TIDMHUR
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
Antony Maris, Chief Executive Officer +44 (0)1483 862
communications@hurricaneenergy.com 820
Stifel Nicolaus Europe Limited
Nominated Adviser & Joint Corporate Broker +44 (0)20 7710
Callum Stewart / Jason Grossman 7600
Investec Bank plc
Joint Corporate Broker +44 (0)20 7597
Chris Sim / Jarrett Silver / Charles Craven 5970
Vigo Consulting
Public Relations
Patrick d'Ancona / Ben Simons +44 (0)20 7390
hurricane@vigoconsulting.com 0230
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
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 CO e, or 35.8 kg/bbl on an intensity basis. This compared
with 139,584 tonnes CO e, or 37.2 kg/bbl in 2021, and 210,884
tonnes CO e and 41.5 kg/bbl in 2020.
These emissions meet the OEUK Scope 1 definition and include CO
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 $96.3/bbl $67.3/bbl
price realised
----------- ------------
Cash production $37.4/bbl $28.2/bbl
cost per barrel
----------- ------------
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 GBP28.0 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 GBP5.7 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 GBP33.7 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 GBP103 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
General and administrative expenses 3.3 (9, 355 ) (26,749)
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
expense written off & 4.3 (4,234) (54,280)
---------------------------------------- ------ ----------- -----------
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 2.4
expense written off & 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 31 Dec 31 Dec
Sterling 2022 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 31 Dec
2022 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 31 Dec
2022 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 calculating
basic earnings per share (being profit after
tax) 108,661 18,236
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 calculating
diluted earnings per share 108,661 18,236
--------------------------------------------------- ------------- -------------
Number Number
--------------------------------------------------- ------------- -------------
Weighted average number of Ordinary Shares
used in calculating basic earnings per share 1,990,423,900 1,989,927,148
Potential dilutive effect of:
Convertible Bond - -
--------------------------------------------------- ------------- -------------
Weighted average number of Ordinary Shares
and potential Ordinary Shares used in calculating
diluted earnings per share 1,990,423,900 1,989,927,148
--------------------------------------------------- ------------- -------------
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 - (4,614) (4,614) - (15,095) (15,095)
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 GBP0.32 (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 31 Dec 2021
2022
$'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 31 Dec 2021
2022
$'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
---------------------------------------------------- ---------- -----------
2 6,887 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 More than
6 months 6-12 months 1-2 years 2-5 years 5 years Total
$'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 More than
6 months 6-12 months 1-2 years 2-5 years 5 years Total
$'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 $'000
Shares
-------------------- ------------- -----
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 GBP0.001. 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 corporation tax
in the UK applicable to oil and gas companies
of 40% (2021: 40%) (44,150) (7,284)
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 recognised 33,854 (6,687)
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 GBP1,465,000 ($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 GBP0.001 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: GBP0.34 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 2.4
exploration and evaluation assets & 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 $29.3/bbl $22.8/bbl
incentive tariff)
--------------------------------------------- ---- ----------- -----------
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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END
FR NKPBBNBKBKPB
(END) Dow Jones Newswires
May 26, 2023 02:00 ET (06:00 GMT)
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