − (110,786) (110,786) - (183,562) (183,562)
Movement in FPSO early termination reserve 12,226 (12,226) − (18,670) 18,670 -
Net release of other restricted funds − − − (2,244) 2,244 -
Foreign exchange rate changes (4,938) (1,788) (6,726) (502) (750) (1,252)
At 31 December 60,754 138,383 199,137 45,717 68,858 114,575
Included within restricted cash, cash equivalents and liquid investments is
$20.2 million (2021: $7.9 million) set aside in relation to the Aoka Mizu FPSO
bareboat charter. This amount was established and classified as restricted
cash following the agreement in March 2022 to extend the FPSO lease. Under the
terms of the contract, the Group is required to ring-fence amounts to ensure
it could meet its liability to the lessor if the contract is terminated by the
Group or the lessor. The $20.2 million amount consists of an original amount
of $18.7million originally agreed with the lessor on extension of the lease in
March 2022, with an additional $1.5 million subsequently being agreed to be
set aside.
Also in restricted cash, cash equivalents and liquid investments is $40.6
million decommissioning security for the Lancaster EPS (2021: $37.8 million).
4.2 Trade and other receivables
31 Dec 2022 31 Dec 2021
$'000 $'000
Amounts due from joint operation partner -- 813
Trade receivables 1,420 423
Prepayments 1,130 1,058
Other receivables 1,125 297
3,675 2,591
The carrying amounts of trade and other receivables are considered to be
materially equivalent to their fair values and are unsecured. Joint operation
receivables represent amounts which will be recovered from the Group's joint
operation partner. Amounts billed to the joint operation partner accrue
interest at LIBOR/SONIA and are generally due for settlement within ten days
of being invoiced.
4.3 Trade and other payables
31 Dec 2022 31 Dec 2021
$'000 $'000
Amounts owed to joint operation partner 1,407 -
Trade payables 352 2,915
Other payables 260 351
Accruals 13,868 15,577
15,887 18,843
The carrying amounts of trade and other payables are considered to be
materially equivalent to their fair values and are unsecured. Trade and other
payables are non-interest bearing and generally payable within 30 days.
Trade and other payables and accruals include the Group's share of joint
operation payables, including amounts that the Group settles on behalf of
joint operation partners.
Amounts owed to joint operating partner includes expenditure of $1.5 million
relating to joint operations incurred by the Group as operator which have yet
to be paid to joint operation partners and which has been classified as
"Impairment of intangible exploration and evaluation assets and exploration
expense written off" in the Statement of Comprehensive Income.
4.4 Financial risk management
The Group monitors and manages the financial risks relating to its operations
on a continual basis. These include market risk, liquidity risk and credit
risk.
The Group does not enter into or trade financial instruments, including
derivatives, for speculative purposes. Other than the financial instruments
referred to below, the Group's significant financial instruments are cash and
cash equivalents (note 4.1), financial trade and other payables (note 4.3),
financial trade and other receivables (note 4.2) and its Convertible Bond debt
(note 5.1).
The Group considers the carrying value of all its financial assets and
liabilities to be materially the same as their fair value.
4.4.1 Market risk
Market risk is the risk that the fair value or future cash flows of a
financial instrument will fluctuate because of changes in market prices.
Market risk comprises foreign exchange, interest rate and other commodity
price risk.
Foreign currency risk
Foreign currency risk is the risk that fair value or future cash flows of a
financial instrument will fluctuate because of changes in foreign exchange
rates.
The Group undertakes transactions denominated in currencies other than its
functional currency (which is the US Dollar). For transactions denominated in
Pounds Sterling, the Group manages this risk by holding Sterling against
actual or expected Sterling commitments to act as an economic hedge against
exchange rate movements. From time to time, the Group enters into foreign
exchange swaps to hedge specific future payments in other currencies; no such
swaps were entered into or matured in the current or prior year. The Group has
not designated any financial instruments as hedging instruments or hedged
items.
The Group's cash and cash equivalents are mainly held in US Dollars and Pounds
Sterling. At 31 December 2022, 54% of the Group's cash and cash equivalents
and liquid investments were held in US Dollars (2021: 40%).
A 10% decrease in the strength of Sterling against the US Dollar would cause
an estimated decrease of $8.2 million (2021: $5.3 million increase) on the
profit after tax of the Group for the year ended 31 December 2022, with a 10%
strengthening causing an equal and opposite increase. The impact on equity is
the same as the impact on profit after tax. The exposure to other foreign
currency exchange movements is not material. This sensitivity analysis
includes the impact of retranslating foreign currency denominated monetary
items at the balance sheet date, and assumes all other variables remain
unchanged. Whilst the effect of any movement in exchange rates upon revaluing
foreign currency denominated monetary items is charged or credited to the
Group Statement of Comprehensive Income, the economic effect of holding Pounds
Sterling against actual or expected commitments in Pounds Sterling is an
economic hedge against exchange rate movements.
Interest rate risk
Interest rate risk is the risk that the fair value of future cash flows of a
financial instrument will fluctuate because of changes in market interest
rates.
The Group is exposed to interest rate movements through its cash and cash
equivalents and liquid investments which earn interest at variable interest
rates.
For the year ended 31 December 2022, a 1% increase in interest rates would
have increased the Group's profit after tax by approximately $2.0 million, and
a 0.5% decrease would have reduced the Group's profit after tax by
approximately $1.0 million, assuming that the amount of cash and cash
equivalents at the balance sheet date had been in place for the whole year.
The impact on equity would be the same as the impact on profit after tax.
Other price risk - commodity price risk
Commodity risk primarily arises from the sale of crude oil from the Lancaster
EPS, as the price realised from the sale of crude oil is determined primarily
by reference to quoted market prices in the month of lifting. Crude oil price
risk is partially mitigated by a proportion of cost of sales (variable lease
payments) being linked to the price of crude oil sold.
The Group enters into other commodity contracts (such as purchases of carbon
emission allowances, fuel and chemicals) in the normal course of business,
which are not derivatives, and are recognised at cost when the transactions
occur.
4.4.2 Liquidity risk
Liquidity risk is the risk that the Group will encounter difficulty in meeting
obligations associated with its financial liabilities that are settled by
delivering cash or other financial assets.
Financial liabilities of the Group comprise trade payables (note 4.3), lease
liabilities (note 5.2) and the Convertible Bond (note 5.1). The maturity
analysis of financial liabilities is shown in note 5.3.
The Group manages its liquidity risk by maintaining adequate cash and cash
equivalents where possible to cover its liabilities as and when they fall due.
Methods of achieving this include utilising receivable bank letters of credit
to accelerate receipt of cash due from crude oil sales (accelerating from
standard payment terms to receipt within two to three working days after
lifting), and cash calling amounts in advance from joint operation partners if
required.
4.4.3 Credit risk
Credit risk is the risk that the Group will suffer a financial loss as a
result of another party failing to discharge an obligation and arises from
cash and other liquid investments deposited with banks and financial
institutions, receivables from the sale of crude oil, and receivables
outstanding from its joint operation partner.
Customers, banks and joint operation partners are subject to risk assessments
using due diligence tools, credit reference agencies, and other publicly
available information with regular monitoring to determine if the level of
credit risk has changed. For deposits lodged at banks and financial
institutions, only those parties with at least investment grade credit ratings
assigned by an international credit rating agency are accepted. Similarly,
where the Group enters into arrangements involving letters of credit to
accelerate the receipt of cash from sales of crude oil, only banks with at
least investment grade credit ratings are used.
The carrying value of cash and cash equivalents and trade and other
receivables represents the Group's maximum exposure to credit risk at year
end. The Group has no material financial assets that are past due.
Section 5. Capital and debt
5.1 Convertible Bond
Accounting policies
Debt and equity instruments are classified as either financial liabilities or
as equity in accordance with the substance of the contractual arrangement.
An equity instrument is any contract that evidences a residual interest in the
assets of an entity after deducting all of its liabilities. Equity instruments
issued by the Group are recognised at the proceeds received, net of direct
issue costs.
Where warrants are granted in conjunction with other equity instruments, which
themselves meet the definition of equity, they are recorded at their fair
value, which is measured using an appropriate valuation model. Warrants which
do not meet the definition of equity are classified as derivative financial
instruments.
The component parts of compound instruments, such as Convertible bonds, issued
by the Group are classified separately as financial liabilities and equity in
accordance with the substance of the contractual arrangement.
If the conversion feature of a Convertible bond issued does not meet the
definition of an equity instrument, that portion is classified as an embedded
derivative and measured accordingly. The debt component of the instrument is
determined by deducting the fair value of the conversion option at inception
from the fair value of the consideration received for the instrument as a
whole. The debt component amount is recorded as a financial liability on an
amortised cost basis using the effective interest rate method until
extinguished upon conversion or at the instrument's maturity date.
Where debt instruments issued by the Group are repurchased for cancellation,
the financial liability is derecognised at the point at which cash
consideration is settled. Upon derecognition, the difference between the
liability's carrying amount that has been cancelled and the consideration paid
is recognised as a gain in the Group Statement of Comprehensive Income, net of
any direct transaction costs.
Embedded derivatives
Derivatives embedded in financial instruments or other host contracts that are
not financial assets are treated as separate derivatives when their risks and
characteristics are not closely related to those of the host contracts and the
host contracts are not measured at FVTPL. Derivatives embedded in financial
instruments or other host contracts that are financial assets are not
separated; instead, the entire contract is accounted for either at amortised
cost or fair value as appropriate.
An embedded derivative is presented as non-current if the remaining maturity
of the compound instrument to which the embedded derivative relates is more
than 12 months and is not expected to be realised or settled within 12 months.
Borrowing costs
Borrowing costs directly relating to the construction or production of a
qualifying capital project under construction are capitalised and added to the
project cost during construction until such time as the assets are
substantially ready for their intended use, i.e. when they are capable of
commercial production. The amount of borrowing costs eligible to be
capitalised is reduced by an amount equivalent to any interest income received
on temporary reinvestment of those borrowings.
In July 2017 the Group raised $230 million (gross) from the successful
placement of the Convertible Bond. The Convertible Bond was issued at par and
carried a coupon of 7.5% payable quarterly in arrears. The Convertible Bond
was convertible into fully paid Ordinary Shares with the initial conversion
price set at $0.52, representing a 25% premium above the placing price of the
concurrent equity placement, being £0.32 (converted into US Dollars at a
USD/GBP rate of 1.30). The number of potential Ordinary Shares that could be
issued if all the Convertible Bonds were converted was 442,307,692 (assuming
conversion at the initial conversion price of $0.52). The impact of these
potential Ordinary Shares on diluted earnings per share is shown in note 3.1.
During 2021, the Group repurchased $151.5 million of nominal Convertible Bonds
debt for cash consideration of $131.9 million, including accrued interest of
$1.6 million.
On 25 July 2022, the Group repaid in full the outstanding $78.5 million 7.50
per cent Convertible Bonds plus $1.5 million of accrued interest by the
maturity date of 24 July 2022. The bonds have now been delisted from The
International Stock Exchange and have been cancelled.
The amounts recognised in the Financial Statements related to the Convertible
Bond (which, together with leases as disclosed in note 5.2, are the Group's
liabilities arising from financing activities) are as follows:
Debt component Derivative component Total
$'000 $'000 $'000
Carrying value at 1 January 2021 216,034 885 216,919
Cash interest paid (17,372) - (17,372)
Cash consideration for repurchase of Convertible Bond principal (130,346) - (130,346)
Gain on repurchase (15,753) (2,759) (18,512)
Fair value loss - 1,901 1,901
Interest charged 24,810 - 24,810
Carrying value at 31 December 2021 77,373 27 77,400
Repayment of principal (78,515) - (78,515)
Cash interest paid (4,416) - (4,416)
Fair value gain - (27) (27)
Interest charged 5,558 - 5,558
Carrying value at 31 December 2022 - - -
Fair value at 31 December 2021 75,449 27 75,476
Fair value at 31 December 2022 - - -
5.2 Leases
Accounting policy
The Group enters into leases of property, equipment and oil exploration,
development and production assets. The most significant leases are the
bareboat charter of the Aoka Mizu FPSO, which commenced in May 2019, and the
leases of various office properties.
Lease liabilities are initially measured at the present value of lease
payments unpaid at the commencement date. Lease payments are discounted using
the incremental borrowing rate (being the rate that the lessee would have to
pay to borrow the funds necessary to obtain an asset of similar value in a
similar economic environment with similar terms and conditions), unless the
rate implicit in the lease is available. The Group currently uses the
incremental borrowing rate as the discount rate for all leases. For the
purposes of measuring the lease liability, lease payments comprise fixed
payments and variable lease payments based on an index or rate.
Right-of-use assets are measured at cost, which comprises the initial
measurement of the lease liability, plus any lease payments made prior to
lease commencement, initial direct costs incurred and the estimated cost of
restoration or decommissioning, less any lease incentives received. The Aoka
Mizu FPSO right-of-use asset is depreciated on a unit-of-production basis, the
Reserves base of which is proved plus probable Reserves (2P Reserves), as
estimated as being recoverable over the assessed lease term. Other
right-of-use assets are depreciated over the lease term (or useful life, if
shorter). Right-of-use assets are subject to an impairment test if events and
circumstances indicate that the carrying value may exceed the recoverable
amount.
Lease repayments made are allocated to capital repayment and interest so as to
produce a constant periodic rate of interest on the remaining lease liability
balance.
Right-of-use assets are presented within property, plant and equipment. Lease
liabilities are presented as separate line items on the face of the Statement
of Financial Position. In the Cash Flow Statement, lease repayments (of both
the principal and interest portions) are presented within cash used in
financing activities, except for payments for leases of short-term and
low-value assets and variable lease payments, which are presented within cash
flows from operating activities or cash used in investing activities in
accordance with the relevant Group accounting policy.
Leases of low-value items (such as office equipment) and short-term leases
(where the lease term is 12 months or less, which include the rental of
drilling rigs) are expensed on a straight-line basis to the Group Statement of
Comprehensive Income or capitalised into intangible exploration and evaluation
assets and/or oil and gas assets in accordance with the relevant Group
accounting policy. Variable lease payments linked to the sale of crude oil are
recognised within cost of sales when the associated sale occurs.
The Group does not have any activities as a lessor.
Critical judgement - lease term of the Aoka Mizu
On 25 March 2022, the Group announced that it had signed a contract with
Bluewater, for an extension to the Bareboat Charter beyond the previous expiry
date of 4 June 2022. Judgement has been applied to determine the lease term of
the Aoka Mizu FPSO bareboat charter as the contract includes the option for
either party to give six months notice to terminate the charter. The contract
is a rolling, evergreen contract so does not contain any extension options.
The timing of such termination, and the costs or penalties associated with
exercising such options, are included to the extent that the timing is
reasonably certain. This assessment can significantly affect the
right-of-use asset and lease liability recognised. The lease term for the Aoka
Mizu FPSO has been assessed to last until August 2025, the estimated end of
the economic life of the Lancaster field given the economic incentive for both
the Group and lessor to continue the contract until that point, with the six
months notice to terminate the charter being given to align with that.
As at 31 December 2021, the lease term used to determine the right-of-use
asset and lease liability recognised was assessed to expire in June 2022 which
was the end of contractual period at that date.
Lease liabilities
The amounts recognised in the Financial Statements relating to lease
liabilities (which are liabilities arising from financing activities) are as
follows:
Year ended Year ended
31 Dec 2022 31 Dec 2021
$'000 $'000
At 1 January 15,790 97,321
Remeasurement of lease liability 75,897 (67,337)
Cash payments of principal and interest (27,837) (18,596)
Interest charged 3,873 4,412
Foreign exchange movements (233) (10)
At 31 December 67,490 15,790
Of which:
Current 27,612 13,880
Non-current 39,878 1,910
67,490 15,790
The Group's main lease is the bareboat charter of the Aoka Mizu FPSO for which
the Group makes fixed payments (which are included within the lease liability
measurement) and variable payments (which are based on a percentage of the
quantity and price of crude oil sold and recognised as an expense in the
period in which the related sales are made - see note 2.2). Under the original
terms of the contract, should the Group give notice to terminate the lease
(other than by not exercising extension option periods), significant early
termination penalties would have applied. The Group was required to set aside
amounts to cover a portion of these early termination penalties, the balance
of which changed over time in line with the contract, and such balances were
classified as restricted cash (see note 4.1).
The lease term for the Aoka Mizu FPSO was previously assessed to have been six
years from inception of the lease (to June 2025), taking into account
extension options and termination arrangements. On 4 June 2021, the Group
announced it had resolved not to exercise its option to extend the bareboat
charter of the Aoka Mizu FPSO for a period of three years from June 2022 to
June 2025. As the Group elected not to exercise an option previously included
in its determination of the lease term, the lease term was subsequently
reassessed, for IFRS 16 accounting purposes, to be expiring at the end of the
contractual period (being June 2022), and therefore the liability remeasured
by discounting the revised lease payments. This resulted in a decrease to the
lease liability of $67.3 million, decrease to the associated right-of-use
asset cost of $18.2 million and a gain of $49.1 million recognised in Group
Statement of Comprehensive Income.
On 25 March 2022, the Group announced that it had signed a contract with
Bluewater, for an extension to the bareboat charter beyond the previous expiry
date of 4 June 2022. The extension is expected to continue for the remaining
economic life of the Lancaster field given the significant economic incentive
for both sides to extend the lease based on the current forward price curve
and production profiles. In accordance with IFRS 16 the liability was
remeasured by discounting the revised lease payments covering the economic
life of field. This resulted in an increase to the lease liability of $54.5
million (above) and corresponding increase to the associated right-of-use
asset cost of $54.5 million (note 2.3).
On 31 December 2022, the economic life of the Lancaster field was reassessed,
and the liability remeasured resulting in a further increase to the lease
liability (above) and associated right-of-use asset (note 2.3) of $21.4
million.
Other charges to the Group Statement of Comprehensive Income in respect of
leases during the year included the following:
Year ended Year ended
31 Dec 2022 31 Dec 2021
$'000 $'000
Depreciation charge of right-of-use assets:
Oil and gas assets (included within cost of sales) 26,652 3,404
Other fixed assets (included within general and administrative expenses) 235 364
26,887 3,768
Provision for impairment of right-of-use assets:
Oil and gas assets (included within cost of sales) − -
Other fixed assets (included within general and administrative expenses) − 719
− 719
Lease interest (included within finance costs) 3,873 4,412
Variable lease payments (included within cost of sales) 24,822 20,454
The total gross cash outflow for leases for the year was $52.8 million.
5.3 Maturity analysis of financial liabilities
The maturity analysis of contractual undiscounted cash flows for
non-derivative financial liabilities is as follows:
Less than 6 months 6-12 months 1-2 years 2-5 years More than Total
5 years
$'000 $'000 $'000 $'000 $'000 $'000
( ) ( )
Trade and other payables 15,887 - - - - 15,887
Lease liabilities 13,873 13,914 27,759 19,151 308 75,005
At 31 December 2022 29,760 13,914 27,759 19,151 308 90,892
Less than 6 months 6-12 months 1-2 years 2-5 years More than Total
5 years
$'000 $'000 $'000 $'000 $'000 $'000
( ) ( ) ( ) ( )
Trade and other payables 18,843 - - - - 18,843
Convertible Bond interest 2,944 1,472 - - - 4,416
Convertible Bond principal - 78,515 - - - 78,515
Lease liabilities 13,900 441 499 1,038 865 16,743
At 31 December 2021 35,687 80,428 499 1,038 865 118,517
The maturity analysis for lease liabilities includes only those fixed lease
repayments contracted to at the balance sheet date.
5.4 Share capital
Ordinary Shares $'000
At 31 December 2020 1,991,871,556 2,885
At 31 December 2021 1,991,871,556 2,885
At 31 December 2022 1,991,871,556 2,885
The Company has one class of Ordinary Share, all of which are fully paid and
have a par value of £0.001. The rights and obligations of holders of Ordinary
Shares are disclosed in the Directors' Report. The Company does not have an
authorised share capital.
There are no outstanding warrants or rights relating to the Company's Ordinary
Shares.
5.5 Share option reserve
The share option reserve arises as a result of the expense recognised in the
Group Statement of Comprehensive Income to account for the cost of share-based
employee compensation arrangements.
5.6 Own shares reserve
The own shares reserve represents the cost of Ordinary Shares in Hurricane
Energy plc purchased and held by the Group's SIP Trust to satisfy the Group's
SIP administered by Global Shares Trustee Company Limited.
The SIP did not acquire any Ordinary Shares in 2022 or 2021. At 31 December
2022 there were 2,113,153 Ordinary Shares held in the SIP Trust (2021:
2,610,286), with 995,684 allocated to participants (2021: 1,872,498).
5.7 Foreign exchange reserve
The foreign exchange reserve arose from the change in the Company's functional
and presentation currency from Pounds Sterling to US Dollars on 1 January
2017.
5.8 Capital risk management
The Group's objectives when managing capital are to safeguard its ability to
continue as a going concern in order to provide returns for shareholders and
benefits for other stakeholders. The Group is not subject to any externally
imposed capital requirements.
Capital managed by the Group at 31 December 2022 consists of cash and cash
equivalents, borrowings and equity attributable to equity holders of the
parent. The capital structure is reviewed by management through regular
internal and financial reporting and forecasting. As at 31 December 2022
equity attributable to equity holders of the parent was $195.8 million (2021:
$86.9 million), whilst unrestricted cash and cash equivalents and liquid
investments amounted to $138.4 million (2021: $68.9 million).
Section 6. Taxation
Accounting policy
Current and deferred tax, including UK corporation tax and overseas
corporation tax, are provided at amounts expected to be paid using the tax
rates and laws that have been enacted or substantively enacted by the balance
sheet date.
From time to time, entities within the Group may be entitled to claim tax
deductions in relation to qualifying expenditure, such as the UK's research
and development tax incentive regime. Such allowances are accounted for as tax
credits, reducing income tax payable and current tax expense, and are only
recognised as current tax receivables when amounts have been agreed with the
relevant tax authorities and not at the point that the claims are made.
Deferred tax assets are recognised for unclaimed tax credits subject to the
conditions outlined below.
Deferred tax assets and liabilities are calculated in respect of temporary
differences using a balance sheet liability method. Deferred tax assets and
liabilities are recorded for all temporary differences arising between the tax
basis of assets and liabilities and their carrying values for financial
reporting purposes, except in relation to goodwill or the initial recognition
of an asset as a transaction other than a business combination. A deferred tax
asset is recorded only to the extent that it is probable that taxable profit
will be available against which the deferred tax asset will be realised or if
it can be offset against existing deferred tax liabilities.
Deferred tax assets and liabilities are measured at tax rates that are
expected to apply to the period when the asset is realised or the liability is
settled, based on tax rates that have been enacted or substantively enacted at
the balance sheet date.
Critical judgement and key source of estimation uncertainty - recognition of,
and estimation of future taxable profits against which to recognise, deferred
tax assets
Judgement has been applied in determining whether deferred tax assets are
recognised on the Statement of Financial Position (over and above the extent
to which they offset deferred tax liabilities). Estimates of future taxable
profits were made using the Group's corporate cash flow model. The cash flows
included in the corporate model are predominantly derived from future revenue
from the Lancaster EPS arising from the currently producing wells, and future
spend on currently unsanctioned capital projects. Estimates of future taxable
profits were made using the Group's corporate cash flow model, with key
judgements and assumptions consistent with those used in testing the Lancaster
assets for impairment (note 2.3.1). The results of the review concluded that
there would not be sufficient forecast taxable profits at this time to
recognise a deferred tax asset in excess of deferred tax liabilities.
Assumptions about the generation of future taxable profits depend on
management's estimates of cash flows and taxable income. These estimates are
primarily based on forecast cash flows from operations (which are impacted by
production and sales volumes, oil and gas prices, hydrocarbon reserves and
operating costs), as well as decommissioning estimates, future capital
expenditure and capital structure. Should future cash flows and/or taxable
income differ significantly from these estimates, the ability of the Group to
realise the net deferred tax assets recorded at the reporting date could be
impacted.
6.1 Tax charge for the year
Year ended Year ended
31 Dec 2022 31 Dec 2021
$'000 $'000
UK corporation tax
Current tax charge - current year (6,199) _
Current tax credit - prior year 4,588 -
Total current tax charge (1,611) -
Deferred tax - current year (104) 21
Deferred tax - prior year - 5
Total deferred tax (104) 26
Tax (charge) / credit per Group Statement of Comprehensive Income (1,715) 26
Profit on ordinary activities before tax 110,376 18,210
Profit on ordinary activities multiplied by standard combined rate of (44,150) (7,284)
corporation tax in the UK applicable to oil and gas companies of 40% (2021:
40%)
Effects of:
Expenses not deductible for tax purposes (1,155) (1,934)
Income not chargeable for tax purposes 1,265 7,692
Items taxed at rates other than the standard rate of 40% 590 (2,064)
Ring-fence expenditure supplement 14,825 20,560
Prior period deferred tax 4,588 5
Utilisation of amounts not previously recognised/deferred tax assets not 33,854 (6,687)
recognised
Impact of tax rate change - 25
Chargeable gain (5,333) (10,287)
Energy Profits Levy (6,199) -
Total tax credit/(charge) for the year (1,715) 26
The tax charge for the period includes a current tax charge of $6.2 million
relating predominately to the Energy (Oil and Gas) Profits Levy Act 2022
(EPL), which was introduced and took effect for profits generated from 26 May
2022 onwards at a rate of 25%. An instalment payment of $2.6 million was made
in the year against the EPL resulting in a tax liability as at 31 December
2022 of $3.6 million. The amounts not recognised for the period includes $94.7
million of additional deferred tax assets not recognised, in relation to the
revaluation of temporary differences (excluding decommissioning liabilities)
from 40% to 75% (being the combined RCFT/SC/EPL rate from 1 January 2023) to
reflect the increase in tax rate in future periods to 31 March 2028, when the
EPL is currently legislated to no longer apply.
6.2 Deferred tax
31 Dec 2022 31 Dec 2021
$'000 $'000
Accelerated capital allowances - 83
Other temporary differences - 21
Tax losses carried forward - -
Deferred tax asset - 104
A potential deferred tax asset of $303.6 million in relation to tax losses and
allowances available to the main trading entity, Hurricane GLA Limited, has
not been recognised, as it has been concluded that it is not appropriate to
recognise any of this potential deferred tax asset based on current forecasts
of future profitability. There is an additional deferred tax asset of $81.5
million representing pre-trading expenditure not recognised and includes
potential claims for ring fence expenditure supplement (RFES). The additional
deferred tax asset is calculated primarily at a rate of 40% (2021: 40%)
subject to any adjustments required for supplementary charge tax.
6.3 Factors which may affect future tax charges
The Group has ring-fenced trading losses (including certain RDEC credits) of
$214.5 million at 31 December 2022 (2021: $381.9 million) and supplementary
charge losses and allowances of $629.8 million at 31 December 2022 (2021:
$693.0 million), which have no expiry date and would be available for offset
against future ring-fenced trading profits. The Group also has unclaimed
capital allowances of $333.1 million available to be used against future
taxable profits (2021: $328.4 million). Out of these unclaimed capital
allowances, $182.0 million are expected to unwind during the period when the
EPL applies to the ring fence taxable profits and therefore the tax value of
these allowances has been disclosed at the 75% combined EPL rate (from 1
January 2023) rather than the combined RCFT/SC rate of 40%.
In addition to the above, the Group has pre-trading expenditure of $126.4
million (2021: $124.9 million) which is carried forward at 31 December 2022
and tax relief may be available should trading activities commence (this
expenditure could also be uplifted by RFES to $77.2 million).
The value of tax attributes as at 31 December 2022 at the currently prevailing
tax rates can be summarised as follows:
Tax attributes Tax rate Tax value
$'000 % $'000
Ring-fence losses 191,526 30% 57,458
RDEC not recognised 22,974 40% 9,190
Supplementary charge losses 102,346 10% 10,235
Investment allowance 527,505 10% 52,751
Unclaimed capital allowances 150,921 40% 60,368
Unclaimed capital allowances expected to unwinding during the EPL period 182,211 75% 136,658
Pre-trading expenditure (including RFES) 203,622 40% 81,449
Future decommissioning costs 47,057 40% 18,823
Non-ring-fence losses 5,320 25% 1,330
Value of tax attributes at prevailing tax rates 428,262
Oil and gas activity in the UK is subject to Corporation Tax at a combined
rate of 40% made up of 30% ring fence corporation tax and 10% supplementary
tax charge. The amount of tax loss that is associated with supplementary tax
charge is generally lower that ring fence losses as while interest is
deductible for ring fence corporation tax purposes, it is not deductible for
supplementary charge tax. Ring Fence losses are relievable at 30% and
supplementary charge tax losses are relievable at 10%. Once adjusted to take
into account interest not deductible for supplementary charge the effective
rate of relief is 35.3% relief. Investment allowance is only allowable against
supplementary charge tax and attracts relief at 10%. Investment allowance is
available after tax losses have been taken into account.
In the Spring Budget 2021, the Government announce that from 1 April 2023 the
corporation tax rate will increase to 25%. The increase in rate was
substantively enacted on 24 May 2021. Deferred taxes at the balance sheet date
have been measured using these enacted rats and where recognised reflected in
these financial statements. In the Autumn Statement 2022, amongst other
measures, it was confirmed that as already enacted the Corporation Tax will
increase to 25% from 1 April 2023.
Section 7. Other disclosures
7.1 Auditor's remuneration
The following is an analysis of the gross fees payable to the Group's auditor,
PKF Littlejohn LLP.
Year ended Year ended
31 Dec 2022 31 Dec 2021
$'000 $'000
Audit services
Fees payable to the Company's auditors for:
The audit of the Company's annual accounts * 165 247
The audit of the Company's subsidiaries 28 25
193 272
Non-audit services
Other services pursuant to legislation - interim review 28 25
Fees payable to previous auditor for audit transition services − 9
28 34
Total 221 306
* Fees payable for the audit of the Company's annual accounts for the year
ended 31 December 2021 included $104,000 of additional fees paid to Deloitte
LLP, the Group's previous auditor, in respect of the 2020 audit.
7.2 Other non-current assets
Accounting policy
Fixed assets, other than oil and gas assets, are depreciated so as to write
off the cost, less estimated residual value, of the asset on a straight-line
basis over their useful lives of between two and five years.
The accounting policy for leases, including right-of-use assets, is presented
in note 5.2.
31 Dec 2022 31 Dec 2021
$'000 $'000
Other fixed assets:
Leased 788 1,024
Owned 80 165
Prepayments and rent deposits 176 175
Emission allowances − 9
1,044 1,373
Other fixed assets held under leases (right-of-use assets) comprise office
property leases. During the prior year, a provision for impairment of $0.7
million was made against one such lease. There were no additions or disposals
to this class of right-of-use asset during the current or prior year.
Owned other fixed assets include the cost of leasehold improvements, fixtures,
office equipment and computer hardware.
7.3 Related parties
The remuneration of the directors, who are considered the Group's key
management personnel, is as follows:
Year ended Year ended
31 Dec 2022 31 Dec 2021
$'000 $'000
Salaries, fees, bonuses and benefits in kind * 1,792 * 1,960
Share-based payment charge 10 463
1,802 2,423
All transactions with the directors will be detailed in the Remuneration
Report section of the Governance Report of the full 2022 Annual Report, which
shows total fixed and variable payments of £1,465,000 ($1,792,000 as above *)
made to directors during the year.
As of 31 December 2022, Crystal Amber Fund Limited ('Crystal Amber') held
28.9% of the Company's Ordinary Shares, and Crystal Amber have classified its
investment in Hurricane as an associate. As such, Crystal Amber are considered
to be a related party of the Group.
There is no ultimate controlling party of the Group.
7.4 Subsequent events
· On 3 February 2023, the Company's previously held share premium
account for value $822.5m was cancelled against the Company's accumulated
deficit. This cancellation was approved by the Company's shareholders at a
General Meeting held on 11 January 2023, and was subsequently approved by the
High Court of England and Wales on 31 January 2023. The cancellation of the
share premium and consequent elimination of the accumulated deficit results in
reserves being made available for distribution to the Company's shareholders
· On 17 February 2023, the Group relinquished the licence P2308
comprising the Halifax asset. This asset was impaired to nil by 31 December
2022.
· On 16 March 2023, the Company announced that an agreement has
been reached on the terms of a recommended acquisition of the entire issued
ordinary share capital by Prax Exploration & Production PLC. The terms and
details of the recommended offer are set out in the Scheme Document published
on 6 April 2023 and available on the Hurricane website. Completion of the
acquisition is subject to Court approval.
Appendix A: Glossary
1C Denotes low estimate of Contingent Resources
1P Denotes low estimate of Reserves (i.e. Proved Reserves).
2C Denotes best estimate of Contingent Resources
2P Denotes the best estimate of Reserves. The sum of Proved plus Probable
Reserves
3C Denotes high estimate of Contingent Resources
3P Denotes high estimate of Reserves. The sum of Proved plus Probable plus
Possible Reserves
4Z The suspended 205/21a-4z well on the Lancaster field, plugged and abandoned
during 2021
The Acquisition The proposed purchase of the entire issued and to be issued ordinary share
capital of Hurricane by Prax
AIM The AIM market of the London Stock Exchange
AGM Annual General Meeting
Aoka Mizu The Aoka Mizu FPSO, under lease to the Company from Bluewater
bbl Barrel
Bluewater Bluewater Energy Services and affiliates
Bondholder A holder of one or more the Company's Convertible Bonds
Board Board of directors of the Company
bopd Barrels of oil per day
BP BP Oil International Limited
bubble point The pressure at which gas begins to come out of solution from oil within the
reservoir
carry Payment of a partner's working interest share of costs
CEO Chief Executive Officer
CFO Chief Financial Officer
CGU Cash generating unit
CMED Central medical emergency dispatch
CO(2)e Carbon dioxide equivalent
Company Hurricane Energy plc and/or its subsidiaries
Companies Act 2006 Act of the Parliament of the United Kingdom which forms the primary source of
UK company law
Contingent Resources Those quantities of petroleum estimated, as of a given date, to be potentially
recoverable from known accumulations by application of development projects,
but which are not currently considered to be commercially recoverable owing to
one or more contingencies
Convertible Bond(s) $230.0 million 7.5% convertible bonds issued by the Company in July 2017, of
which $78.5 million remain outstanding as at 31 December 2021
COO Chief Operations Officer
CoP Cessation of production
COP 21 The 21(st) Conference of the Parties to the United Nations Framework
Convention on Climate Change
Court High Court of Justice of England and Wales
COVID-19 Coronavirus
CPR Competent Persons Report
Crystal Amber Crystal Amber Fund Limited
DCU Deferred Consideration Units
DD&A Depreciation, depletion and amortisation
Developed reserves Reserves that are expected to be recovered from existing wells and facilities.
Developed reserves may be further sub-classified as producing or non-producing
DRR Directors' Remuneration Report
D&O Directors and Officers
E&E Exploration and Evaluation
E&P Exploration and Production/Exploration and Production company
EPL Energy (oil & gas) Profits Levy
EPS Early Production System
ERCE ERC Equipoise Limited
ESG Environmental, Social and Governance
ESP Electrical submersible pump
FDPA Field Development Plan Addendum
FPSO Floating production storage and offloading vessel
FRC Financial Reporting Council
FSP Formal Sale Process
FVLCD Fair value less costs of disposal
FVTPL Fair value through profit and loss
G&A General and Administrative costs
GBP British Pounds Sterling
GHG Greenhouse Gas (i.e. Carbon Dioxide, Methane, Nitrous Oxide,
Chlorofluorocarbon-12, Hydrofluorocarbon-23, Sulphur Hexafluoride, Nitrogen
Trifluoride)
GLA Greater Lancaster Area, comprising UKCS licences P1368 Central and P2308
GRI Global Reporting Initiative
Group Hurricane Energy plc, together with its subsidiaries
GWA Greater Warwick Area, comprising the Lincoln and Warwick fields located on
UKCS licences P1368 South and P2294
HSE Health, Safety and Environment
HSEMS Health, Safety and Environmental Management System
HSSE Health, Safety, Security and Environment
Hurricane Hurricane Energy plc, together with its subsidiaries
IAS International Accounting Standard
IFRS International Financial Reporting Standards
Incoterms The internationally recognised set of rules which define the responsibilities
of buyers and sellers for the delivery of goods under sales contracts
IPCC Intergovernmental Panel on Climate Change
IPIECA International Petroleum Industry Environmental Conservation Association
IPO Initial Public Offering
ISDA International Swaps and Derivatives Association
ISO 14001 International Organization for Standardization certification - Environmental
Management
ISO 45001 International Organization for Standardization certification - Occupational
Health and Safety Management
JV Joint venture
Kyoto Protocol An international agreement that called for industrialised nations to reduce
their greenhouse gas emissions significantly.
KPI Key Performance Indicator
LIBOR London Interbank Offered Rate
LTIFR Lost time incident frequency rate
LTIP Long term incentive plan
Mbbl Thousand barrels of oil
MER UK A government strategy: maximising economic recovery of UK petroleum
MMbbl Million barrels of oil
MMstb Million stock tank barrels of oil
NSTA North Sea Transition Authority (formerly Oil and Gas Authority (OGA))
Official List The list of companies listed in the UK maintained by the Financial Conduct
Authority (acting in its capacity as the UK Listing Authority)
OGA Oil and Gas Authority (now known as the North Sea Transition Authority (NSTA))
OEUK Offshore Energies UK; the oil & gas trade association for the United
Kingdom (formerly known as OGUK)
OPRED Offshore Petroleum Regulator for Environment and Decommissioning
Ordinary Shares Ordinary shares in the Company of £0.001 each
OWC Oil water contact
P6 The 205/21a-6 producer well on the Lancaster field
P7z The 205/21a-7z well on the Lancaster field, currently shut-in
P8 Proposed side-track of the existing 205/21a-7z well
Performance Measures Those KPIs that relate to annual bonuses - inter-year progress measures,
ensuring continued progress towards delivery of the Company's strategy on an
annual basis
PILON Pay in Lieu of Notice
PKF PKF Littlejohn LLP, auditor
Prax Prax Exploration and Production PLC (a wholly owned subsidiary of State Oil
Limited)
Premium Listing Listing on the premium segment of a recognised stock exchange
PRMS Petroleum Resources Management System
PSP Performance Share Plan
psi Pounds per square inch unit of pressure
QCA Quoted Companies Alliance
QCA Code The QCA Corporate Governance Code
R&D Research & Development
Regulator The North Sea Transition Authority, the Department for Business Energy and
Industrial Strategy, the Offshore Petroleum Regulator for Environment and
Decommissioning and/or The Health and Safety Executive
Reserves Reserves are those quantities of petroleum anticipated to be commercially
recoverable by application of development projects to known accumulations from
a given date forward under defined conditions
RDEC Research and Development Expenditure Credit
RFES Ring fence expenditure supplement
The Scheme The potential acquisition of Hurricane by Prax by means of a court-sanctioned
scheme of arrangement under Part 26 of the Companies Act 2006 between
Hurricane and Hurricane Shareholders
Scheme Document Circular in relation to the Scheme setting out the full terms and conditions
of the Scheme available on Hurricane's website
SIP Share Incentive Plan
SONIA Sterling Overnight Index Average
Special dividends The transaction dividend and the supplementary dividend
Spirit Energy Spirit Energy Limited and affiliates
Supplementary dividend Under the terms of the Acquisition, Hurricane Shareholder will be entitled to
receive a supplementary dividend of up to 1.87 pence per share in cash
conditional on Hurricane receiving cash proceeds from the April oil lifting
from the Lancaster field
TCFD Task force on climate-related financial disclosures
Threshold Value The price used to determine the value of Growth Shares in relation to the VCP:
£0.34 per share (the price on date of issue of the Growth Shares), as
adjusted
Tier 1 contractors Hurricane's major direct contractors
Transaction dividend Under the terms of the Acquisition, Hurricane Shareholder will be entitled to
receive a transaction dividend of 3.32 pence per share in cash
TRIR Total recordable incident rate
TSR Total Shareholder Return
UKCS United Kingdom Continental Shelf
USD United States Dollars
VCP Value Creation Plan
VIU Value in use
WOSPS West of Shetland Pipeline System
Appendix B: Non-IFRS measures
Accounting policy for non-IFRS measures
Management believes that certain non-IFRS measures (also referred to as
'alternative performance measures') are useful metrics as they provide
additional useful information on performance and trends. These measures are
used by management for internal performance analysis and incentive
compensation arrangements for directors and employees. The non-IFRS measures
presented below are not defined in IFRS or other GAAPs and therefore may not
be comparable with similarly described or defined measures reported by other
companies. They are not intended to be a substitute for, or superior to, IFRS
measures.
Definitions and reconciliations to the nearest equivalent IFRS measure are
presented below.
Underlying profit before tax
Underlying profit before tax is defined as profit before tax under IFRS less:
fair value gains or losses on the Convertible Bond embedded derivative; fair
value gains or losses on unhedged derivative financial instruments;
impairment, impairment reversals and write-offs of intangible exploration and
evaluation assets and other fixed assets; changes in decommissioning estimates
on fully impaired assets; gains or losses on lease remeasurements; gains or
losses on repurchase of debt instruments; and gains or losses on disposal of
assets or subsidiaries.
Management believes that underlying profit before tax is a useful measure as
it provides useful trends on the pre-tax performance of the Group's core
business and asset by removing certain non-cash items and transactions within
the Group Statement of Comprehensive Income. These are the volatile non-cash
impact of the Convertible Bond embedded derivative movement, gains or losses
arising from lease remeasurements, write-offs and impairments of assets
including movements on decommissioning provisions where assets are fully
impaired, accounting gains arising from debt repurchases, and disposals of
assets or subsidiaries where they do not reflect the Group's core business.
Year ended Year ended
Note 31 Dec 2022 31 Dec 2021
$'000 $'000
Profit before tax (IFRS measure) 110,376 18,210
Add back:
Fair value loss/(gain) on Convertible Bond embedded derivative 5.1 (27) 1,901
Impairment and write-off of intangible exploration and evaluation assets 2.4 & 4.3 4,234 54,280
Change in decommissioning estimates on fully impaired assets 2.5 (1,032) 1,973
Impairment of oil and gas assets 2.3 - -
Impairment of other fixed assets and other right-of-use assets 5.2 - 719
Gain on revision of lease term 5.2 - (49,125)
Net gain on repurchase of Convertible Bonds 5.1 - (17,201)
Underlying profit before tax 113,551 10,757
Cash production costs
Cash production costs are defined as cost of sales under IFRS, less
depreciation of oil and gas assets (including right-of-use assets) and
accounting movements of crude oil inventory (including any net realisable
value provision movements), plus fixed lease payments payable for leased oil
and gas assets. Cash production costs (excluding incentive tariff) are defined
as cash production costs less variable lease payments.
Depreciation and movements in crude oil inventory are deducted as they are
non-cash accounting adjustments to cost of sales. Fixed lease payments payable
for oil and gas assets are added back because, under IFRS 16, the charge
relating to fixed lease payments is charged to the Group Statement of
Comprehensive Income within both depreciation of oil and gas assets and
interest on lease liabilities. They are therefore included within cash
production costs as they are considered by management to be operating costs in
nature. Fixed lease payments payable for the purposes of this measure are
calculated as the day rate charge multiplied by the number of days in the
period. Cash production costs (excluding incentive tariff) deduct variable
lease payments, as the latter is directly linked to the price of crude oil
sold and thus largely outside of management's control. Cash production cost
per barrel measures are defined as the relevant cash production cost measure
divided by production volumes.
Management believes that cash production costs and cash production costs per
barrel (both including and excluding incentive tariff) are useful measures as
they remove non-cash elements from cost of sales, assist with cash flow
forecasting and budgeting, and provide indicative breakeven amounts for the
sale of crude oil.
Year ended Year ended
Note 31 Dec 2022 31 Dec 2021
$'000 $'000
Cost of sales (IFRS measure) 2.2 173,421 173,125
Less:
Depreciation of oil and gas assets - owned 2.2 (55,212) (94,200)
Depreciation of oil and gas assets - leased 2.3 (26,652) (3,405)
Movements in crude oil inventory 2.2 (3,553) 10,622
Add:
Fixed lease payments payable on oil and gas assets 27,381 19,638
Cash production costs 115,385 105,780
Variable lease payments (incentive tariff) 2.2 (24,822) (20,454)
Cash production costs (excluding incentive tariff) 90,563 85,326
Production volumes 3,089 Mbbl 3,748 Mbbl
Cash production costs per barrel $37.4/bbl $28.2/bbl
Cash production costs per barrel (excluding incentive tariff) $29.3/bbl $22.8/bbl
Net free cash and net debt
Net free cash is defined as current unrestricted cash and cash equivalents,
plus current financial trade and other receivables (which exclude prepayments)
and current oil price derivatives, less current financial trade and other
payables (which includes accruals) and tax liabilities.
Management believes that net free cash is a useful measure as it provides a
view of the Group's available liquidity and resources after settling all its
immediate creditors and accruals and recovering amounts due and accrued from
joint operation activities, outstanding amounts from crude oil sales and after
settling any other financial trade payables or receivables.
Net debt is defined as net free cash less the nominal value of the Convertible
Bond, being the total amount repayable on maturity of the Bond debt in July
2022 (unless previously converted, redeemed or purchased and cancelled).
Management believes that net debt is a useful measure as it aids stakeholders
in understanding the current financial position and liquidity of the Group.
Note 31 Dec 2022 31 Dec 2021
$'000 $'000
Cash and cash equivalents (IFRS measure) 4.1 199,137 76,792
Add:
Trade and other receivables 4.2 3,675 2,591
Less:
Restricted cash and cash equivalents 4.1 (60,754) (7,934)
Prepayments 4.2 (1,130) (1,058)
Trade and other payables 4.3 (15,887) (18,843)
Tax liabilities 6.1 (3,617) -
Net free cash 121,424 51,548
Nominal value of Convertible Bond 5.1 − (78,515)
Net free cash / (Net debt) 121,424 (26,967)
Free cash flow
Free cash flow is defined as net cash inflow or outflow from operating
activities per the Cash Flow Statement, excluding decommissioning spend and
including fixed lease repayments, adjusted for other items considered by
management to be capital rather than operating in nature. Free cash flow per
barrel is calculated as free cash flow divided by production volumes for the
year.
Management believes that free cash flow is a useful measure as it shows cash
generated from ongoing operations and G&A.
Year ended Year ended
Note 31 Dec 2022 31 Dec 2021
$'000 $'000
Net cash inflow from operating activities (IFRS measure) 203,427 147,044
Adjustments:
Decommissioning spend 277 4,824
Reallocation of items to cash capex - 2,405
Lease repayments 5.2 (27,837) (18,596)
Free cash flow 175,867 135,677
Free cash flow per barrel $56.9/bbl $36.2/bbl
Cash capex
Cash capex is defined as net cash used in investing activities per the Cash
Flow Statement, less cash interest received and movement in liquid investment,
plus decommissioning spend and adjusted for other items considered by
management to be capital rather than operating in nature. Third-party cash
capex is defined as cash capex less general and administrative expenditure
capitalised into fixed assets.
Management believes that cash capex and third-party cash capex are useful
measures as they show overall expenditure on projects and activities
considered capital in nature, with and without the impact of internally
capitalised general and administrative costs.
Year ended Year ended
Note 31 Dec 2022 31 Dec 2021
$'000 $'000
Net cash (from)/used in investing activities (IFRS measure) (30,445) 29,698
Adjustments:
Interest received 1,174 27
Increase in liquid investments 34,739 (15,530)
Decommissioning spend 277 4,824
Reallocation of items from free cash flow - 2,405
R&D tax refund 4,588
Cash capex 10,333 21,424
Less: capitalised general and administrative expenditure
Capitalised into oil and gas assets 3.3 (2,229) (3,025)
Capitalised into intangible exploration and evaluation assets 3.3 648 (3,456)
Third-party cash capex 8,752 14,943
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