TIDMHUR
RNS Number : 6180J
Hurricane Energy PLC
28 April 2022
28 April 2022
Hurricane Energy plc
("Hurricane", the "Company", or the "Group")
Full-year Results 2021
Hurricane Energy plc, the UK based oil and gas company,
announces its full-year results for the period ended 31 December
2021.
Highlights
Financial results
-- Revenues of $240.5 million from seven liftings of Lancaster
crude (2020: $180.1 million from 12 liftings)
-- Cash production costs of $28.2/bbl (2020: $17.9/bbl)
-- Generated $135.7 million of free cash flow , equivalent to
$36.2/bbl (2020: $74.2 million, $14.6/bbl)
-- Profit after tax for the period of $18.2 million (2020: loss after tax of $625.3 million)
-- Net free cash of $51.5 million (31 December 2020: $111.4 million)
-- Net debt of $27.0 million (31 December 2020: $118.6 million)
-- Repurchased $151.5 million of Convertible Bonds at average
price of 86%, saving $29.5m in future principal and interest
Operations
-- Production within guidance with average daily rate of 10,267 bopd (2020: 13,900)
-- Excellent operational uptime of 92.3%, covering planned and unplanned events
-- Crude oil sales reached over 10 million barrels with 3.6
Mbbls sold across seven cargoes in 2021
-- FDPA consent received allowing for production below bubble point
-- Following unsuccessful farmout process, JV partners agree
surrender of P1368(S) (Lincoln) licence
Corporate
-- The Company's proposed financial restructuring was ultimately
not pursued following the High Court Judgment that the
restructuring should not be implemented
-- In June 2021, the incumbent Non-Executive Directors resigned
from the board, with John Wright and David Craik appointed to the
board as Non-Executive Directors and John Wright assuming the
position of Interim Chairman
-- In October 2021, Philip Wolfe was appointed to the board as
Independent Non-Executive Director
Outlook
-- FPSO Charter extension agreed in March 2022
-- Full bond repayment anticipated in July 2022
-- Net free cash of at least $60m projected following bond
repayment, assuming production in line with guidance and oil prices
of at least $90/bbl
-- Focus on efficient capital allocation to deliver most value for shareholders
-- Consideration of opportunities within existing portfolio and new assets
Antony Maris, CEO of Hurricane, commented:
"This last year has been one of profound change for Hurricane.
Despite all the recent volatility in the oil price, with the
expectation that oil prices remain over $90/bbl, post bond
repayment we forecast to have over $60 million of net free cash
.
The UK Government's renewed emphasis on security of supply is
welcome and we are working hard to identify how best to optimise
capital allocation in future activities to build further value for
our shareholders. We have opportunities both within our existing
portfolio, and in new opportunities in the UK oil and gas
sector.
Against the backdrop of our demonstrable operational track
record, financial discipline, and the significant rise in oil
prices, we are preparing Hurricane for the future. Our thoughts are
therefore fully focused on building on our position of increasing
strength and value."
Designates a non-IFRS measure. See Appendix B to this
announcement for definition and reconciliation to nearest
equivalent statutory IFRS measures.
The Company has published a presentation on its website to
accompany this results announcement.
There will be a webcast/conference call for analysts at 9:30
a.m. BST and a recording of this will be made available on the
Company's website later today at
https://www.hurricaneenergy.com/investors/presentations.
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
Callum Stewart / Jason Grossman +44 (0)20 7710 7600
Investec Bank plc
Joint Corporate Broker
Chris Sim / Jarrett Silver / Charles Craven +44 (0)20 7597 5970
Vigo Consulting
Public Relations
Patrick d'Ancona / Ben Simons
hurricane@vigoconsulting.com +44 (0)20 7390 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.
Hurricane also has a 50% interest in the Greater Warwick Area
licence, which contains the Lincoln and Warwick assets.
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
"A year of profound change"
Dear shareholders,
I am very pleased to introduce this annual report, the first
since I took on the role of Chairman of Hurricane in February 2022,
having joined the Board in October 2021.
2021 was a year of profound change for Hurricane as it moved
from a focus on ensuring its financial survival to a much more
upbeat consideration of its positive options for the future. That
process has continued in the first part of this year, at a time
when a highly volatile macro environment has heavily impacted the
backdrop for oil and gas companies.
Hurricane now stands in a much stronger financial position than
at this point twelve months ago, largely as a result of a
combination of very good operational performance at the Lancaster
field and continuing high oil prices resulting both from the easing
of pandemic restrictions and, more recently, the terrible events in
Ukraine, where we hope to see a peaceful resolution as soon as
possible.
Following a number of Board changes in 2021 and welcoming Juan
Morera of Crystal Amber Fund Limited in March this year, the
Company is clearly focused on determining its future path built
upon firm operational and commercial foundations. As the need for
domestic oil and gas supplies has been reinforced by the war in
Ukraine, the policy and regulatory environment for Hurricane
appears to be moving in a more supportive direction. We continue to
engage with all our key stakeholders as we determine the most
effective way to create value for investors.
Our priorities, as always, are safe, environmentally responsible
and effective operations through our offshore and onshore business
activities. I am very pleased to report that in 2021 the Company
undertook all production, marine and well operations safely against
a challenging COVID-19 backdrop. The focus both offshore and
onshore has been to provide a safe working environment throughout
the pandemic, with added safeguarding measures where necessary. The
Aoka Mizu FPSO at the Lancaster Field has again performed well with
excellent uptime. Our production averaged 10,267 barrels of oil per
day ("bopd") in 2021, and in the first quarter of 2022 it has been
9,372 bopd, maintaining this strong performance. We have,
throughout the year, continued with our commitment to regulatory
compliance and improved environmental stewardship; to that end we
have been able to cut our 2021 Scope 1 GHG emissions intensity on
the Aoka Mizu by over 10% .
Our current position contrasts with the challenging situation
Hurricane faced a year ago. As a result of the combined impact of
reservoir challenges at the Lancaster field identified in 2020,
which saw lower than originally predicted production levels due to
the field's well performance and markedly lower oil prices
following the emergence of COVID-19, the Board believed there was
significant doubt over the Company's ability to repay its $230
million Convertible Bond. Therefore, in late 2020, Hurricane
commenced engagement with stakeholders, including an ad hoc group
of its bondholders (the "Ad Hoc Committee"), to find a way to
ensure Hurricane had a viable financial platform on which to
operate and potentially invest further based on the Company's
anticipated cashflows.
Following those discussions, during the first half of 2021, the
Company proposed the implementation of a financial restructuring to
its bondholders and shareholders in order to provide the Company
and its stakeholders with more financial certainty. Following a
hearing at which the views of multiple stakeholders were presented,
including shareholders and bondholders, the High Court decided that
the restructuring should not be implemented.
In the wake of this decision, the Company's incumbent Chairman,
Steven McTiernan, and the other Non-Executive Directors, John van
der Welle, Sandy Shaw, Beverley Smith and Dr David Jenkins,
resigned from the Board on 29 June 2021. The Board thanks the
previous Chairman and the other Non-Executive Directors for their
contribution to the Board over their years of service. John Wright
and David Craik were appointed to the Board as Non-Executive
Directors on 29 June 2021 with Mr Wright assuming the position of
Interim Chairman, from which he stood down in February this year. I
joined the Board in October 2021 as an Independent Non-Executive
Director and was then appointed as Independent Non-Executive
Chairman in February 2022, with Mr Wright stepping back to be a
Non-Executive Director, and Juan Morera joined as Non-Executive
Director in March 2022.
In December 2021, the Company announced the completion of a
review, led by the Non-Executive Directors of the Company, of the
events leading up to the restructuring plan being rejected by the
High Court in June 2021, including decisions made by the Company's
previous Board relating to the Company's Convertible Bonds and the
restructuring plan. The review, having been requested by some
shareholders, was overseen by the Non-Executive Directors and
carried out by an independent solicitor assisted by leading
counsel. The review concluded that the Company's previous Board
discharged their fiduciary duties diligently and in good faith
during this time to address the fact that there was projected to be
a significant shortfall upon maturity of the bond, and they
received extensive advice from outside professionals on whom the
Company's previous Board could and did properly rely. The review
concluded that no further action was necessary, and that time and
resources should now be spent on maximising the future value and
potential of the Company.
The Company has been focused on improving its financial
situation and commencing in September 2021, the Company undertook a
number of bond repurchases, repurchasing approximately 66% of its
outstanding bonds at an average price of 86 cents in the dollar.
These repurchases have reduced the par value of bonds held by third
parties to $78.5 million, resulting in a combined net saving of
$29.5 million in debt repayment and interest charges. The Board is
now confident that the bond will be repaid in full in July 2022,
with the Company forecasting to be holding net free cash of at
least $60 million following the repayment, assuming oil prices
remain at over $90/bbl.
I believe firmly that the challenges of 2021 are behind us, and
the Board's focus is now very much on working with the senior
management team to determine the strategy that will create most
value for our investors and provide a sustainable and exciting
future for the business.
A number of options, by no means mutually exclusive, are under
review to take the Company forward, whether by further exploitation
of our existing portfolio, or entry to other assets within the
UKCS, and ultimately with the aim of building an asset base to
support capital returns to our investors. The senior management
team is focused on identifying the most effective capital
allocation to move Hurricane forward.
I look forward to updating stakeholders on our progress in due
course and thank you for your continued support.
I would also like to thank my fellow board members, and all of
the executive team and staff for their hard work, commitment and
resilience during this very challenging time.
Philip Wolfe
Chairman
Chief Executive Officer's Review
Introduction
2021 was a challenging year for Hurricane as we considered how
best to ensure a sustainable future for the business against a
volatile market backdrop, but I am pleased to report that the
Company has emerged from a difficult period in a much stronger
position than it entered last year, with a solid financial platform
coupled with very good operational performance at its Lancaster
field. It is a great credit to our team that we have delivered high
uptime and output within guidance at Lancaster. We are now able to
look forward and are working hard to identify how best to allocate
capital to create value for all our stakeholders.
Operational Review
Greater Lancaster Area ("GLA")
Operationally, 2021 was focused on managing production from the
Company's Lancaster field to maximise output via the Aoka Mizu FPSO
whilst also continuing our work to mitigate the impact of water cut
and pressure decline in the field's main producing well. Our
operational team's work resulted in an average production rate of
10,267 bopd for the period.
The production uptime during the year was an excellent 92.3%,
covering all planned and unplanned events. Overall, operational
performance at Lancaster was very strong, with the team's clear
focus on safety and environmental performance underpinning its
approach throughout the year.
Some operational challenges had to be overcome but were dealt
with effectively and safely. In early June 2021, the electric
submersible pump ("ESP") in the P6 well tripped, which led to
Lancaster production being temporarily reduced while the root cause
of the trip was investigated. The successful restart of the P6 well
was announced on 16 June 2021.
During 2021, seven cargoes of Lancaster oil were lifted,
totalling 3.6 MMbbls. Post period end, the 27th and 28th cargoes,
totalling approximately another 1.05 MMbbls, have already been
lifted in January and March respectively. The next cargo is
expected to be lifted in May 2022 by which time Lancaster will have
produced over 13 million barrels since startup.
In June 2021, the Company received approval of the Lancaster
Field Development Plan Addendum (the "FDPA") from the Regulator.
The FDPA approval, together with associated production, flare, and
vent consents, enables production with the bottom hole flowing
pressure up to 300 psi below the bubble point pressure of the fluid
(1,605 psia at 1,240 metres TVDSS), subject to the Company ensuring
that no incremental liberated gas is produced to surface.
The initial consent was for a three-month period from 16 June
2021 to 15 September 2021. Subsequent renewed production, flare,
and vent consents were received, and future consents are expected
to be issued on an ongoing three-monthly basis subject to
compliance with the terms of the FDPA. During December, the well
gauge pressure reached and declined below bubble point, in line
with the previously guided timing of this occurring between late
December 2021 and mid-February 2022. No production issues arising
from reaching bubble point have been observed to date. The Company
continues to monitor this issue closely and has continued to
receive the required consents from the Regulator on a three-monthly
basis.
In July 2021, the FPSO underwent a planned maintenance shutdown
which was completed safely with production restarting in a timely
manner, at an anticipated elevated production rate leading to the
average oil rate for August being higher than in previous months.
This then returned, as expected, to the trend seen throughout the
rest of the year.
In September 2021, the Company provided production guidance for
the six-month period 1 October 2021 to 31 March 2022 of 8,500 -
10,000 bopd, based on FPSO production uptime assumption (excluding
annual maintenance shutdown) of 96.5% and production from the P6
well alone on artificial lift via ESP. Production during this
6-month period was 9,689 bopd, reflecting continued excellent
uptime on the FPSO combined with production rates towards the top
of the guided range.
Production guidance for the full calendar year 2022 is 7,500 -
8,600 bopd. This is based on production from the P6 well alone on
artificial lift via ESP, an annual maintenance shutdown anticipated
to occur during Q3 2022, and overall FPSO production uptime outside
of the shutdown window of 96.5%. As of 17 April 2022, Lancaster was
producing c.9,150 bopd from the P6 well alone with an associated
water cut of c. 43%, in line with guidance.
In June 2021, the Company resolved not to exercise its option to
extend the bareboat charter of the Aoka Mizu FPSO for an additional
three years to June 2025 as it was deemed at that juncture, from a
commercial and fiduciary perspective, not to be in the best
interest of the Company or its stakeholders given the significant
financial obligations exercising the extension option would have
entailed. The initial three-year term was due to expire in June
2022. Hurricane subsequently concluded positive negotiations with
Bluewater (Aoka Mizu) B.V. ("Bluewater"), the owner of the Aoka
Mizu FPSO, with regards to an alternative 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 bond. Based
on the current oil price and field performance predictions we
forecast this to be at least 18 months from 4 June 2022.
In addition to the charter extension, the Company also announced
that it had negotiated with BP Oil International Limited ("BP"),
the purchaser of its crude oil, a facility that will allow for cash
to be advanced ahead of a lifting, drawing down against oil
produced and held in the FPSO's tanks but not yet lifted. This
provides the ability to create more frequent cash receipts and
assist with the Company's working capital. The facility incurs a
financing fee that is only payable if the Company uses it.
Greater Warwick Area ("GWA")
The GWA JV (Hurricane 50%, Spirit Energy 50%) has reassessed its
understanding of the area, evaluating both the basement and the
Mesozoic potential of the licences and has considered all options
for further appraisal and routes to possible development. Owing to
the disruption caused by the COVID-19 pandemic, an agreement was
reached with the Regulator to extend the deadline for commencement
of the Lincoln obligation well ("Lincoln Well") from 31 December
2020 to 30 June 2022.
Following the technical re-evaluation and interpretation of the
area, the GWA JV further engaged with the Regulator to seek an
appropriate extension to the timeframe for this commitment, beyond
30 June 2022. As announced on 17 December 2021, the Regulator had
indicated that in the current circumstances it was not content to
support a further deferral of the Lincoln Well. As such, the GWA JV
elected to suspend further funding towards planning and drilling of
the obligation Lincoln Well in 2022 while it continued its
discussions with the Regulator.
Efforts to realise value for its equity share of the GWA assets,
including the possibility of third-party funding for the drilling
of the Lincoln Well, were explored by Hurricane with a significant
number of external parties, however, these did not result in
formalising any interest to secure third party investment in the
GWA assets.
Hurricane has determined that further appraisal and development
costs to reach an economic development on Lincoln within acceptable
risk and licence timing is not feasible for the Company on a
standalone basis. Further to discussions with our JV partner,
Spirit Energy, the GWA JV has taken the decision to surrender the
Lincoln P1368(S) licence sub area. With access to limited funds,
and no reasonable expectation that the Lincoln discovery could
generate any meaningful near-term cash realisation in comparison to
the other options currently under consideration, voluntarily
surrendering the Licence is the right choice. This gives rise to an
impairment charge of $54.3 million against the full carrying value
of the Lincoln asset in the Company's accounts.
Decommissioning Activities
In July 2021, Hurricane completed the plugging and abandonment
("P&A") of the 205/26b-14 ("Lincoln-14") well, which Hurricane
conducted on behalf of the GWA JV. Hurricane contracted the Stena
Don semi-submersible rig with the operation completed within both
schedule and budget. The GWA JV had a regulatory obligation to
P&A the Lincoln-14 well by 31 October 2021, and this obligation
was fulfilled in advance of this date.
During November 2021, the Company successfully completed the
P&A of the Lancaster 205/21a-4z well for a cost of c.$1
million. $2.2 million of decommissioning security (previously
classified as restricted cash) was released back to the Company and
used in part to fund this P&A activity.
Subsequent to the year end, 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 2021, Hurricane recorded one Lost Time Incident, when an
offshore technician sustained a hand injury whilst undertaking
maintenance activities. The individual made a full recovery. The
incident was fully investigated by Bluewater and Hurricane.
The Lost Time Incident Frequency rate for 2021 was 1.71,
compared to 1.29 for 2020.
Throughout the year COVID-19 continued to feature highly on
Hurricane's risk register. We have continued to work closely with
our stakeholders and government authorities to manage the impact of
COVID-19 on all aspects of our business during 2021.
Safeguarding measures were put in place to manage the health and
safety of offshore personnel. These measures included
pre-mobilisation COVID-19 testing, use of face coverings during
transit to the FPSO by helicopter, daily COVID-19 health screening
on the FPSO and the wearing of face masks offshore, where
practicable, to prevent airborne transmission. Our installation
operator, Bluewater, has put in place a COVID-19 hazard
identification risk assessment aimed at preventing outbreaks of
COVID-19 offshore and, if cases occur, managing any outbreaks on
the FPSO. Offshore medics have been trained in the use of testing
equipment, which has been vital for the early detection, isolation,
and repatriation to shore of COVID-19 cases.
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 COVID-19 flying arrangements, with attendant
paramedics, have been put in place 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.
ESG and gas export update
In June 2021, Hurricane published its second standalone
Environmental, Social and Governance ("ESG") report. The report
covered Hurricane's approach to ESG and performance across its
operations for the 2020 calendar year. It will publish its third
ESG report later this year.
During 2021, our Scope 1 greenhouse gas emissions were 139,584
tonnes CO(2) e, or 37.2 kg/bbl on an intensity basis. This compared
with 210,884 tonnes CO(2) e and 41.5 kg/bbl in 2020. These
emissions meet the OEUK Scope 1 definition and include CO(2) as
well as other greenhouse gases specified by the Kyoto Protocol.
These figures and are based on Intergovernmental Panel on Climate
Change's ("IPCC") Fifth Assessment report, whereas previously,
Hurricane reported using IPCC's Fourth Assessment report. Figures
for 2020 have therefore been restated and align with the NSTA's
reporting metrics. We believe this provides a more complete picture
of our emissions performance and will allow for easier annual
comparisons in the future.
On the FPSO there has been a particular focus on optimising
power generation following successful FPSO power management system
testing and a revision to the FPSO's power generation strategy.
This has led to a reduction in power generation emissions of 42,727
tonnes CO(2) in 2020 to 33,208 tonnes CO(2) in 2021.
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 2022 and beyond where it is
economically and commercially viable to do so.
Bond tenders
In September 2021, the Company undertook a bond tender exercise,
repurchasing approximately 34% of its outstanding bonds at a price
of 78 cents in the dollar. This reduced the par value of bonds held
by third parties to $152 million, using $62 million of net free
cash, inclusive of accrued interest. The Company completed three
further repurchases during December 2021: first it completed the
repurchase of a further $15.0 million of its bonds for a total
consideration of $14.0 million, including accrued interest; then it
repurchased an additional $28.5 million for a total consideration
of $27.3 million, including accrued interest; and finally it
repurchased an additional $30.0 million in aggregate principal for
a total consideration of $29.0 million, including accrued interest.
The net effect of these purchases was that by the end of 2021, the
nominal value of the Company's outstanding bonds had reduced to
$78.5 million, and a total of $29.5 million of savings had been
achieved.
Reserves and resources
While the Lancaster field EPS was developed on time and on
budget with first production achieved in May 2019, the field has
significantly underperformed pre-production expectations. Following
the full technical review of the Lancaster field and the Company's
wider West of Shetland portfolio in 2020 and the independent
assessment of the Company's assets, published in April 2021,
additional detailed subsurface and reservoir performance analysis
has been ongoing throughout the year.
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 in April
2022. Their estimates of Lancaster field Reserves and the
Contingent Resources are detailed in the tables below. Year on year
comparison shows an increase in developed reserves, in part due to
the implications of the Lancaster field's performance during 2021
and in part due to high oil price assumptions.
People and operations
I would also like to express my thanks to all our colleagues
whose hard work, professionalism and dedication during a
challenging year has ensured Hurricane's operational delivery since
start-up of the Lancaster field has been first class. Many months
of work on the technical review and development options screening
has been compressed into a fraction of that time without
compromising on rigour or quality.
The health and safety of our onshore colleagues has also been a
priority given the home working arrangements put in place in March
2020 to manage the spread of COVID-19. Our onshore staff have
primarily been working from home since that time and, where
possible, we actively encouraged flexible working recognising that
employees may have responsibility for childcare, home schooling,
family members as well as other obligations during the pandemic. We
have conducted home working assessments to ensure that our staff
have the necessary equipment and appropriate working conditions for
safe and effective remote working. We have also introduced
initiatives to address staff isolation and encourage contact
between colleagues while we are working remotely.
Feedback from employee engagement suggested that as we returned
to the office, our employees wished to preserve some measure of
home working, and we have aimed to achieve this where possible. Our
offices reopened on 8 November 2021, with the implementation of a
trial hybrid working arrangement requiring two days' office
attendance per week. With the resurgence of the COVID-19 Omicron
variant, we took the decision to curtail the hybrid working
arrangement on 9 December 2021, returning to home working.
Following the Government's relaxation of COVID-19 precautionary
measures, we reopened the office in February 2022, returning to the
earlier hybrid working arrangement. We continue to monitor the
prevalence of COVID-19 in the workplace and society at large, in
order to ensure we apply suitable safeguarding measures to
personnel both onshore and offshore.
Outlook
The Company anticipates that production from Lancaster will be
in the range of 7,500 - 8,600 bopd during 2022, including a usual
period of scheduled maintenance and uptime of 96.5% outside of the
maintenance window. We expect water cut to increase and pressure
decline to continue but still see the field as highly cash
generative at current commodity prices.
With the expectation that oil prices remain over $90/bbl, post
bond repayment we forecast to have over $60 million of net free
cash . Our thoughts are therefore fully focused on building on our
position of increasing strength and value. Against the backdrop of
our demonstrable operational track record, financial discipline,
and the significant rise in oil prices, we are preparing Hurricane
for the future. The UK Government's renewed emphasis on security of
supply is welcome and we are working hard to identify how best to
optimise capital allocation in future activities to build further
value for our shareholders, whether through further investment in
our existing portfolio, new opportunities in the UK oil and gas
sector, or both.
Antony Maris
Chief Executive Officer
Lancaster Reserves and Resources
While the Lancaster field EPS was developed on time and on
budget with first production achieved in May 2019, the field has
significantly underperformed pre-production expectations. Following
the full technical review of the Lancaster field and the Company's
wider West of Shetland portfolio in 2020 and the independent
assessment of the Company's assets, published in April 2021,
additional detailed subsurface and reservoir performance analysis
has been ongoing throughout the year.
Hurricane elected to retain ERCE to update its CPR on the
Reserves and Contingent Resources of the Lancaster field, published
in April 2022. ERCE's work has been prepared in accordance with the
June 2018 Petroleum Resources Management System (PRMS) as the
standard for classification and reporting with an effective date of
31 December 2021.
ERCE's estimates of Lancaster field Reserves and the Contingent
Resources are detailed in the tables below. Year on year comparison
shows an increase in developed reserves, in part due to the
implications of the Lancaster field's performance during 2021 and
in part due to higher oil price assumptions.
The Company's ability to monetise its Contingent Resources will
require further technical appraisal, a commercially viable
development plan to be agreed, sufficient additional funding for
further appraisal and development, and regulatory consents. The
funding of any appraisal and/or development activity, and the
Company's financial planning more broadly, needs to consider the
Company's existing financial and contractual obligations, such as
decommissioning and costs associated with the charter and operation
of the Aoka Mizu.
ERCE's estimates of Reserves for the Lancaster field as of 31
December 2021
(MMbbl) Gross Net attributable to
Hurricane
1P 2P 3P 1P 2P 3P
---- ---- ---- ------- ------- ------
Developed
Reserves (MMbbl)(1) 4.1 5.8 9.1 4.1 5.8 9.1
---- ---- ---- ------- ------- ------
1. In determining the economic Reserves for the Lancaster field,
ERCE has assumed a nominal Brent oil price forecasts as of 31
December 2021 of US$75/bbl in 2022, US$71/bbl in 2023, US$69/bbl in
2024 and US$70/bbl in 2025 and constant thereafter in real terms.
In line with PRMS guidelines, the nominal oil prices assumed are
those forecasts made as at the effective date of the CPR, being 31
December 2021. Prices are escalated at 2.0% per annum
inflation.
ERCE's estimates of Contingent Resources for the Lancaster field
at 31 December 2021
(MMbbl) Gross Net attributable to
Hurricane
1C 2C 3C 1C 2C 3C
----- ----- ----- ------- ------- ------
Contingent Resources,
Development Unclarified
(2) 11.3 35.4 86.9 11.3 35.4 86.9
----- ----- ----- ------- ------- ------
2. Contingent Resources, Development Unclarified, assume
additional development wells and/or water injection is implemented
as part of any further development; and contingent on regulatory
consents, funding and execution during the lifetime of the existing
Lancaster wells.
A summary of the movements in net attributable 2P Reserves as
compared to the previous CPR (effective date of 31 December 2020)
is as follows:
Net attributable 2P Reserves
(MMbbl)
At 31 December 2020 7.1
Produced during the year (3.7)
Change in assumptions and economic
life 2.4
------------------------------------ -----------------------------
At 31 December 2021 5.8
------------------------------------ -----------------------------
Chief Financial Officer's Review
Highlights
2021 2020
Production 3,748 Mbbl 5,078 Mbbl
------------ ------------
Production rate* 10,300 bopd 13,900 bopd
------------ ------------
Sales volumes 3,576 Mbbl 5,112 Mbbl
------------ ------------
Revenue $240.5m $180.1m
------------ ------------
Average sales price realised $67.3/bbl $35.2/bbl
------------ ------------
Cash production cost per barrel $28.2/bbl $17.9/bbl
------------ ------------
Free cash flow $135.7m $74.2m
------------ ------------
Free cash flow per barrel $36.2/bbl $14.6/bbl
------------ ------------
Net free cash $51.5m $111.4m
------------ ------------
Net debt $27.0m $118.6m
------------ ------------
Underlying profit/(loss) before
tax $10.8m $(36.0)m
------------ ------------
Statutory profit/(loss) after
tax $18.2m $(625.3)m
------------ ------------
* Rounded to nearest 100 bopd.
Non-IFRS measures. See Appendix B for definition and
reconciliation to nearest equivalent statutory IFRS measures.
Overview
2021 was a year of recovery and consolidation for Hurricane,
benefitting from the continuous rise and recovery in the oil price,
but also taking steer from the Court's decision not to sanction the
proposed financial restructuring and looking to actively manage the
Company's net debt position.
Over 3.5 million barrels of Lancaster crude were sold across
seven cargoes, generating over $240 million in revenue thanks to
the strong oil prices seen in 2021 compared to 2020. This, combined
with a continued focus on low operating costs and excellent
production efficiency produced free cash flow of $135.8 million.
Cash capex was $21.4 million, largely comprising previously
committed to long-lead items for future tie-back and gas export
works, capitalised G&A relating to potential Lancaster
enhancement projects, and decommissioning spend primarily on the
Lincoln-14 well, which was completed significantly under
budget.
In the second half of the year, Hurricane took steps to actively
manage its net debt position, spending $132 million to repurchase
and cancel just over two-thirds of the outstanding Convertible
Bonds, saving $29.5 million in future principal repayments and
interest.
Although uncertainties still remain, with oil prices still
supportive albeit volatile, and a significantly reduced net debt
position, the financial outlook for Hurricane is now significantly
improved as we look beyond repayment of the remaining Bond debt and
towards new opportunities to deliver value.
Proposed financial restructuring
Towards the end of 2020, following the downgrade of our reserves
and the suspension of production guidance, the Company was
forecasting a shortfall of over $100 million in relation to its
ability to fully repay its bonds at maturity. Given the magnitude
of this shortfall, Hurricane entered into meaningful discussions
with the Bondholders regarding the ability to fully repay the
Convertible Bond debt due in July 2022. This culminated in a
proposed financial restructuring, which would have resulted in
reduced and restructured Bonds, dilution for existing shareholders,
but greater certainty over Hurricane's solvency, and a potential
solution to drill an additional well on the Lancaster field.
Throughout the process up to the Court sanction hearing, the
Group's projections were still showing a significant shortfall in
being able to fully repay the Convertible Bond. These projections
were on the basis of management's production forecasts combined
with the best available oil price forecasts, using forward curves
and analyst estimates. At the time, none of those forecasts and
estimates showed a scenario whereby there would be a full repayment
of the Bond; it was not an option to ignore those projections and
continue operating as usual in the hope that the best available
research and estimates on oil price would turn out to be materially
incorrect.
As part of the restructuring process production forecasts were
provided covering the period from June 2021 onwards. In the period
from June 2021 to March 2022, cumulative actual production was only
marginally (2.7%) above these forecasts. The positive change in the
financial circumstances of the Company has been brought about
mainly by the continued, significant and unexpected rise in oil
prices, but also impacted by the cost cutting measures implemented
by the Company and the savings from the bond buy backs.
Revenue
Revenue recognised for the year was $240.5 million (2020: $180.1
million), with an average realised price of $67.3/bbl ($35.2/bbl)
across 7 cargoes comprising nearly 3.6 million barrels (2020: 12
cargoes comprising 5.1 million barrels). Whilst the average Dated
Brent price for the year was $70.9/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 2021 to minimise transportation costs per
barrel.
The average netback to the contractual Brent price was $2.7/bbl
(2020: $2.9/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 means that Hurricane has continued to sell all cargoes on
time, within specification and contractual terms, maintaining our
reputation as a reliable producer. This strong reputation helped in
Lancaster crude being sold and delivered to two new refineries
during 2021. A growing pool of buyers should result in more
competitive bids for Lancaster crude and in turn higher overall
realised prices received going forward.
The sales arrangement with BP means that Hurricane receives cash
for a sale typically within five days of the lifting occurring.
With production continuing to naturally decline, the period between
liftings will increase. As such, Hurricane has agreed a facility
with BP that will allow for cash to be advanced ahead of a lifting,
drawing down against oil produced and held in the FPSO's tanks but
not yet lifted, to create more frequent cash receipts and assist
with the Company's working capital. This facility, which takes
effect from end of July 2022, incurs a small financing fee that is
only payable if the Company uses it.
Cost of sales
Total cost of sales was $173.1 million (2020: $179.8 million),
including $97.6 million of DD&A (2020: $96.6 million). Cash
production costs were $105.8 million (2020: $90.6 million),
equivalent to $28.2 per barrel (2020: $17.9/bbl).
Excluding the revenue-linked incentive tariff, cash production
costs per barrel increased from $14.6/bbl in 2020 to $22.8/bbl in
2021. This increase per barrel was driven by lower average
production rates in 2021 and the contractual increase to the FPSO
day rate from $25,000/day to $75,000/day effective from June 2021.
Excluding the incentive tariff, cash production costs per barrel
for H2 2021 (a period wholly including the increased day rate) were
$26.8/bbl. With a cost base that is largely fixed, natural decline
in production and inflationary cost pressures, we expect cash
production costs per barrel to increase during 2022; although we
continue to look for cost savings internally and with our key
contractors where possible.
Impairment of intangible assets and GWA licences
During the year, the GWA JV was in engagement with the Regulator
on the technical re-evaluation and interpretation of the GWA
licence potential, and requested a regulatory amendment of the
obligation to drill a well on the Lincoln licence, which must be
commenced on or before 30 June 2022, to a later commencement date.
The Regulator indicated that it was not content to support a
deferral of the obligation well. Following discussions within the
JV, the partners elected to continue their plans to suspend further
funding towards well planning and drilling of the obligation well
on Lincoln in 2022; however, funds continued to be made available
in 2022 to further evaluate the area's prospectivity. Whilst
meaningful discussions were held during the year between Hurricane
and potential third parties to enter into the licence, these did
not result in any formalised interest.
Having noted the announcements on 8 December 2020 by Spirit
Energy and its largest shareholder, Centrica plc, regarding the
strategic focus of its remaining UK assets and the limitation of
any further investment in exploration and appraisal, and also
taking into account Hurricane's financial circumstances and the
related challenges of securing additional funding for the Lincoln
obligation well, it was concluded that there was a reasonable
prospect that the JV would be unable to either spud the obligation
well by the required deadline or to obtain a deferral of the
obligation well. In addition, Hurricane determined that further
appraisal and development costs to reach an economic development on
Lincoln within acceptable risk and licence timing is not feasible
for the Company on a standalone basis. As such, in April 2022, the
JV voted to voluntarily surrender the P1368(S) licence sub area. In
anticipation of this, the carrying value of the Lincoln assets has
been fully impaired, resulting in an impairment charge of $54.3
million.
FPSO lease
On 4 June 2021, Hurricane announced that it 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. For
the purposes of accounting for the lease under IFRS 16, the lease
term was re-assessed to end in June 2022 (previously June 2025).
This has resulted in a write-back of the lease liability and
corresponding lease asset. As the lease asset had previously been
impaired to materially less than the liability, under accounting
rules the difference was credited to the income statement,
resulting in a non-cash gain of $49.1 million.
In March 2022, Hurricane announced it had concluded an agreement
with Bluewater to extend the charter indefinitely beyond June 2022,
with either party being able to give six months' notice to
terminate the arrangement. The existing day rate and tariff for the
vessel remains at $75,000 per day and 8% of revenue respectively,
and a secured deposit account of up to $18.7 million for the
benefit of Bluewater has been established 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 opportunity
and flexibility to cover production from the Lancaster field for
its remaining economic life, which is forecast to be at least 18
months from June 2022.
Convertible Bond and debt management
In order to take advantage of the Group's strong cash position
and the market price of the Convertible Bonds, in September 2021
Hurricane successfully completed a tender programme for repurchase
of some of its bonds, repurchasing $78.0 million of outstanding
Convertible Bonds for cancellation at a discount of 78% to face
value. During December 2021, a series of additional bond repurchase
transactions were made, repurchasing an additional $73.5 million of
Bonds at an average discount of 95% to face value. The total amount
of Bonds repurchased and cancelled was $151.5 million, for a total
cash consideration of $132.0 million (including accrued interest).
These buybacks generated a combined net saving of $29.5 million of
future principal repayment and interest charges, significantly
improving the net debt position and giving the Group clearer line
of sight to full Bond repayment. At 31 December 2021, $78.5 million
of Convertible Bonds remained outstanding.
The repurchase of the Bonds at a discount gave rise to a gain of
$17.2 million (net of transaction costs). The remeasurement of the
embedded derivative component of the Convertible Bond gave rise to
a fair value loss of $1.9 million.
Other profit and loss
Net general and administrative costs ("G&A") before non-cash
items increased from $2.9 million in 2020 to $23.6 million in 2021.
This increase was primarily due to the significant expenditures
incurred on the proposed financial restructuring (see above), and a
higher level of G&A costs capitalised or recharged into
projects or cost of sales in 2020 as compared to 2021 (see note 3.3
to the Financial Statements). Towards the end of the year, the
Group moved to identify cost savings through a right-sizing of
headcount (via recruitment freezes and targeted redundancies),
partially offset by the cost of retention arrangements put in place
for remaining key employees. As at April 2022, excluding
Non-Executive Directors, the Group's headcount had reduced to 27
employees, compared to an average of 51 throughout 2021.
Cashflow
The Group ended the year with $51.5 million of net free cash , a
decrease of $59.9 million from the position of $111.4 million at 31
December 2020.
Free cash flow for the year was $135.7 million (2020: $74.2
million), equivalent to $36.2/bbl (2020: $14.6/bbl), driven by
higher average realised Brent prices offset by the increase in day
rate payable for the Aoka Mizu charter which became effective from
June 2021.
Cash capex in the period was $21.4 million, $4.8 million of
which was Hurricane's share of decommissioning costs paid in the
year on the Lincoln 14 and Lancaster 4Z wells. The balance of
capital expenditure on GLA reflected previously committed to
long-lead items for potential additional wells and gas export
activity, licences, studies, and capitalised timewriting costs
scoping production enhancement and development opportunities for
the Lancaster field. Cash capex on GWA comprised Hurricane's share
of previously committed to long-lead items for a potential Lincoln
tie-back, licences, and the storage and preservation of well spares
inventory and tie-back equipment. Given the uncertainty over the
timings of future drilling campaigns and well tie-backs, the joint
venture is exploring opportunities and options to realise value
from the inventory currently held in storage.
Restricted funds
As of 31 December 2021, the Group held $45.7 million of cash and
liquid investments within restricted funds, relating to
decommissioning security arrangements and amounts set aside to
cover potential early termination fees on the FPSO lease.
Under the FPSO charter the Group was required to hold in reserve
and escrow accounts the termination costs of the FPSO lease should
the Group wish to terminate the charter early. This balance would
have had to increase significantly, to $56 million, if the Group
exercised the charter's extension option to June 2025, which it
would have been required to do by June 2021. Given the Group's
financial position and forecasts at the time, combined with the
uncertainty over the life of the Lancaster field, it was therefore
not appropriate to extend the charter for three years on these
terms. As the option was not exercised, the amounts held as
restricted funds were able to be released straight line to free
cash from between June 2021 and June 2022. The balance classified
as restricted cash under this arrangement as at 31 December 2021
was $7.9 million (31 December 2020: $26.5 million). As part of the
agreement to extend the FPSO charter, this amount is anticipated to
increase to $18.7 million during 2022 and is expected to remain at
that level until either party gives six months' notice to terminate
the charter.
At the start of the year, the Group held GBP16.8 million ($22.8
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.
This security was posted on a post-tax basis. In April 2021, the
Regulator formally notified the Group of its intention to request
an increase to the amount of decommissioning security for the
Lancaster field, so that it is lodged on a pre-tax basis. Following
this request, we agreed with the Regulator to place an additional
GBP11.2 million ($15.5 million) of funds into trust. At 31 December
2021, a total of $37.8 million was held in trust as decommissioning
security for the Lancaster EPS. Subsequent to the balance sheet
date, an additional $7.7 million was placed into Trust following a
request from the Regulator as a result of increases to our
decommissioning estimates.
Following the abandonment of the Lancaster 205/21a-4z well
during the year, $2.2 million of additional decommissioning
security related specifically to this activity was released to free
cash.
Decommissioning
The Group holds accounting provisions totalling $49.3 million
for the anticipated cost of plugging and abandoning the Lancaster
P6 and P7z wells, removing the associated subsea infrastructure and
related FPSO costs to the Lancaster EPS and FPSO, for which
decommissioning security of $37.8 million is held in trust
(subsequently increased by an additional $7.7 million in February
2022). Changes in estimates during the year resulted in a non-cash
charge of $2.0 million, being those changes in estimate related to
the FPSO and fully impaired assets.
During the year, the abandonment of the Lincoln 205/26b-14 well
was completed, as required under our licence obligation, at a gross
cost of $8.6 million. This was significantly below the previously
provided for cost of $13 million, thanks to the hard work of the
contracting and operations team, rig contractor, and the joint
venture partner support. During the year the suspended Lancaster
205/21a-4z well was also plugged and abandoned at a cost of $1.3
million.
Tax
The Group recognised a total tax credit for 2021 of $0.03
million, all of which related to deferred tax and was non-cash.
During 2021, Hurricane 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. Subsequent to
the balance sheet date, $4.3 million was received in respect of
these claims and will be recognised in 2022.
Tax losses
Due to the nature of the Group's business, it has accumulated
significant tax losses since incorporation. The Group has $381.9
million of ring-fenced trading losses and other allowances and
supplementary charge losses and investment allowances of $693.0
million, which have no expiry date and would be available for
offset against future trading profits, and $328.4 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 $409.7 million. This is the maximum possible theoretical
value and is subject to timing and circumstance; and it is unlikely
that all of the potential value would be able to be realised. 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. Other tax losses can only be
utilised over a longer period of time, and pre-trading expenditure
losses will expire should trade not commence in those entities with
pre-trading losses within a certain period of time of those losses
originally being incurred. At prevailing oil prices, the Group will
continue to utilise its existing ring fence losses as the Lancaster
EPS generates taxable profits.
Richard Chaffe
Chief Financial Officer
Going concern
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
$114.6 million of cash and cash equivalents and liquid investments,
of which $68.9 million was unrestricted. After adjusting for
working capital items, net free cash at 31 December 2021 was $51.5
million. The Group's most significant long-term liabilities are the
remaining $78.5 million of Convertible Bonds in issue due in July
2022 (with a coupon of 7.5% payable quarterly in arrears) and
committed lease liabilities in respect of the Aoka Mizu FPSO.
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 the Group Financial Statements.
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
The Group's base case going concern assessment assumed the
following:
-- average Dated Brent oil price of $102/bbl and $89/bbl in 2022 and 2023 respectively;
-- 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 supported by the most recent
CPR.
Under the base case scenario, the Group had sufficient liquidity
to fully repay the remaining Convertible Bonds at their maturity in
July 2022 with sufficient headroom thereafter for a period of at
least 12 months from the date of this report 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 25% reduction to forecast production rates
Under the sensitivity cases above, both individually and in
aggregate, the Group is projected to have sufficient cash to fully
repay the Convertible Bonds and 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 repay its Convertible Bonds in
July 2022. These stress tests indicated that a reduction to the
forecast oil price curve by $65/bbl, or a reduction to projected
production rates by 60%, would result in the Group having
insufficient cash to repay the Convertible Bond in full in July
2022. 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 fully repay the Bonds is unlikely to occur.
Conclusion
As a result of the going concern assessment presented above, the
directors have a reasonable expectation that, after also taking
into consideration the current macroeconomic situation and
uncertainty arising from the COVID-19 pandemic, 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.
Group Statement of Comprehensive Income
Year ended Year ended
Notes 31 Dec 2021 31 Dec 2020
$'000 $'000
Revenue 2.1 240,540 180,083
Cost of sales 2.2 (173,125) (179,816)
--------------------------------------- ----- ----------- -----------
Gross profit 67,415 267
General and administrative expenses 3.3 (26,749) (4,229)
Gain on revision of lease term 5.2 49,125 -
Impairment of oil and gas assets 2.3 - (519,152)
Change in decommissioning estimates
on fully impaired assets 2.5 (1,972) -
Impairment of intangible exploration
and evaluation assets and exploration
expense written off 2.4 (54,280) (47,945)
--------------------------------------- ----- ----------- -----------
Operating profit/(loss) 33,539 (571,059)
Finance income 3.2 27 2,696
Finance costs 3.2 (30,656) (38,160)
Net gain on repurchase of Convertible
Bonds 5.1 17,201 -
Fair value (loss)/gain on Convertible
Bond embedded derivative 5.1 (1,901) 35,431
Profit/(loss) before tax 18,210 (571,092)
Tax 6.1 26 (54,233)
--------------------------------------- ----- ----------- -----------
Total comprehensive profit/(loss)
for the year 18,236 (625,325)
--------------------------------------- ----- ----------- -----------
Cents Cents
Earnings per share - basic and diluted 3.1 0.92 (31.43)
--------------------------------------- ----- ----------- -----------
All results arise from continuing operations.
Group Balance Sheet
Notes 31 Dec 2021 31 Dec 2020
$'000 $'000
Non-current assets
Intangible exploration and evaluation
assets 2.4 3,830 55,390
Oil and gas assets 2.3 98,296 208,027
Other non-current assets 1,373 2,605
Deferred tax assets 104 78
Liquid investments 4.1 37,783 22,811
141,386 288,911
-------------------------------------- ----- ----------- -----------
Current assets
Inventory 2.2 27,488 11,285
Trade and other receivables 2,591 14,524
Cash and cash equivalents 4.1 76,792 143,703
-------------------------------------- ----- ----------- -----------
106,871 169,512
-------------------------------------- ----- ----------- -----------
Total assets 248,257 458,423
-------------------------------------- ----- ----------- -----------
Current liabilities
Trade and other payables (18,843) (16,356)
Lease liabilities 5.2 (13,880) (18,479)
Convertible Bond liability 5.1 (77,373) -
Convertible Bond embedded derivative 5.1 (27) -
Decommissioning provisions 2.5 - (15,466)
-------------------------------------- ----- ----------- -----------
(110,123) (50,301)
-------------------------------------- ----- ----------- -----------
Non-current liabilities
Lease liabilities 5.2 (1,910) (78,842)
Convertible Bond liability 5.1 - (216,034)
Convertible Bond embedded derivative 5.1 - (885)
Decommissioning provisions 2.5 (49,346) (45,675)
-------------------------------------- ----- ----------- -----------
(51,256) (341,436)
-------------------------------------- ----- ----------- -----------
Total liabilities (161,379) (391,737)
-------------------------------------- ----- ----------- -----------
Net assets 86,878 66,686
-------------------------------------- ----- ----------- -----------
Equity
Share capital 2,885 2,885
Share premium 822,458 822,458
Share option reserve 23,321 21,443
Own shares reserve (845) (923)
Foreign exchange reserve (90,828) (90,828)
Accumulated deficit (670,113) (688,349)
-------------------------------------- ----- ----------- -----------
Total equity 86,878 66,686
-------------------------------------- ----- ----------- -----------
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 2020 2,883 821,910 20,828 (684) (90,828) (63,024) 691,085
Loss for the period - - - - - (625,325) (625,325)
New shares issued
under employee share
schemes 2 548 - (445) - - 105
Share-based payments - - 615 206 - - 821
---------------------- -------- ------- ------- ---------- -------- ----------- ---------
At 31 December 2020 2,885 822,458 21,443 (923) (90,828) (688,349) 66,686
Profit for the period - - - - - 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
---------------------- -------- ------- ------- ---------- -------- ----------- ---------
Group Cash Flow Statement
Restated
Year ended Year ended
Notes 31 Dec 2021 31 Dec 2020
$'000 $'000
Cash flows from operating activities
Operating profit/(loss) 33,539 (571,059)
Adjustments for:
Depreciation of property, plant
and equipment 2.3 98,100 97,136
Impairment of oil and gas assets 2.3 - 519,152
Change in decommissioning estimates
on fully impaired assets 2.5 1,972 -
Impairment of intangible exploration
and evaluation assets and exploration
expense written off 2.4 54,280 47,945
Gain on lease remeasurement 5.2 (49,125) -
Impairment of other right-of-use
assets 719 -
Share-based payment charge 1,955 821
Purchase of derivative financial
instruments - (3,420)
Expenditure on proposed financial
restructuring 15,903 1,550
Decommissioning spend 2.5 (4,824) (2,108)
------------------------------------------ ----- ----------- -----------
Operating cash flow before working
capital movements 152,519 90,017
Movement in receivables 579 159
Movement in payables 5,356 (10,352)
Movement in crude oil, fuel and
chemicals inventories 2.2 (11,410) 1,946
Net cash inflow from operating
activities 147,044 81,770
------------------------------------------ ----- ----------- -----------
Cash flows from investing activities
Interest received 27 1,227
Increase in liquid investments (15,530) (22,811)
Expenditure on oil and gas assets (6,618) (23,396)
Expenditure on other fixed assets (2) (69)
Expenditure on intangible exploration
and evaluation assets (2,782) (35,269)
Movement in spares and supplies
inventories 2.2 (4,793) (3,286)
Net cash used in investing activities (29,698) (83,604)
------------------------------------------ ----- ----------- -----------
Cash flows from financing activities
Repurchases of Convertible Bond
principal for cancellation 5.1 (130,346) -
Transaction costs 5.1.1 (1,311) -
Convertible Bond interest paid 5.1 (17,372) (17,250)
Lease repayments 5.2 (18,596) (9,658)
Interest and other finance charges
paid (34) (15)
Expenditure on proposed financial
restructuring (15,903) (1,550)
New shares issued under employee
share schemes - 105
------------------------------------------ ----- ----------- -----------
Net cash used in financing activities (183,562) (28,368)
------------------------------------------ ----- ----------- -----------
Decrease in cash and cash equivalents (66,216) (30,202)
------------------------------------------ ----- ----------- -----------
Cash and cash equivalents at beginning
of year 4.1 143,703 171,434
Net decrease in cash and cash equivalents (66,216) (30,202)
Effects of foreign exchange rate
changes (695) 2,471
------------------------------------------ ----- ----------- -----------
Cash and cash equivalents at end
of year 4.1 76,792 143,703
------------------------------------------ ----- ----------- -----------
The presentation of certain comparative lines has been restated
- see note 1.4.
Notes
Section 1: General Information
1.1 Basis of preparation
The consolidated Financial Statements of Hurricane Energy plc
for the year ended 31 December 2021 were authorised for issue by
the directors on 27 April 2022. 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
registered office is Ground Floor, The Wharf, Abbey Mill Business
Park, Lower Eashing, Godalming, Surrey, GU7 2QN.
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 international
accounting standards in conformity with the requirements of the
Companies Act 2006 and in accordance with the requirements of the
AIM Rules.
On 31 December 2020, IFRS as adopted by the European Union at
that date was brought into UK law and became UK-adopted
International Accounting Standards, with future changes being
subject to endorsement by the UK Endorsement Board. The Group
transitioned to UK-adopted International Accounting Standards (for
its consolidated Financial Statements) on 1 January 2021. This
change constitutes a change in accounting framework; however, there
is no impact on recognition, measurement or disclosure in the
period reported as a result of this change.
The Group has applied new accounting standards, amendments and
interpretations for the first time, but their adoption 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:
-- COVID-19-Related Rent Concessions - amendments to IFRS 16;
-- Interest Rate Benchmark Reform - Phase 2 - amendments to IFRS
9, IAS 39, IFRS 7, IFRS 4 and IFRS 16;
-- Annual Improvements to IFRS Standards 2018-2020; and
-- Deferred Tax related to Assets and Liabilities arising from a
Single Transaction - amendments to IAS 12
A number of new and amended accounting standards and
interpretations have been published that are not mandatory for the
Group's financial year ended 31 December 2021, 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.
1.2 Annual report and accounts
The financial information set out within this announcement does
not constitute the Company's statutory accounts for the years ended
31 December 2021 or 2020, but is derived from those accounts. A
copy of the statutory accounts for 2020 has been delivered to the
Registrar of Companies and those for 2021 will be delivered
following the Company's annual general meeting. The auditor has
reported on the 2021 accounts; their audit report was unqualified,
and did not draw any attention to any material uncertainty or other
areas by way of emphasis of matter.
Whilst the financial information included in this announcement
has been computed in accordance with IFRS, this announcement does
not itself contain sufficient information to comply with IFRS.
1.3 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, committed and sanctioned capital expenditure,
and the remaining Convertible Bond principal amount due in July
2022. In addition, sensitivity and reverse stress test analyses
have been considered. Further details on the going concern
assessment undertaken are outlined in the Chief Financial Officer's
Review.
1.4 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:
-- a significant increase in revenue versus the previous year
due to a strong recovery in crude oil prices, with the average
realised sales price increasing from $35.2/bbl to $67.3/bbl (note
2.1);
-- the incurrence of $15.9 million of legal and professional
costs (for advisers engaged by the Group, bondholders and
shareholders) related to the proposed financial restructuring of
the Group, originally announced in April 2021, but ultimately not
sanctioned by the Court in June 2021;
-- a reduction in lease liabilities, right-of-use assets and a
non-cash lease remeasurement gain arising from the decision made in
June 2021 not to extend the bareboat charter of the Aoka Mizu FPSO
beyond June 2022 (notes 2.3 and 5.2);
-- the placing of an additional GBP11.2 million of cash into
restricted funds following a formal request by OPRED to increase
the amount of decommissioning security for the Lancaster field
(note 4.1);
-- a significant reduction in Convertible Bond debt and gain on
repurchase of Convertible Bonds recognised in the Income Statement
following the repurchase of $151.5 million of bonds for cash
consideration of $130.3 million (note 5.1); and
-- the recognition of an impairment charge of $54.3 million in
respect of the Lincoln asset following the decision by the Group
and its joint operation partner to relinquish the P1368(S) licence
(note 2.3.1).
Amounts relating to the proposed financial restructuring
incurred in the prior year have been reclassified from operating
activities to financing activities within the Cash Flow Statement
and note 4.1 in order to align with the current year
classification.
For further discussion about the Group's performance and
financial position, see the Chief Executive Officer's Review and
Chief Financial Officer's Review.
Section 2: Oil and gas operations
2.1 Revenue
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
2021 2020
$'000 $'000
Oil sales 240,540 180,083
Revenue from contracts with customers 240,540 180,083
-------------------------------------- ---------- ----------
Cargoes sold 7 12
Sales volumes (thousand bbl) 3,576 5,112
Average sales price realised ($/bbl) $67.3/bbl $35.2/bbl
-------------------------------------- ---------- ----------
2.2 Cost of sales and inventory
Cost of sales
Year ended Year ended
31 Dec 31 Dec
2021 2020
Note $'000 $'000
Operating costs 65,688 65,107
Depreciation of oil and gas assets - owned 2.3 94,200 84,756
Depreciation of oil and gas assets - leased 2.3 3,405 11,828
Movement in crude oil inventory (10,622) 1,733
Variable lease payments 5.2 20,454 16,392
-------------------------------------------- ---- ---------- ----------
173,125 179,816
-------------------------------------------- ---- ---------- ----------
Inventory
31 Dec 2021 31 Dec 2020
$'000 $'000
Crude oil 13,313 2,691
Fuel and chemicals 2,124 1,336
Spares and supplies 12,051 7,258
-------------------- ----------- -----------
27,488 11,285
-------------------- ----------- -----------
The amount of crude oil inventory recognised as an expense in
the year was $140.6 million (2020: $155.2 million).
2.3 Oil and gas assets
Leased Owned Total
Note $'000 $'000 $'000
Cost
At 1 January 2020 101,347 757,424 858,771
Additions - 23,652 23,652
Changes to decommissioning estimates 2.5 474 3,482 3,956
At 31 December 2020 101,821 784,558 886,379
Additions - 4,572 4,572
Remeasurement of lease liability 5.2 (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
------------------------------------- ---- -------- --------- ---------
Depreciation and impairment
At 1 January 2020 (8,210) (54,406) (62,616)
Depreciation charge for the
year (11,828) (84,756) (96,584)
Provision for impairment (60,166) (458,986) (519,152)
------------------------------------- ---- -------- --------- ---------
At 31 December 2020 (80,204) (598,148) (678,352)
Depreciation charge for the
year (3,405) (94,200) (97,605)
Changes to decommissioning estimates
expensed (1,961) - (1,961)
------------------------------------- ---- -------- --------- ---------
At 31 December 2021 (85,570) (692,348) (777,918)
------------------------------------- ---- -------- --------- ---------
Carrying amount at 31 December
2020 21,617 186,410 208,027
------------------------------------- ---- -------- --------- ---------
Carrying amount at 31 December
2021 - 98,296 98,296
------------------------------------- ---- -------- --------- ---------
Oil and gas assets held under leases comprise solely the Aoka
Mizu FPSO bareboat charter, which commenced in May 2019. During the
year, this lease term was reassessed, resulting in a decrease in
the leased asset value to nil (see note 5.2). Subsequent to the
balance sheet date, the Group agreed an extension to the charter
(see note 7.2).
The total amount of depreciation charged to oil and gas assets
and other fixed assets was $98.1 million (2020: $97.1 million).
2.3.1 Impairment of oil and gas assets
The triggers for the impairment test were the non-sanction of
the proposed financial restructuring in June 2021, and the decision
not to extend the lease of the Aoka Mizu FPSO beyond June 2022. 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 2022 ERCE CPR; and
-- Dated Brent oil price assumptions (in real terms) of $76/bbl
average for 2022, $70/bbl in 2023 and $67/bbl in 2024 (being
forecasts of future oil prices extant as at 31 December 2021, as
required by IAS 36);
-- operating cost assumptions based on latest budgets, contracts
and information from key suppliers;
-- an extension to the Aoka Mizu FPSO charter allowing
production to continue until June 2024 (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 9.0%.
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; although this was subject to the key
judgement that it would be possible to agree an alternative
extension to the bareboat charter beyond June 2022 until such time
as, based on management's forecast of production rates, operating
costs and oil prices, production became uneconomic.
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 20.2
Forecast production rates:
5% decrease -
10% decrease 5.8
Cessation of production and FPSO charter
end date
October 2022 14.1
December 2022 3.6
December 2023 -
------------------------------------------ ------------------
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.
The triggers for the prior period impairment charges were the
downward revision of estimated recoverable reserves as a result of
the Technical Review and updated CPR, the decline in oil prices
across the first half of 2020 and the market capitalisation of the
Group falling below its net assets. The charge was allocated
pro-rata to owned and leased assets based on their respective
carrying values pre-impairment.
2.4 Intangible exploration and evaluation assets
Year ended Year ended
31 Dec 2021 31 Dec 2020
Note $'000 $'000
At 1 January 55,390 75,874
Additions 5,235 25,623
Provision for impairment and exploration
expenditure written off 2.4.1 (54,280) (47,476)
Changes to decommissioning estimates 2.5 (2,515) 1,369
----------------------------------------- ----- ----------- -----------
At 31 December 3,830 55,390
----------------------------------------- ----- ----------- -----------
Intangible exploration and evaluation assets represent the
Group's share of the cost of licence interests and exploration and
evaluation expenditure within its licensed acreage in the West of
Shetland area, which comprise Lincoln (on licence P1368(S)),
Warwick (licence P2294) and Halifax (licence P2308).
Additions during the period primarily comprised licence fees,
geological and other subsurface studies undertaken, long-lead items
ordered in previous years for potential future development activity
and capitalised timewriting costs.
2.4.1 Impairment and write-off of intangible exploration and evaluation assets
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 $54.3 million has been recognised
against the full carrying amount of exploration and evaluation
expenditure attributable to the Lincoln asset on licence P1368(S).
The Group and its joint operation partner, Spirit Energy, had a
regulatory obligation to commence drilling a well on the P1368(S)
licence (the 'obligation well') by 30 June 2022. During the year,
the joint operation partners engaged with the Regulator on the
technical re-evaluation and interpretation of the licence potential
and requested a regulatory amendment of the obligation well to a
later commencement date. The Regulator indicated, as part of its
considerations, that it was not content to support a deferral of
the obligation well unless the joint operation partners satisfy the
Regulator that they will be able to fund the obligation well in a
timely manner. In December 2021, given the respective partners
financial circumstances and related challenges of securing
additional funding for the Lincoln obligation well, the joint
operation partners e lected to continue plans to suspend further
funding towards well planning and drilling of the Lincoln
obligation well in 2022. In April 2022, the joint operation
partners agreed to voluntarily surrender the P1368(S) licence (see
note 7.3).
In 2020, following the finalisation of the 2021 CPR, provision
for impairment of $35.4 million was recognised against the full
carrying amount of exploration and evaluation expenditure
attributable to the Halifax licence, as the 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. $12.1 million of
exploration and evaluation expenditure was also written off,
comprising the Group's share of standby costs for the Paul B Loyd
Jr rig, which was on hire but not used for any drilling campaigns
during 2020.
2.5 Decommissioning provisions
Year ended Year ended
31 Dec 2021 31 Dec 2020
Note $'000 $'000
At 1 January 61,141 55,673
Net new provisions and changes in
estimates (1,921) 7,459
Utilised in year (9,894) (2,108)
Unwinding of discount 3.2 20 117
----------------------------------- ---- ----------- -----------
At 31 December 49,346 61,141
----------------------------------- ---- ----------- -----------
Of which:
Current - 15,466
Non-current 49,346 45,675
----------------------------------- ---- ----------- -----------
49,346 61,141
---------------------------------- ---- ----------- -----------
Restricted funds held in respect
of decommissioning:
Restricted cash 4.1 - 2,244
Liquid investments 4.1 37,783 22,811
----------------------------------- ---- ----------- -----------
37,783 25,055
---------------------------------- ---- ----------- -----------
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 June 2024; being the estimated point at
which the EPS becomes uneconomic absent any incremental
development. Estimated costs are discounted at a rate of 0.67%.
Changes in estimates in the period have arisen from change in
the assumed discount rate, changes in foreign exchange rates,
increases to the assumed inflation rate and refined estimates to
the expected costs and timing of decommissioning the EPS and FPSO;
and actualisation of provisions for the Lincoln and Lancaster 4Z
wells.
Of the total net new provisions and changes in estimates, $2.5
million was recorded as non-cash reductions to intangible
exploration and evaluation assets, $1.5 million as non-cash
additions to oil and gas assets, $2.5 million credited to
receivables due from the Group's joint operation partner and $1.6
million charged directly to the Income Statement (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
plugging and abandonment of the Lincoln-14 well, and the Lancaster
4Z wells.
Section 3 Income Statement
3.1 Earnings per share
Year ended Year ended
31 Dec 2021 31 Dec 2020
$'000 $'000
Profit/(loss) attributable to holders of Ordinary
Shares in the Company used in calculating
basic earnings per share (being profit/(loss)
after tax) 18,236 (625,325)
Add back impact of:
Convertible Bond - interest expense - -
Convertible Bond - fair value gain - -
--------------------------------------------------- ------------- -------------
Profit/(loss) attributable to holders of Ordinary
Shares in the Company used in calculating
diluted earnings per share 18,236 (625,325)
--------------------------------------------------- ------------- -------------
Number Number
--------------------------------------------------- ------------- -------------
Weighted average number of Ordinary Shares
used in calculating basic earnings per share 1,989,927,148 1,989,607,524
Potential dilutive effect of:
Convertible Bond - -
--------------------------------------------------- ------------- -------------
Weighted average number of Ordinary Shares
and potential Ordinary Shares used in calculating
diluted earnings per share 1,989,927,148 1,989,607,524
--------------------------------------------------- ------------- -------------
Cents Cents
--------------------------------------------------- ------------- -------------
Basic earnings per share 0.92 (31.43)
Diluted earnings per share 0.92 (31.43)
--------------------------------------------------- ------------- -------------
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 in 2021.
The impact of the VCP and PSP awards was antidilutive in 2021
because market-based conditions for both schemes was not met at any
point throughout the year.
The effect of the conversion feature included within the
Convertible Bond, the VCP and PSP share awards and other share
options outstanding in 2020 were antidilutive as the Group incurred
a loss.
3.2 Finance income and costs
Year ended Year ended
31 Dec 2021 31 Dec 2020
$'000 $'000
Interest income on cash, cash equivalents
and liquid investments 27 1,227
Net foreign exchange gains - 1,469
Finance income 27 2,696
------------------------------------------- ----------- -----------
Convertible Bond interest expense (note
5.1) (24,810) (26,680)
Interest on lease liabilities (note
5.2) (4,412) (7,702)
Fair value losses on oil price derivatives - (3,420)
Other interest expense and bank charges (217) (241)
Net foreign exchange losses (1,197) -
Unwinding of discount on decommissioning
provisions (note 2.5 ) (20) (117)
------------------------------------------- ----------- -----------
Finance costs (30,656) (38,160)
------------------------------------------- ----------- -----------
Net finance costs (30,629) (35,464)
------------------------------------------- ----------- -----------
3.3 General and administrative expenditure
Year ended Year ended
31 Dec 2021 31 Dec 2020
$'000 $'000
Wages and salaries 9,939 10,001
Social security costs 1,226 937
Defined contribution pension costs 689 720
---------------------------------------------- ----------- -----------
Staff costs 11,854 11,658
Non-staff costs 22,958 7,409
Gross general and administrative expenditure
before recharges 34,812 19,067
Capitalised into oil and gas assets (3,025) (3,499)
Capitalised into intangible exploration and
evaluation assets (3,456) (7,121)
Included within cost of sales (4,752) (5,591)
---------------------------------------------- ----------- -----------
Net general and administrative expenditure
before non-cash items 23,579 2,856
Non-cash general and administrative costs:
Net share-based payment charge 1,956 821
Depreciation of other fixed assets and other
right-of-use assets 495 552
Impairment of other right of use assets 719 -
---------------------------------------------- ----------- -----------
General and administrative expenditure 26,749 4,229
---------------------------------------------- ----------- -----------
Number Number
Average number of employees 55 62
Section 4 Cash
4.1 Cash and cash equivalents and liquid investments
31 Dec 2021 31 Dec 2020
------------------------------------ ------------------------------------
Restricted Unrestricted Total Restricted Unrestricted Total
$'000 $'000 $'000 $'000 $'000 $'000
---------------------------- ----------- ------------- -------- ----------- ------------- --------
Current cash and cash
equivalents 7,934 68,858 76,792 28,792 114,911 143,703
Non-current cash and - - -
equivalents - - -
---------------------------- ----------- ------------- -------- ----------- ------------- --------
Cash and cash equivalents
(per Cash Flow Statement) 7,934 68,858 76,792 28,792 114,911 143,703
Liquid investments 37,783 - 37,783 22,811 - 22,811
---------------------------- ----------- ------------- -------- ----------- ------------- --------
Total cash and cash
equivalents and liquid
investments 45,717 68,858 114,575 51,603 114,911 166,514
---------------------------- ----------- ------------- -------- ----------- ------------- --------
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:
Restated
-------------------------------------- -------------------------------------
Year ended 31 Dec Year ended 31 Dec
2021 2020
-------------------------------------- -------------------------------------
Restricted Unrestricted Total Restricted Unrestricted Total
$'000 $'000 $'000 $'000 $'000 $'000
--------------------------- ----------- ------------- ---------- ----------- ------------- ---------
At 1 January 51,603 114,911 166,514 14,843 156,591 171,434
Operating cash flows - 147,970 147,970 -- 81,770 81,770
Change in Lancaster EPS
decommissioning security
arrangements 15,530 (15,530) - 22,811 (22,811) -
Capital expenditure and
other investing cash
flows - (15,095) (15,095) - (60,793) (60,793)
Financing cash flows - (183,562) (183,562) - (28,368) (28,368)
Movement in FPSO early
termination reserve (18,670) 18,670 - 14,807 (14,807) -
Net release of other
restricted funds (2,244) 2,244 - (892) 892 -
Foreign exchange rate
changes (502) (750) (1,252) 34 2,437 2,471
--------------------------- ----------- ------------- ---------- ----------- ------------- ---------
At 31 December 45,717 68,858 114,575 51,603 114,911 166,514
--------------------------- ----------- ------------- ---------- ----------- ------------- ---------
The presentation of certain comparative lines has been restated
- see note 1.4.
Included within restricted cash and cash equivalents is $7.9
million (2020: $26.5 million) set aside in relation to the Aoka
Mizu FPSO bareboat charter. Under the terms of the contract, the
Group is required to ring-fence amounts to ensure it could meet its
liability to pay an early termination fee to the lessor if the
contract was terminated by the Group earlier than the expiry of an
option period. Under the current lease, this amount will be
released into unrestricted cash on a straight-line basis and be
fully released at the expiry of the current lease term. Following
the agreement in March 2022 to extend the lease (see note 7.2), a
secured deposit account of up to $18.7 million will be established
and classified as restricted cash.
The $37.8 million restricted liquid investment balance comprises
decommissioning security in place for the Lancaster EPS. As part of
the original Lancaster Field Development Plan approval, the Group
was required to provide security of GBP16.8 million for its
decommissioning liability on the Lancaster field, being the
estimated post-tax amount to meet future decommissioning
obligations. This security was placed in a decommissioning bond and
subsequently released to unrestricted cash during 2019 as the bond
conditions were satisfied. Following the downwards revision of
Reserves and Contingent Resources in September 2020 and the ongoing
uncertainty with regard to oil prices, the bond provider requested
that the Company provide cash collateral for 100% of the bond's
value. As the Group would derive no benefit from the bond while
still paying fees to the bond provider, the decommissioning bond
was terminated by mutual agreement and the required security amount
was placed back into trust (classified within restricted liquid
investments). In June 2021, the Group agreed with the Regulator to
place an additional GBP11.2 million ($15.5 million) into trust, in
order to provide security for its decommissioning liability on the
Lancaster field on a pre-tax basis.
During 2021, $2.2 million of restricted cash relating to
decommissioning security for the suspended Lancaster 205/21a-4z
well was released back to the Group following completion of its
plug and abandonment.
Section 5 Capital and debt
5.1 Convertible Bond
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 carries a coupon of 7.5% payable quarterly in
arrears. The Convertible Bond is 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 is 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. Unless
previously converted, redeemed or purchased and cancelled, the
Convertible Bond will be redeemed at par on 24 July 2022. The
Convertible Bond is subject to a covenant which imposes a
restriction on the incurrence of certain indebtedness. This
restriction shall not apply in respect of:
-- any indebtedness in respect of the Convertible Bond (Bond Debt);
-- any other indebtedness where the aggregate principal amount
of such other indebtedness, when combined with the aggregate
principal amount of all other indebtedness of the Group from time
to time (excluding the Bond Debt), would not cause the total
indebtedness of the Group on a consolidated basis to exceed $45
million (or the equivalent thereof in other currencies at then
current rates of exchange); and
-- any permitted indebtedness, being:
o any liability in respect of any lease or hire purchase
contract which would, in accordance with IFRS, be treated as a
finance or capital lease, with respect to the bareboat charter of
the Aoka Mizu FPSO;
o amounts borrowed, or any guarantee or indemnity given with
respect to any security, where required by the Oil and Gas
Authority or any other applicable regulator, in relation to
suspended wells, decommissioning or other related regulatory
obligations of the Group; and
o any amount raised under any transaction, having the commercial
effect of borrowing, in respect of the deferral of payment of
invoices due to Technip UK Limited (or any of its affiliated
companies) in connection with the agreement for the provision of
subsea umbilical risers and flowlines and subsea production systems
for the Company's operations in the Lancaster field.
The conversion feature of the Convertible Bonds is classified as
an embedded derivative as the Convertible Bonds can be settled by
the Group in cash and hence does not meet the 'fixed for fixed'
criteria outlined in IAS 32 for recognition as an equity
instrument. It has therefore been measured at fair value through
profit and loss. The amount recognised at inception in respect of
the host debt contract was determined by deducting the fair value
of the conversion option at inception (the embedded derivative)
from the fair value of the consideration received for the
Convertible Bond. The debt component is then recognised at
amortised cost, using the effective interest method, until
extinguished upon conversion or at maturity. The effective interest
rate applicable to the debt component is 13.5%.
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
2020 206,604 36,316 242,920
Cash interest paid (17,250) - (17,250)
Fair value gain - (35,431) (35,431)
Interest charged 26,680 - 26,680
------------------------------- -------------- -------------------- ---------
Carrying value at 31 December
2020 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
------------------------------- -------------- -------------------- ---------
Fair value at 31 December
2020 102,615 885 103,500
------------------------------- -------------- -------------------- ---------
Fair value at 31 December
2021 75,449 27 75,476
------------------------------- -------------- -------------------- ---------
5.1.1 Repurchase of Convertible Bonds
During the year, the Group repurchased $151.5 million of nominal
Convertible Bond debt for cash consideration of $131.9 million,
including accrued interest of $1.6 million. An initial tender offer
in September resulted in $78.0 million of Convertible Bonds being
repurchased at a cost of $61.7 million including accrued interest
of $0.8 million. The average price achieved in this tender was 78%.
During December 2021, the Company undertook further buybacks, in
various tranches. These transactions resulted in $73.5 million of
nominal bonds repurchased at a cost of $70.3 million, including
$0.8 million accrued interest. The average price achieved of these
tranches was 95%. As at 31 December 2021, the nominal value of
Convertible Bonds remaining in issue was $78.5 million.
The net gain on the repurchase of the Convertible Bonds is
reconciled as follows:
$'000
-------------------------------------------------------------------- ----------
Carrying value of Convertible Bond debt portion derecognised 146,099
Carrying value of Convertible Bond derivative portion derecognised 2,759
Cash consideration paid (130,346)
-------------------------------------------------------------------- ----------
Gross gain on repurchase 18,512
Transaction costs (1,311)
-------------------------------------------------------------------- ----------
Net gain on repurchase of Convertible Bonds 17,201
-------------------------------------------------------------------- ----------
5.1.2 Embedded derivative valuation
The embedded derivative component of the Convertible Bond is
categorised within Level 3 of the fair value hierarchy, as the
derivatives themselves are not traded on an active market and their
fair values are determined using a valuation technique that uses
one key input that is not based on observable market data, being
share price volatility.
The key inputs used are share price volatility (calculated as
the volatility of one Hurricane Ordinary Share over a period
equivalent to the remaining expected term to redemption) and the
price of one Ordinary Share at 31 December 2021. In determining the
fair value of the embedded derivative, the likelihood of the early
redemption option being exercised and the likelihood of a change of
control of the Group within the life of the Convertible Bond were
considered. The likelihood of each was considered to be nil for the
purposes of the valuation.
The fair value calculation at 31 December 2021 used a share
price volatility assumption of 117.6% (2020: 118.2%) and the price
of one Hurricane Energy plc Ordinary Share as at the balance sheet
date of GBP0.038 (2020: GBP0.025). Given the remaining time to
maturity, it is not considered that there is a significant risk of
changes to these assumptions resulting in a material adjustment to
the carrying amounts of the embedded derivative within the next
financial year.
5.2 Leases
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 2021 31 Dec 2020
$'000 $'000
At 1 January 97,321 99,186
Remeasurement of lease liability (67,337) -
Cash payments of principal and interest (18,596) (9,658)
Interest charged 4,412 7,702
Foreign exchange movements (10) 91
---------------------------------------- ----------- -----------
At 31 December 15,790 97,321
---------------------------------------- ----------- -----------
Of which:
Current 13,880 18,479
Non-current 1,910 78,842
---------------------------------------- ----------- -----------
15,790 97,321
---------------------------------------- ----------- -----------
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). Should the Group give
notice to terminate the lease (other than by not exercising
extension option periods), significant early termination penalties
would apply. The Group is required to set aside amounts to cover a
portion of these early termination penalties, the balance of which
changes over time in line with the contract, and such balances are
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 profit and
loss.
The assumption that the bareboat charter can be extended beyond
June 2022 is a critical judgement within the assessment of
impairment of oil and gas assets (note 2.3.1). Subsequent to the
balance sheet date, an extension to the bareboat charter was agreed
(see note 7.2) to cover an indefinite period with both lessor and
lessee having the ability to terminate the lease with six months'
notice, with the current fixed and variable lease payment structure
remaining in place.
Other charges to the Income Statement in respect of leases
during the year included the following:
Year ended Year ended
31 Dec 2021 31 Dec 2020
$'000 $'000
Depreciation charge of right-of-use assets:
Oil and gas assets (included within cost of sales) 3,404 11,828
Other fixed assets (included within general and
administrative expenses) 364 340
---------------------------------------------------- ----------- -----------
3,768 12,168
---------------------------------------------------- ----------- -----------
Provision for impairment of right-of-use assets:
Oil and gas assets (included within cost of sales) - 60,166
Other fixed assets (included within general and
administrative expenses) 719 -
---------------------------------------------------- ----------- -----------
719 60,166
---------------------------------------------------- ----------- -----------
Lease interest (included within finance costs) 4,412 7,702
Variable lease payments (included within cost of
sales) 20,454 16,392
Following a reduction to staff numbers during the year and a
move towards hybrid working arrangements, the Group recognised
provision for impairment of $0.7 million in respect of one of its
office leases.
The total gross cash outflow for leases for the year was $39.1
million.
In 2020, the Group's share of the expense relating to the
short-term lease of the Paul B Loyd Jr rig was recognised within
write-off of exploration and evaluation expenditure (see note
2.4.1). The expense relating to low-value leases and other
short-term leases recognised in the Income Statement was not
material.
Section 6 Taxation
6.1 Tax charge for year
Year ended Year ended
31 Dec 2021 31 Dec 2020
$'000 $'000
UK corporation tax
Current tax - current and prior years - -
------------------------------------------------- ----------- -----------
Total current tax - -
------------------------------------------------- ----------- -----------
Deferred tax - current year 21 (44,501)
Deferred tax - prior year 5 (9,732)
Total deferred tax 26 (54,233)
------------------------------------------------- ----------- -----------
Tax credit/(charge) per Income Statement 26 (54,233)
------------------------------------------------- ----------- -----------
Profit/(loss) on ordinary activities before
tax 18,210 (571,092)
------------------------------------------------- ----------- -----------
Profit/(loss) on ordinary activities multiplied
by standard combined rate of corporation tax
in the UK applicable to oil and gas companies
of 40% (2020: 40%) (7,284) 228,437
Effects of:
Expenses not deductible for tax purposes (1,934) (4,656)
Income not chargeable for tax purposes 7,692 15,138
Items taxed at rates other than the standard
rate of 40% (2,064) (24)
Ring-fence expenditure supplement 20,560 22,769
Prior period deferred tax 5 (9,732)
Losses not recognised (6,687) (306,165)
Impact of tax rate change 25 -
Chargeable gain (10,287) -
Total tax credit/(charge) for the year 26 (54,233)
------------------------------------------------- ----------- -----------
The chargeable gain in the period arose as a consequence of the
repurchase and cancellation of some of the Group's Convertible
Bonds (note 5.1.1) due to crystallisation of the underlying
embedded derivative. No cash tax has arisen as a consequence of
this chargeable gain.
6.2 Factors which may affect future tax charges
The Group has ring-fenced trading losses of $381.9 million at 31
December 2021 (31 December 2020: $468.7 million) and supplementary
charge losses and investment allowances of $693.0 million at 31
December 2021 (31 December 2020: $707.8 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 $328.4 million available to be used against future
taxable profits at 31 December 2021 ($383.5 million). In addition,
the Group has pre-trading expenditure of $124.9 million which is
carried forward at 31 December 2021 and tax relief may be available
were trading activities to commence in the pre-trading entities.
This pre-trading expenditure could also be uplifted by RFES to
$183.5 million.
The value of tax attributes as at 31 December 2021 at the
currently prevailing tax rates can be summarised as follows:
Tax attributes Tax rate Tax value
$'000 % $'000
Ring-fence losses 381,866 30% 114,560
Supplementary charge losses 261,900 10% 26,190
Investment allowance 431,145 10% 43,114
Unclaimed capital allowances 328,435 40% 131,374
Pre-trading expenditure (including RFES) 183,541 40% 73,416
Future decommissioning costs 49,346 40% 19,738
Non-ring-fence losses 5,128 25% 1,282
----------------------------------------- ---------
Value of tax attributes at prevailing
tax rates 409,674
----------------------------------------- ---------
Access to these losses and allowances may be severely restricted
at the point at which trading activities end (which would include a
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 Group or entity's trading
activities
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 charge tax is generally lower than
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 36.9%.
Investment allowance is only allowable against supplementary charge
tax and attracts relief at 10%, and is available after tax losses
have been taken into account.
During the year, the Group made claims for Small and Medium
sized Enterprises (SME) R&D Relief ('SME R&D') (in respect
of 2019) and Research and Development Expenditure Credit ('RDEC')
(in respect of 2020). Subsequent to the balance sheet date, the
Group received a cash repayment of $3.2 million in respect of the
SME R&D claim and $1.4 million in respect of the RDEC. The
impact of these claims on the 2022 tax position will be a tax
credit of $4.6 million in exchange for a surrender of $21.0 million
of ring-fence trading losses.
Section 7 Subsequent events
7.1 Decommissioning security
In February 2022, following a request from the Regulator, the
Group placed an additional GBP5.7 million ($7.7 million) into Trust
as additional decommissioning security in respect of the Lancaster
EPS. These funds will be classified as restricted liquid
investments.
7.2 Aoka Mizu charter extension
On 25 March 2022, the Group signed a contract with Bluewater
(Aoka Mizu) B.V. ('Bluewater'), the owner of the Aoka Mizu FPSO,
for an extension to the Bareboat Charter. Under the terms of the
extension, the existing fixed and variable lease payments remain at
their current rate and either party can give six months' notice of
termination. The Group will also place up to $18.7 million into a
secured deposit account (classified as restricted cash) 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 impact of these changes will be reflected in the
Group's 2022 Financial Statements.
7.3 P1368(S) licence relinquishment
On 27 April 2022, the Group and its joint operation partner
agreed to voluntarily surrender licence P1368(S), comprising the
Lincoln asset. An impairment charge of $54.3 million has been
recognised against the full carrying amount of exploration and
evaluation expenditure attributable to the licence (see note
2.4.1).
Appendix A Glossary
1C Denotes low estimate of Contingent Resources
--------------------- ----------------------------------------------------------------
1P Denotes low estimate of Reserves (i.e., Proved Reserves).
Equal to P1.
--------------------- ----------------------------------------------------------------
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
--------------------- ----------------------------------------------------------------
Ad Hoc Committee A group comprising certain of Hurricane's Bondholders,
with whom Hurricane announced, on 30 April 2021, it
had entered into a lock-up agreement pursuant to the
proposed financial restructuring
--------------------- ----------------------------------------------------------------
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
--------------------- ----------------------------------------------------------------
CO(2) e Carbon dioxide equivalent
--------------------- ----------------------------------------------------------------
Company Hurricane Energy plc and/or its subsidiaries
--------------------- ----------------------------------------------------------------
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.
--------------------- ----------------------------------------------------------------
Contingent Resources, A discovered accumulation where project activities are
Development under evaluation and where justification as a commercial
Unclarified development is unknown based on available information.
--------------------- ----------------------------------------------------------------
Convertible $230 million 7.5% convertible bonds issued by the Company
Bond(s) in July 2017, of which $78.5 million remain outstanding
as at 31 December 2021
--------------------- ----------------------------------------------------------------
Court High Court of Justice of England and Wales
--------------------- ----------------------------------------------------------------
COVID-19 Coronavirus
--------------------- ----------------------------------------------------------------
CPR Competent Persons Report
--------------------- ----------------------------------------------------------------
Crystal Amber Crystal Amber Fund Limited
--------------------- ----------------------------------------------------------------
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.
--------------------- ----------------------------------------------------------------
E&E Exploration and Evaluation
--------------------- ----------------------------------------------------------------
E&P Exploration and Production/Exploration and Production
company
--------------------- ----------------------------------------------------------------
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
--------------------- ----------------------------------------------------------------
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
--------------------- ----------------------------------------------------------------
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 Environmental
--------------------- ----------------------------------------------------------------
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
--------------------- ----------------------------------------------------------------
JV Joint venture
--------------------- ----------------------------------------------------------------
KPI Key Performance Indicator
--------------------- ----------------------------------------------------------------
Mbbl Thousand barrels of oil
--------------------- ----------------------------------------------------------------
MMbbl Million barrels of oil
--------------------- ----------------------------------------------------------------
NSTA North Sea Transition Authority (formerly Oil and Gas
Authority (OGA))
--------------------- ----------------------------------------------------------------
Obligation well The licence requirement to commence drilling a well
on the Lincoln subarea of licence P1368 by no later
than 31 December 2020 (subsequently deferred to be no
later than 30 June 2022)
--------------------- ----------------------------------------------------------------
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
--------------------- ----------------------------------------------------------------
P&A Plug and abandon
--------------------- ----------------------------------------------------------------
P6 The 205/21a-6 producer well on the Lancaster field
--------------------- ----------------------------------------------------------------
P7z The 205/21a-7z well on the Lancaster field, currently
shut-in
--------------------- ----------------------------------------------------------------
PP&E Property, Plant and Equipment
--------------------- ----------------------------------------------------------------
Prospective Best case prospective resources under the Society of
resources Petroleum Engineers' Petroleum Resources Management
System
--------------------- ----------------------------------------------------------------
PRMS Petroleum Resources Management System
--------------------- ----------------------------------------------------------------
PSP Performance Share Plan
--------------------- ----------------------------------------------------------------
psia Pounds per square inch (absolute) unit of pressure
--------------------- ----------------------------------------------------------------
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.
--------------------- ----------------------------------------------------------------
Restructuring Implementation of the proposed financial restructuring
Plan announced by Hurricane on 30 April 2021 with holders
of its Convertible Bonds under Part 26A of the Companies
Act 2006; but subsequently not sanctioned by the Court
--------------------- ----------------------------------------------------------------
RDEC Research and Development Expenditure Credit
--------------------- ----------------------------------------------------------------
RFES Ring fence expenditure supplement
--------------------- ----------------------------------------------------------------
SIP Share Incentive Plan
--------------------- ----------------------------------------------------------------
SME R&D Small and Medium sized Enterprises R&D Relief
--------------------- ----------------------------------------------------------------
SONIA Sterling Overnight Index Average
--------------------- ----------------------------------------------------------------
Spirit Energy Spirit Energy Limited and affiliates
--------------------- ----------------------------------------------------------------
Tier 1 contractors Hurricane's major direct contractors
--------------------- ----------------------------------------------------------------
TVDSS True Vertical Depth Sub Sea
--------------------- ----------------------------------------------------------------
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
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 Income
Statement. 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 2021 31 Dec 2020
$'000 $'000
Profit/(loss) before tax (IFRS measure) 18,210 (571,092)
Add back:
Fair value loss/(gain) on Convertible
Bond embedded derivative 5.1 1,901 (35,431)
Fair value loss on unhedged derivative
financial instruments 3.2 - 3,420
Impairment and write-off of intangible
exploration and evaluation assets 2.4 54,280 47,945
Change in decommissioning estimates on
fully impaired assets 2.5 1,973 -
Impairment of oil and gas assets 2.3 - 519,152
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/(loss) before tax 10,757 (36,006)
-------------------------------------------- ---- ----------- -----------
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 Income Statement 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 2021 31 Dec 2020
$'000 $'000
Cost of sales (IFRS measure) 2.2 173,125 179,816
Less:
Depreciation of oil and gas assets - owned 2.2 (94,200) (84,756)
Depreciation of oil and gas assets - leased 2.3 (3,405) (11,828)
Movements in crude oil inventory 2.2 10,622 (1,733)
Add:
Fixed lease payments payable on oil and
gas assets 19,638 9,150
--------------------------------------------- ---- ----------- -----------
Cash production costs 105,780 90,649
Variable lease payments (incentive tariff) 2.2 (20,454) (16,392)
--------------------------------------------- ---- ----------- -----------
Cash production costs (excluding incentive
tariff) 85,326 74,257
--------------------------------------------- ---- ----------- -----------
Production volumes 3,748 Mbbl 5,078 Mbbl
Cash production costs per barrel $28.2/bbl $17.9/bbl
Cash production costs per barrel (excluding $22.8/bbl $14.6/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.
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 2021 31 Dec 2020
$'000 $'000
Cash and cash equivalents (IFRS measure) 4.1 76,792 143,703
Add:
Trade and other receivables 2,591 14,524
Less:
Restricted cash and cash equivalents 4.1 (7,934) (28,792)
Prepayments (1,058) (1,644)
Trade and other payables (18,843) (16,356)
----------------------------------------- ---- ----------- -----------
Net free cash 51,548 111,435
5.1
Nominal value of Convertible Bond .1 (78,515) (230,000)
----------------------------------------- ---- ----------- -----------
Net debt (26,967) (118,565)
----------------------------------------- ---- ----------- -----------
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 2021 31 Dec 2020
$'000 $'000
Net cash inflow from operating activities
(IFRS measure) 147,044 81,770
Adjustments:
Decommissioning spend 4,824 2,108
Reallocation of items to cash capex 2,405 -
Lease repayments 5.2 (18,596) (9,658)
------------------------------------------ ---- ----------- -----------
Free cash flow 135,677 74,220
------------------------------------------ ---- ----------- -----------
Free cash flow per barrel $36.2/bbl $14.6/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 2021 31 Dec 2020
$'000 $'000
Net cash used in investing activities
(IFRS measure) 29,698 83,604
Adjustments:
Interest received 27 1,227
Increase in liquid investments (15,530) (22,811)
Decommissioning spend 4,824 2,108
Reallocation of items from free cash
flow 2,405 -
--------------------------------------------- ---- ----------- -----------
Cash capex 21,424 64,128
Less: capitalised general and administrative
expenditure
Capitalised into oil and gas assets 3.3 (3,025) (3,499)
Capitalised into intangible exploration
and evaluation assets 3.3 (3,456) (7,121)
--------------------------------------------- ---- ----------- -----------
Third-party cash capex 14,943 53,508
--------------------------------------------- ---- ----------- -----------
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