TIDMHUR
RNS Number : 6663Z
Hurricane Energy PLC
25 May 2021
25 May 2021
Hurricane Energy plc
("Hurricane", the "Company", or the "Group")
Full-year Results 2020
Hurricane Energy plc, the UK based oil and gas company focused
on hydrocarbons in naturally fractured basement reservoirs,
announces its full-year results for the period ended 31 December
2020.
Key points
-- Lancaster produced an average of 13,900 bopd in 2020,
supported by 98% production uptime from the Aoka Mizu FPSO.
However, production was significantly less than expected due to the
field materially underperforming relative to pre-production
expectations
-- The Company recorded a loss for the year of $625.3 million,
including impairment charges totalling $567.1 million in respect of
the Lancaster field and the Company's exploration assets and an
associated deferred tax write-off of $54.2 million
-- An internal technical review of the Lancaster field reservoir
model resulted in significant downgrades to Lancaster Reserves and
Contingent Resources. This revised interpretation was broadly
consistent with a Competent Person's Report by ERC Equipoise
published in April 2021, and also negatively impacted the resource
potential of the Company's other discoveries
-- Net free cash of $111.4 million at 31 December 2020 (31
December 2019: $133.6 million) was significantly less than
anticipated due to lower oil prices caused by the COVID-19 pandemic
as well as lower Lancaster production than anticipated. Net debt at
year-end was $118.6 million (31 December 2019: $96.4 million)
-- In combination, lower than expected cash generation during
2020 and significantly reduced potential future cash flows from
Lancaster means the Company will not be in a position to repay its
$230 million of convertible bond debt at maturity in July 2022.
After exploring all possible alternatives, the Company announced a
proposed restructuring of the Company's Convertible Bond debt on 30
April 2021. Material uncertainties regarding the Company's ability
to continue as a going concern have been identified, pending the
results of the proposed financial restructuring process
-- If duly approved and implemented, the proposed financial
restructuring is expected to take effect in June 2021. This would
deliver a viable balance sheet from which to execute the Company's
revised strategy of maximising cash flow from the existing
Lancaster wells and infrastructure to pay down debt. In parallel,
the Company will continue to develop the technical and commercial
case for further development opportunities at Lancaster and, if
supported by its Bondholders, execute any further investment as
efficiently as possible
Non-IFRS measures. See Appendix B for definition and
reconciliation to nearest equivalent statutory IFRS measures
Antony Maris, CEO of Hurricane, commented:
"This has been a profoundly difficult period for Hurricane and
its stakeholders. The understanding of the West of Shetland
fractured basement play has changed significantly. As a result, the
potential of the Lancaster field is much smaller than originally
thought and cannot support the level of debt in the Company which
was sized for a much larger Reserves and Contingent Resources
base.
Against this extremely challenging backdrop, the Company has
explored all potential options to resolve the Company's financial
situation, with the proposed financial restructuring ultimately
being deemed the best possible outcome. We understand the impact
this will have on our shareholders and the strong feelings that
have been expressed as a result, but this was a necessary move in
order to secure the Company's future.
If the proposed restructuring is approved and implemented, we
will focus our efforts on maximising Lancaster cash flows to pay
down debt, as well as making the case for further development of
our West of Shetland asset base"
Contacts:
Hurricane Energy plc
Antony Maris, Chief Executive Officer +44 (0)1483 862
Philip Corbett, Head of Investor Relations 820
Stifel Nicolaus Europe Limited
Nominated Adviser & Joint Corporate Broker
Callum Stewart +44 (0)20 7710 7600
Investec Bank plc
Joint Corporate Broker
Chris Sim / Rahul Sharma +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 was established to discover, appraise and develop
hydrocarbon resources associated with naturally fractured basement
reservoirs. The Company's acreage is concentrated on the Rona
Ridge, in the West of Shetland region of the UK Continental
Shelf.
The Lancaster field (100% owned by Hurricane) is the UK's first
producing basement field, which was developed via an Early
Production System consisting of two wells tied-back to the Aoka
Mizu FPSO. Hydrocarbons were introduced to the FPSO system on 11
May 2019 and the first oil milestone was achieved on 4 June
2019.
In September 2018, Spirit Energy farmed-in to 50% of the Lincoln
and Warwick assets, committing to a phased work programme.
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 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 profoundly challenging year
Dear shareholders,
It was always expected that 2020 would be a crucial year for
Hurricane, but we did not anticipate facing multiple shocks from
under-performance at our key Lancaster field asset, the COVID-19
pandemic, a collapse in oil prices, and significant organisational
change. As a result, we have had to make difficult decisions in
order to reduce our financial leverage and deliver a viable
financial platform from which to take the business forward,
resulting in the proposed financial restructuring announced in
April 2021.
Covid 19 pandemic
The rapid global spread of COVID-19 during 2020 led to
distressing levels of mortality, as well as profound disruption to
businesses and personal lives. Protecting Hurricane's people from
the virus while supporting our suppliers and partners was a
critical concern during the year. The comprehensive protective
measures we have taken ensured uninterrupted offshore operations,
and our onshore staff successfully adapted to changes in the
working environment. We will aim to strike a suitable balance
between office and home working in future.
Oil prices
The pandemic had a significant impact on oil markets, with Brent
prices falling to a remarkable low of $13/bbl in April 2020 as
global lockdowns choked off oil demand. While demand and prices
recovered somewhat during 2020, the global oil supply-demand
balance remains fragile, there are ongoing effects from COVID-19,
and there are growing impacts from energy transition measures. As a
result, in a market which has always been prone to price
volatility, there is elevated uncertainty over the path of future
oil prices.
Lancaster field under-performance
The Lancaster field Early Production System (EPS) was conceived
as a long-term production test with the objective of obtaining
critical performance data on the fractured basement reservoir type,
which had never before been developed in the UK (and only rarely
globally). Previous estimates of Reserves and Contingent Resources
were based on standard well evaluation techniques and short-term
tests only, which are more difficult to interpret in fractured
basement.
It had always been recognised that a minimum of twelve months
observation of reservoir performance would be required before firm
conclusions could start to be drawn on the scale of Reserves and
Contingent Resources in Lancaster.
We had been encouraged by the operational success of bringing
the field on stream in May 2019, albeit with water production
commencing earlier than expected and increasing over time.
During the first half of 2020, Lancaster experienced a
significant deterioration in reservoir performance while attempting
to ramp production up to towards the target of 20,000 bopd. This
led to a decision to shut in the 205/21a-7z well in May 2020 and
suspend production guidance for the year. This disappointing
performance signalled a material departure from pre-production
expectations, and a need to re-visit the basic geological model and
data interpretations.
On 8 June 2020, it was announced that Dr Robert Trice had
resigned as Chief Executive Officer (CEO) by mutual consent with
the Board, and the ably qualified Beverley Smith agreed a temporary
shift from her non-executive role to become Interim Chief
Executive. A Technical Committee of the Board was established to
provide further oversight as the subsurface team, under new
leadership, re-examined the range of geological and reservoir
models for Lancaster and the other Rona Ridge assets.
Technical review
A preliminary technical review of the Lancaster field was
completed in September 2020, which concluded that the oil water
contact was significantly shallower than previously estimated, and
that effective reservoir properties within the fractured basement
were worse than previously thought, consistent with the higher
water production and more rapid pressure decline than originally
anticipated. The revised reservoir and geological model, calibrated
with observed performance, resulted in the Company significantly
downgrading the Reserves and Contingent Resources for the Lancaster
field in September 2020.
Greater Warwick Area
While the Company's main focus during 2020 was on Lancaster, the
revised interpretation of the Lancaster oil water contact also
triggered a review of the data and assumptions for all Rona Ridge
assets. Further progress has been made on understanding the Greater
Warwick Area (GWA) subsurface following extensive analysis of the
results of the 2019 drilling programme and reinterpretation of
existing seismic data. This work also incorporated the learnings
and implications from the results at Lancaster, including observed
pressure depletion at Lincoln as a result of Lancaster production.
This led to the conclusion that hydrocarbon columns are likely
limited to local structural closures, and resulted in a significant
downgrade of the GWA licence resource potential in both the Lincoln
and Warwick Crest discoveries. While the Company and its joint
venture (JV) partner continue to evaluate options for the GWA
asset, further appraisal of both discoveries would be required as a
first step before any assessment of commerciality and Reserves can
be made.
CPR
An independent Competent Persons Report (CPR) was commissioned
from ERC Equipoise Limited (ERCE) and published in April 2021, the
results of which were broadly consistent with the Lancaster and GWA
Reserves and Contingent Resources estimates published by the
Company in September 2020. Additionally, ERCE did not attribute any
Contingent Resources to the Halifax well drilled in 2017.
Financial results
In 2020, we delivered sales revenues of $180.1 million at an
average realised oil price of $35.2/bbl, resulting in operating
cash flow of $80.2 million. Net free cash of $111.4 million led to
a year end net debt position of $118.6 million. The substantial
downgrade of Reserves and Contingent Resources led to write-downs
in the carrying value of the Lancaster field and exploration
intangibles totalling $567.1 million and a write-down of deferred
tax of $54.2 million, resulting in an after tax loss of $625.3
million for the year.
Strategy and outlook
Based on the revised understanding of Lancaster, further
development options for the field were announced in December 2020
and updated in April 2021. The options include re-entry and
side-track of the existing 205/21a-7z producing well in 2022; a
seismic programme in 2022; and a water injection well and related
works in 2023, to provide reservoir pressure support.
However, the estimated capital investment of $180 million
required to implement these further Lancaster development options
is significant compared to available cash, while abandonment and
decommissioning costs must also be provided for. Future cash flows
will be constrained by lower than expected and declining oil
production rates from a single Lancaster well. Recognising the July
2022 maturity date for the Company's $230 million Convertible Bond,
in December 2020 the Company announced that it would enter into a
period of substantive discussions with certain key stakeholders,
including its Bondholders, to seek funding support and address the
Convertible Bond maturity date.
The outcome of these discussions was the proposed financial
restructuring announced on 30 April 2021. While the proposed
financial restructuring entails significant dilution for existing
equity investors, it would deleverage the Company's balance sheet,
enhance its liquidity position, extend its debt maturity profile,
and provide a stable platform upon which the Company can continue
to operate its business.
Having carefully and thoroughly considered the alternatives,
including that the likely consequence of the proposed financial
restructuring not being implemented is likely to be a controlled
wind-down of operations followed by an insolvent liquidation, the
Company believes that the outcome of implementing the proposed
financial restructuring is likely to be better for the Company, its
business and its operations and employees than in the event of this
likely alternative, and is in the best interests of the Company's
stakeholders taken as a whole.
If duly approved and implemented, the proposed financial
restructuring is expected to take effect in June 2021. However, as
approval and implementation of the proposed financial restructuring
is outside of the Company's control, there is a material
uncertainty that may cast significant doubt over the Company's
ability to continue as a going concern. For further details and
analysis, see the Going Concern section of this report.
As at the date of this report, more than 75% of Bondholders (by
value) had acceded to a lock-up agreement which incorporates
general undertakings to support the proposed financial
restructuring. The proposed financial restructuring is an ongoing
process and is subject, inter alia, to the approval of 75% (in
value) of Bondholders present and voting at a meeting convened by
the High Court of Justice and the subsequent sanction of that
Court. There will also be a Court-convened meeting of shareholders
to vote on the proposed financial restructuring. The Company will
continue to publish announcements regarding the progress of the
proposed financial restructuring at appropriate points in the
process.
Corporate Governance
The executive team changed substantially during 2020. Alistair
Stobie resigned as Chief Financial Officer and a director on 26
February 2020 by mutual agreement with the Board, and was replaced
by Richard Chaffe, who had been Head of Finance since 2016.
After the announcement of Dr Trice's departure on 8 June 2020,
Beverley Smith played a critical part in the Technical Review and
company reorganisation as Interim Chief Executive, but in line with
her desire to return to a non-executive role, a search was
undertaken for a permanent Chief Executive. This resulted in Antony
Maris being appointed Chief Executive designate on 21 August 2020
and he assumed the full role on 11 September 2020. Antony brought
35 years of wide-ranging oil and gas sector technical and
managerial experience to Hurricane, including in fractured basement
reservoir plays offshore Vietnam and onshore Yemen. Beverley now
Chairs the Technical Committee of the Board.
On 6 July 2020 we announced the very sad news that Neil Platt
had passed away. Neil was a highly respected colleague, and his
enthusiasm and technical excellence were integral to the successful
delivery and operation of the Lancaster EPS. He will be sorely
missed. Steve Holmes was appointed Chief Operating Officer,
bringing 41 years of diverse oil and gas development, operations
and commercial experience including eight years with Hurricane.
On 8 June 2020, Roy Kelly resigned as Kerogen Capital's
nominated director and was replaced by Dr Alan Parsley, while Jason
Cheng resigned from his alternate director role. On 23 September
2020, Dr Parsley resigned as Kerogen Capital's nominated director,
and Leonard Tao also stepped down from his alternate director role.
Kerogen Capital therefore currently has no board representation,
though it retains the right to appoint a director under the
relationship deed signed in 2016 and remains a significant
shareholder at the date of this report.
Given the poor production performance during 2020, the
Remuneration Committee exercised its discretionary powers, and no
awards were made to executive directors under the incentive
compensation schemes in place.
Sustainability
Despite the challenges faced during the year, we did not lose
sight of the need to advance our sustainability strategy, building
on the disclosures and commitments made in our inaugural 2019
Environmental Social and Governance (ESG) Report. We established an
ESG Committee of the Board, with Sandy Shaw as Chair, during 2020
to provide structured oversight of our programmes. We are committed
to complying with evolving reporting requirements and will align
with industry and regulatory efforts to decarbonise United Kingdom
Continental Shelf (UKCS) operations.
Acknowledgements
The West of Shetland fractured basement play has not lived up to
original expectations, with significantly reduced forecasts of
Reserves and Contingent Resources. Much poorer production rates
than expected, combined with very low oil prices during 2020, has
necessitated a proposed financial restructuring. Looking forward,
and on the basis that the proposed financial restructuring
completes, I am confident that we have an executive and management
team with the capability, drive and focus to maximise returns from
these West of Shetland assets, for the benefit of all
stakeholders.
I would like to sincerely thank the whole Hurricane team for
their hard work during this difficult period, in particular
compressing a significant amount of technical re-evaluation and
commercial work into the period since the technical re-set began in
June 2020.
Finally, I want to thank our key industry stakeholders for their
constructive help during this profoundly challenging year,
particularly the Oil and Gas Authority (OGA) and Bluewater.
Steven McTiernan
Chairman
Chief Executive Officer's Review
Introduction
My first report to you as CEO of Hurricane comes at a difficult
time for the business. Underperformance at our key Lancaster asset
has significantly reduced potential future cash flows, and current
financial projections show the Company will not be in a position to
repay its $230 million of Convertible Bond debt at maturity in July
2022. This has necessitated a proposed financial restructuring of
the Company's debt. If completed, this restructuring will deliver a
viable balance sheet which can support our revised strategy of
maximising cash flow from the Lancaster field to repay debt, and in
parallel continue to build the justification for future activity on
our West of Shetland assets.
Risks in fractured basement reservoirs
While the discovery and appraisal of the Lancaster field yielded
a significant amount of subsurface data, the development of the
UKCS's first fractured basement field carried an above average
degree of risk. Amongst the reasons why fractured basement plays
had hitherto been largely ignored in the UKCS was the difficulty in
drilling safely, and also heightened reservoir evaluation
uncertainty, in particular because conventional logging tools and
well testing techniques are not ideally suited to evaluating
fractured basement reservoirs.
Hence, both before and after first production from Lancaster,
there was a consistent emphasis in our communications on the need
to acquire dynamic data from production operations, which was
essential to help refine the wide range of Reserves and Contingent
Resources estimates for Lancaster, and our other West of Shetland
assets. While we have learned a great deal over the past 12 months,
our fractured basement assets continue to require further
investigation and analysis to narrow down the range of uncertainty
on reservoir characteristics and parameters.
Revised Lancaster geological interpretation
First production from the two Lancaster field EPS wells was
achieved on time and budget in May 2019. Production operations were
initially characterised by a series of individual and combined
tests on both the 205/21a-6 and 205/21a-7z wells. While the initial
productivity of both wells exceeded expectations, early water
production and a more rapid decline in reservoir pressure than
anticipated were the first signs that asset performance was
diverging from pre-production projections.
Initially, water production was interpreted as coming from an
isolated, intra-reservoir, water bearing interval, although the
consistent increase and quantum of water production began to
challenge this theory in the first half of 2020. When the
205/21a-7z well was shut in at the end of May 2020, it was decided
to instigate a formal review of the Lancaster field geological and
reservoir models to rigorously assess and interpret the dynamic
data acquired since first production.
The initial results of this technical review were announced in
September 2020. Lancaster is now believed to be more complex than
previously thought. Instead of being primarily a basement
reservoir, we now believe the field has Mesozoic-aged sandstones
onlapping the basement flanks which are contributing to current
production. Furthermore, and most importantly, analysis of
reservoir pressure, production and other data resulted in a
material revision of the field's oil water contact (OWC), from a
range of 1,597 - 1,678 metres TVDSS in the May 2017 RPS Energy
Lancaster CPR to 1,330 metres TVDSS. This shallower OWC is
consistent with the observed early and higher water production, and
more rapid reservoir pressure decline, than originally
expected.
Declining reservoir pressure will have a further impact on
production operations as pressure approaches the bubble point (the
point at which gas is liberated from oil within the reservoir).
Producing below bubble point may extend the life of the Lancaster
field. Following extensive technical interaction with the OGA, we
have submitted a Field Development Plan Addendum (FDPA) that will,
if approved, allow us this additional reservoir management
flexibility, subject to quarterly review of operating procedures to
ensure gas liberated in the reservoir is not produced to
surface.
The Company's revised geological and reservoir performance
interpretation was broadly consistent with the conclusions of
ERCE's independent April 2021 CPR. ERCE estimates remaining
Lancaster 2P Reserves of 7.1 MMbbls at 31 December 2020, based on
future production from the 205/21a-6 well alone. We have, and will
continue to, periodically test the 205/21a-7z well for reservoir
management purposes, although the high and increasing water cut
from this well makes sustained oil production unlikely due to the
resulting excessive reservoir voidage.
In light of the revised interpretation of the OWC, the area of
the P1368 Central licence outside the determined Lancaster field
area was voluntarily relinquished in October 2020 and Hurricane was
released of its obligation to drill a commitment well on the
licence.
Further development options for the Lancaster field
Since the outset of the technical review, a significant amount
of work has been compressed into a short period of time to further
refine the revised technical interpretation and consider further
development options for the field. In December 2020, we outlined
potential next steps for Lancaster development, namely: re-entry,
side-track to an updip location and re-completion of the existing
205/21a-7z well, to target the central area of the field to enhance
near term performance; further seismic to better image the Mesozoic
sandstones and refine the possible location of a water injection
well; and, drilling a water injection well to provide reservoir
pressure support and improved sweep to enhance both Reserves and
production. These development scenarios were refined further during
the engagement with our Bondholders.
The total combined cost of these development options is
currently estimated at approximately $180 million. These options
would commercialise some 8.7 MMbbls of ERCE's estimated 2C
Contingent Resources of 37.9 MMbbls, the majority of which is
currently classified as Development Unclarified pending further
technical and commercial work, and the financing being in place to
support any future activity.
Greater Warwick Area
During 2020, we continued to collaborate with our partner,
Spirit Energy, to refine our understanding of the potential of the
GWA licence following the 2019 drilling programme. Given the
unclear results of that drilling programme, and with more time
being required for technical and commercial analysis, the GWA JV
signed a revised cost allocation agreement in March 2020, adjusting
certain terms relating to Spirit Energy's original 2018 farm-in.
This allowed Hurricane the flexibility to progress planning and
acquisition of long-lead items for both a potential GWA tie-back
well and gas export from the Aoka Mizu ahead of a firm decision by
the JV to proceed.
During the year, the focus was on evaluating the Lincoln
discovery. In July 2020, we announced that the OGA had given notice
of a proposed field determination area over local structural
closure at the Lincoln discovery. This was subsequently accepted by
the GWA JV.
Downhole gauges were installed in the Lincoln 205/26b-14 well at
the time of drilling in 2019, which allow for periodic collection
of data to refine our understanding of reservoir conditions at
Lincoln and any implications for regional geology. In July 2020,
Lincoln pressure data was retrieved and indicated 20 psi pressure
depletion. We attribute this to the impact of Lancaster production
some 8 km distant, which suggests that Lancaster and Lincoln share
the same aquifer pressure and gradient, and that the OWC at Lincoln
is also likely to be close to the structural closure.
ERCE has estimated the OWC for the Lincoln discovery at 1,844
metres TVDSS (+/- 16 metres), and gross 2C Contingent Resources
(Development Unclarified) of 36.9 MMbbls for the basement reservoir
only. As at Lancaster, there is some evidence for Mesozoic
sandstones of Jurassic and Cretaceous age above the Lincoln
basement discovery, although these have not been demonstrated by
drilling and the Company is currently assessing their
potential.
The Company has a regulatory commitment to plug and abandon the
Lincoln 205/26b-14 well. The OGA recently approved an extension of
the deadline for this activity to 31 October 2021 (from 30 June
2021) to allow for completion of operations in the summer 2021
weather window. The GWA JV has contracted a rig for this activity,
with a gross budgeted campaign cost of c.$13 million. The OGA has
also agreed to extend the deadline for the GWA licence commitment
well from 31 December 2020 to 30 June 2022 as a result of the
disruption caused by the COVID-19 pandemic.
ERCE also estimated gross 2C Contingent Resources (Development
Unclarified) for the Warwick Crest discovery of 50.9 MMbbls. No
Contingent Resources were attributed by ERCE to the Halifax well
drilled in 2017.
The Lincoln and Warwick Crest discoveries are at an early stage
of appraisal. Further appraisal of both discoveries would be
required as a first step before any assessment of commerciality and
Reserves could be made. Any appraisal activity would involve a
significant financial commitment for Hurricane, which the Company
may not be able to fund. As a result of this funding uncertainty
and the early stage of appraisal, there is currently no reasonable
expectation that the Lincoln and Warwick Crest discoveries could
generate any meaningful near-term cash realisation. The GWA JV
partners will continue to evaluate and consider all options for the
licence going forward.
Proposed Financial Restructuring
Although the Company retained net free cash of approximately
$111 million at the end of 2020, this was significantly less than
expected because of low oil prices in 2020 and oil production rates
at substantially lower and declining levels than original
forecasts. Furthermore, the material reduction in Lancaster field
Reserves has significantly reduced production expectations, in turn
impacting future cash flow forecasts.
Given the negative impacts described above, and the likely
capital cost of further investment in the Lancaster field, the
Company decided to enter into a discussion with its Bondholders
with regard to the funding of, and required support for, possible
development options, while also addressing the July 2022 maturity
of its Convertible Bond debt.
These discussions considered the likelihood that the Lancaster
field will continue to produce from the 205/21a-6 well alone, the
Company's necessary future spending requirements, contractual and
decommissioning spending obligations, and the requirement for a
viable balance sheet going forward. The engagement resulted in the
Company announcing a proposed financial restructuring on 30 April
2021, which would entail a part-equitisation of the Convertible
Bond, and significant dilution for existing shareholders. This
difficult decision is however necessary to support the financial
future of the Company.
As at the date of this document, more than 75% of Bondholders
(by value) had acceded to a lock-up agreement which incorporates
general undertakings to support the proposed financial
restructuring. The proposed financial restructuring is an ongoing
process and is subject, inter alia, to the approval of 75% (in
value) of Bondholders present and voting at a meeting convened by
the High Court of Justice and the subsequent sanction of that
Court. There will also be a Court-convened meeting of shareholders
to vote on the proposed financial restructuring. The Company will
continue to publish announcements regarding the progress of the
proposed financial restructuring at appropriate points in the
process.
People and operations
While somewhat overshadowed by the subsurface work, Hurricane's
operational delivery since start-up of the Lancaster field has been
first class, and I commend our staff and key contractors on their
performance against the backdrop of a challenging year.
Like many businesses, we have had to adapt our working practices
and environments to reflect government and industry restrictions
enacted to keep staff safe and reduce the impact of COVID-19,
particularly on offshore operations. This has included a
significant reduction in the manning of the Aoka Mizu FPSO to
essential personnel only for most of the year. In March 2020, a
crew member on the Aoka Mizu was evacuated to the mainland and
subsequently tested positive for COVID-19. The individual made a
full recovery.
Hurricane has worked closely with its contractors, suppliers,
and local authorities to manage the impact of these restrictions on
its employees and the Company, and to date has not experienced any
adverse operational impact from COVID-19.
Our onshore staff have been working from home since March 2020
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. Feedback suggests that when a return to the office is
possible, our employees wish to preserve some measure of home
working, and we will aim to achieve this where possible. We have
also introduced initiatives to address staff isolation and
encourage contact between colleagues while we are working remotely.
I would also like to express my thanks to all our colleagues whose
hard work and dedication during a challenging 2020 helped to
compress many months of work on the technical review and
development options screening into a fraction of that time, without
compromising on rigour or quality.
Sustainability and environment
We have also maintained our focus on expanding our
sustainability strategy, with an internal ESG Working Group
established to enhance our ESG programme, with oversight from the
new ESG Committee of the Board. We are fully aligned and supportive
of the UK oil industry and regulatory initiatives to decarbonise
the UKCS oil and gas operations and target net zero greenhouse gas
emissions from the UKCS by 2050.
I am pleased to report that greenhouse gas emissions intensity
from our own operations declined in 2020 vs. 2019. We were able to
reduce diesel-related CO(2) emissions year-on-year as more of the
associated gas production from the Lancaster field was used in the
Aoka Mizu's gas turbine generators.
Previously, we had outlined plans to implement a gas export
scheme for associated gas production from our West of Shetland
assets. Unfortunately, these plans have been postponed due to the
financial and subsurface challenges we faced in 2020 and a
constrained funding environment. We will, however, continue to
investigate all possible means to reduce our GHG emissions and
implement these where it is technically, financially and
logistically feasible to do so.
Outlook
Our business has seen significant change in the last 12 months.
While this has caused upheaval and frustration for both employees
and stakeholders, we hope to emerge from the proposed financial
restructuring with a viable balance sheet that can support the
company in our core strategy of maximising cash flow from the
existing wells and infrastructure in the Lancaster field. While
implementing the NFA case, we will also continue to develop the
technical and commercial case for further development opportunities
at Lancaster and, if supported by our Bondholders, execute any
further investment case effectively.
I will also aim to reinvigorate the entrepreneurial spirit and
commitment to success which allowed Hurricane to deliver the first
UKCS fractured basement development on time and budget.
Antony Maris
Chief Executive Officer
Operations and Subsurface Review
Review of 2020 operational performance
Very sadly, Hurricane's previous Chief Operations Officer, Neil
Platt, passed away in July 2020. Neil joined Hurricane in 2011 and
was the driving force in delivering the Lancaster EPS project on
time and budget. He was a much loved and respected colleague and is
greatly missed by everyone at the Company.
From an operations perspective, the focus in 2020 was on
maintaining safe, environmentally responsible and reliable
operations from the Aoka Mizu FPSO, particularly in light of the
impact from COVID-19 on UK offshore oil and gas operations.
Furthermore, we also had to factor in the underperformance of the
Lancaster production wells into operations and production planning,
as well as deliver the production testing data required to assist
in reassessing the subsurface potential of the field.
Aoka Mizu production uptime averaged 98% in 2020, significantly
exceeding our 90% target. This is testament to the notable and
varied contributions of both Hurricane's staff and Bluewater,
particularly given offshore manning levels were reduced in light of
the COVID-19 pandemic. Following completion of remaining equipment
tests, final acceptance of the Aoka Mizu was achieved in November
2020.
The planned annual Aoka Mizu shutdown was undertaken in early
September 2020 and was safely completed in five rather than the
scheduled seven days. Our employees, contractors and partners
should be congratulated on this excellent performance. Our 2021
annual shutdown is currently planned to take place in July
2021.
During the year there were 12 liftings totalling 5.1 MMbbls. We
have been investigating ways to increase resilience, optionality
and flexibility in our offloading schedule, through trial loadings
of a number of alternative vessels which can deliver Lancaster
crude. Two of these trials have been carried out successfully in
2021 to date, including a shuttle tanker with LNG fuelled
propulsion, which has a lower greenhouse gas footprint than our
existing tanker pool.
We have had to work in close cooperation with our stakeholders
and government authorities to manage the impact of COVID-19 on
offshore operations during 2020. We saw this first-hand in March
2020, when a crew member onboard the Aoka Mizu was evacuated to the
mainland for medical reasons and subsequently tested positive for
COVID-19. Subsequently a number of precautionary flights were
arranged to return suspected COVID-19 cases to shore. We are happy
to confirm that the individual who tested positive for COVID-19
made a full recovery. We have worked closely with Bluewater, as
installation operator of the Aoka Mizu, with its response to the
March COVID-19 case and also on the planning to mitigate the impact
of COVID-19 on the crew of the Aoka Mizu. Throughout this period,
safeguarding measures put in place ensured that production
operations were unaffected.
During the year, we have developed and refined pre-mobilisation
offshore COVID-19 travel arrangements before outbound staff are
mobilised to the Aoka Mizu. Currently, passengers are required to
complete an offshore travel pre-flight self-declaration form and
undertake a pre-mobilisation temperature check and a COVID-19 test
before being deemed 'fit to fly' and permitted to travel to the
heliport for outbound travel to the Aoka Mizu. If the test result
is positive, outbound travel is restricted until a further COVID-19
test confirms a negative result. Passengers who do not meet these
criteria are requested to self-isolate for 10 days if they are able
to do so or seek appropriate medical help if they cannot. Face
coverings are provided to all passengers on transit to the FPSO,
the use of which is mandatory when travelling by helicopter. Upon
arrival at the FPSO, passengers are provided with their own single
berth cabins, while daily COVID-19 health screening is undertaken,
and mandatory COVID-19 testing has been introduced on the fourth
day after arrival. The wearing of face masks to prevent airborne
transmission is also required, where
practicable. While UK border control travel restrictions are
impacting our ability to mobilise and demobilise non-UK based
offshore crew members as would be routinely planned, to date we
have not experienced any significant negative impact from the
pandemic on our operations.
Lancaster EPS oil production during 2020 totalled 5.1 MMbbls, or
an average of 13,900 bopd. Production was higher in the first half
of the year with both the 205/21a-6 and 205/21a-7z wells onstream
in various configurations as part of the ongoing data gathering
exercise. In May 2020, performance issues led to production from
well 205/21a-7z being suspended. In June 2020, following a partial
lifting of COVID-19 restrictions on UKCS activity, we successfully
commissioned the electric submersible pumps (ESPs) installed in the
Lancaster production wells. With the benefit of artificial lift
from the ESPs, the 205/21a-7z well was brought back onstream at
different rates to test performance and liquid output. However,
with produced water now interpreted as originating from an
underlying aquifer rather than an isolated water zone, part of the
205/21a-7z well is now considered to be in the water leg, with oil
production being "coned" from the reservoir above the well.
As a result, a decision was taken in November 2020 to produce
the field from the 205/21a-6 well alone. This production strategy
has been implemented for the majority of the time since November
2020, with the well currently producing 11,250 bopd using
artificial lift with a water cut of 30%. Under the NFA scenario,
which is the likely outcome of the Company's proposed financial
restructuring unless new development activity is approved
(including by the Company's Bondholders), production from the
205/21a-6 well is expected to continue exhibiting a slow decline
until the economic limit of the field is reached.
Based on current trends, it is possible that the wellhead
flowing pressure in the Lancaster reservoir may approach the
"bubble point" (the point at which gas is liberated from oil within
the reservoir) in late 2021 or early 2022. We are currently in a
discussion with the OGA on an addendum to the Lancaster Field
Development Plan to allow reservoir pressure to go below bubble
point, as an emerging gas cap may provide a "piston" like effect
where oil in the Lancaster field is driven into the producing
wells. Our production guidance for 2021 is 8,500 - 10,500 bopd,
which is based on an FPSO production uptime assumption of 90% and
production from the P6 well alone.
Planning is underway to meet our regulatory commitment to plug
and abandon the Lincoln 205/26b-14 well, with the Stena Don rig
contracted on behalf of the GWA licence partners to perform this
activity during the summer of 2021.
Health and Safety
In 2020, Hurricane recorded one Lost Time Incident, when an
offshore technician fell during scheduled maintenance activities
and incurred injuries to his shoulder and ribs. The individual made
a full recovery. The incident was fully investigated by Bluewater
and Hurricane; with control of work, supervision and spatial
awareness identified as the main underlying contributing factors to
the Lost Time Incident. Safety and control procedures were
strengthened as a result. The Lost Time Incident Frequency rate for
2020 was 1.29, compared to 0 for 2019.
The health and safety of our onshore colleagues has also been a
priority given the home working arrangements put in place to manage
the spread of COVID-19. We have conducted home working assessments
to ensure that our staff have the necessary equipment and
appropriate working conditions for safe and effective remote
work.
Operational emissions
During 2020, our Scope 1 greenhouse gas emissions were 209,421
tonnes, or 41.2kg/bbl on an intensity basis. This compared to
145,388 tonnes and 48.0kg/bbl in 2019, when the Lancaster field was
only producing for 7 months. Our 2019 greenhouse gas emissions have
been restated to include emissions from logistical support to the
FPSO, in line with the OGUK definition, and expanded to include
other greenhouse gases specified by the Kyoto Protocol.
In particular, 10% of our CO(2) emissions in 2020 were from
diesel consumption, down from 20% in 2019 following successful
commissioning of the FPSO's fuel gas compressor and gas turbine
generators. We will continue to look at ways of further reducing
this figure in 2021 and beyond.
Previously, the tie-back of a well from the GWA licence was
considered to be the trigger for the requirement to put in place a
gas export scheme from our West of Shetland acreage. Long-lead
items were acquired in 2019 for this purpose. However, the need for
further work on the commercial potential of the GWA licence, allied
to the financial constraints on our business, means we are not
currently in a position to finance or implement a gas export scheme
to significantly reduce our flaring emissions. However, we continue
to look at ways of reducing our environmental footprint, whether
physically or offsetting our emissions elsewhere. We remain fully
cognisant of the increased scrutiny and oversight in this area.
Reserves and Contingent 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. As a
result, a full technical review of the Lancaster field and the
Company's wider West of Shetland portfolio was commissioned in June
2020. In September 2020, the initial findings of this review were
announced, resulting in a material downgrade to the Reserves and
Contingent Resources for the Lancaster field (compared to the May
2017 RPS Energy Lancaster CPR) as a consequence of a significantly
shallower OWC than previously thought, consistent with higher water
production and more rapid pressure decline than originally
anticipated.
The Contingent Resources associated with the Lincoln discovery
were also downgraded (compared to the December 2017 RPS Energy West
of Shetland CPR). This followed an extensive review of the 2019
drilling data and re-interpretation of seismic in light of the
updated assessment of Lancaster, in particular that hydrocarbon
columns are likely limited to local structural closures.
To provide an independent assessment of the Company's assets,
ERC Equipoise was appointed as the Company's Independent Competent
Person and Reserves auditor in November 2020. ERCE's CPR was
published in April 2021, with the analysis and conclusions broadly
consistent with the initial findings of the technical review in
September 2020.
The revised interpretation of the Lancaster OWC also triggered a
review of the Halifax historical data set and assumptions. No
Contingent Resources were attributed by ERCE to the Halifax well
drilled in 2017.
ERCE's estimates of Lancaster field Reserves, and the Contingent
Resources estimated for Lancaster and the Lincoln and Warwick Crest
discoveries are detailed in the tables below. ERCE's work was
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 2020.
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, partner and
Bondholder 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 of the Aoka Mizu.
The Lincoln and Warwick Crest discoveries on the GWA licence are
at an early stage of appraisal. While the Lincoln 205/26b-14 well
flowed at approximately 9,800 bopd on test using an ESP in 2019
with a productivity index (PI) of 18 stb/d/psi, there remains
significant uncertainty over future reservoir performance, and an
appraisal programme to refine reservoir parameters would be
required to better assess the potential for Lincoln's Reserves and
commerciality. Ahead of any such appraisal plan, the Company has a
regulatory commitment to plug and abandon the Lincoln 205/26b-14
well by 31 October 2021 as described above.
The Warwick Crest discovery well flowed at approximately 2,000
bopd in 2019 on test using an ESP with a PI of 3 stb/d/psi. The
Company considers that such a rate and PI is significantly below
the level which would support a commercial development. An
appraisal programme would be required to further refine the
reservoir parameters of the Warwick Crest discovery, demonstrate
increased flow rates and a higher PI and establish the potential
for commerciality.
The potential GWA licence appraisal activity described above
would involve a significant financial commitment for Hurricane
before any assessment of commerciality can be made, which the
Company may not be able to fund. As a result of this funding
uncertainty and the early stage of appraisal, there is currently no
reasonable expectation that the Lincoln and Warwick Crest
discoveries could generate any meaningful near-term cash
realisation. The GWA JV partners will continue to evaluate and
consider all options for the licence going forward.
ERCE's estimates of Reserves for the Lancaster field
(MMbbl) Gross Net attributable to
Hurricane
-------------------- ----------------- ------------------------
1P 2P 3P 1P 2P 3P
-------------------- ---- ---- ----- ------- ------ -------
Developed Reserves
(MMbbl)(1) 3.3 7.1 10.8 3.3 7.1 10.8
-------------------- ---- ---- ----- ------- ------ -------
Notes:
1. In determining the economic Reserves for the Lancaster field,
ERCE has assumed a Brent oil price of US$50/bbl in 2021, US$53/bbl
in 2022, US$55/bbl in 2023 and US$56/bbl in 2024 and thereafter in
real terms. Prices are escalated at 2.0% per annum inflation
ERCE's estimates of Contingent Resources for the Lancaster
field
(MMbbl) Gross Net attributable
to Hurricane
----------------------------- ------------------- ---------------------
1C 2C 3C 1C 2C 3C
----------------------------- ----- ----- ----- ------ ------ -----
Contingent Resources,
Development Pending
(P8 well)(1,2) 4.0 3.2 1.9 4.0 3.2 1.9
----------------------------- ----- ----- ----- ------ ------ -----
Contingent Resources,
Development Unclarified(3) 11.8 34.7 87.1 11.8 34.7 87.1
----------------------------- ----- ----- ----- ------ ------ -----
Total 15.8 37.9 89.0 15.8 37.9 89.0
Notes:
1. The P8 well is the proposed side-track of the existing
205/21a-7z well, which the Company is considering drilling in
2022
2. Incremental resources are computed by the subtraction of the
Reserves estimates for Lancaster from estimates of future
recoverable volumes from the combined activity of the P6 and P8
wells. As the forecasts for the combined activity of the P6 and P8
wells both accelerate production and add additional resources, the
incremental resources associated with the P8 well decrease as the
Reserves attributed to the Lancaster field increase
3. Contingent Resources, Development Unclarified, assume water
injection is implemented as part of any further development
ERCE's estimates of Contingent Resources for the Lincoln
discovery.
(MMbbl) Gross Net attributable
to Hurricane
----------------------------------- ------------------- ---------------------
1C 2C 3C 1C 2C 3C
----------------------------------- ----- ----- ----- ----- ------ ------
Contingent Resources, Development
Unclarified(1,2) 17.4 36.9 79.8 8.7 18.5 39.9
----------------------------------- ----- ----- ----- ----- ------ ------
Total 17.4 36.9 79.8 8.7 18.5 39.9
Notes:
1. Contingent Resources, Development Unclarified, assume water
injection is implemented as part of any development
2. Net attributable figures are rounded to one decimal point
ERCE's estimates of Contingent Resources for the Warwick Crest
discovery
(MMbbl) Gross Net attributable
----------------------------------- -------------------- ---------------------
1C 2C 3C 1C 2C 3C
----------------------------------- ----- ----- ------ ----- ------ ------
Contingent Resources, Development
Unclarified(1,2) 19.6 50.9 128.9 9.8 25.5 64.5
----------------------------------- ----- ----- ------ ----- ------ ------
Total 19.6 50.9 128.9 9.8 25.5 64.5
Notes:
1. Contingent Resources, Development Unclarified, assume water
injection is implemented as part of any development
2. Net attributable figures are rounded to one decimal point
Steve Holmes
Chief Operations Officer
Chief Financial Officer's Review
Key figures
2020 2019
Production 5,078 Mbbl 3,030 Mbbl
------------ ------------
Production rate* 13,900 bopd 12,900 bopd
------------ ------------
Sales volumes 5,112 Mbbl 2,874 Mbbl
------------ ------------
Revenue $180.1m $170.3m
------------ ------------
Average sales price realised $35.2/bbl $59.3/bbl
------------ ------------
Cash production cost per barrel $17.9/bbl $21.8/bbl
------------ ------------
Operating cash flow $80.2m $112.2m
------------ ------------
Closing net free cash $111.4m $133.6m
------------ ------------
Net debt $118.6m $96.4m
------------ ------------
Underlying (loss)/profit before
tax $(36.0)m $30.0m
------------ ------------
Statutory (loss)/profit after
tax $(625.3)m $58.7m
------------ ------------
* Rounded to nearest 100 bopd; 2019 rates calculated from First
Oil in 2019.
Non-IFRS measures. See Appendix B to the Financial Statements
for definition and reconciliation to nearest equivalent statutory
IFRS measures.
Overview
2020 was a year when Hurricane had to focus on financial
discipline, on both the operating and capital side, amidst the
challenges of COVID-19, macro-economic environment and the
underperformance of the Lancaster field.
Despite the historic low oil prices seen across the period, and
the reduced performance of the Lancaster wells, over 5.1 million
barrels of Lancaster crude were sold across 12 cargoes, generating
$180 million in revenue. The Group was still able to generate
positive cash flow from operations of $80 million, thanks to the
low operating costs and production efficiency of the Lancaster EPS.
It is also testament to Hurricane's employees and key Tier 1
contractors that despite the ongoing impacts of COVID-19 there was
minimal disruption to operations and business both offshore and
onshore. Alongside operations at Lancaster, work continued on our
joint venture with Spirit, including the build out of previously
committed long-lead items for, and planning of, a potential future
GWA tie-back and other studies to better understand the regional
hydrocarbon potential.
The statutory loss for the year was driven by significant
non-cash asset impairments relating to Lancaster ($519.2 million),
where reduced performance of the Lancaster wells, combined with the
more volatile oil price environment and uncertainty over future
work programmes has materially reduced future expected cashflows
from the asset; and Halifax ($35.4 million), as a result of the
2021 CPR attributing no Reserves or Contingent Resources to the
area.
The Group incurred $62.0 million of cash capital expenditure
(primarily on items and projects already committed to prior to the
impact of COVID-19), ending the year with $111.4 million of net
free cash .
Although Hurricane closed the year with a strong net free cash
position, the reduced Reserves estimates and production outlook as
a result of the revised understanding of the Lancaster field has
significantly reduced potential future cash flows from the field,
and consequently current financial projections show the Company
will not be in a position to repay its $230 million of Convertible
Bond debt at maturity in July 2022. As such, Hurricane entered into
a period of stakeholder engagement with regards to funding of
future projects, support for development options, and repayment of
the Convertible Bond debt. In April 2021, Hurricane entered into a
lock-up agreement with an ad hoc group of its Bondholders in order
to secure their support for a proposed financial restructuring that
will deleverage the balance sheet, enhance Hurricane's liquidity
position, reduce the amount of debt repayable upon maturity of the
Convertible Bonds and extend its debt maturity profile. If duly
approved and implemented, the proposed financial restructuring is
expected to take effect in June 2021 and will result in significant
dilution for existing shareholders, a difficult, but necessary
decision to support the financial future of the company.
As at the date of this report, the proposed financial
restructuring is an ongoing process and is subject, inter alia, to
the approval of the requisite majority (in value) of Bondholders
and the sanction of the High Court of Justice. There will also be a
Court-convened meeting of shareholders to vote on the proposed
financial restructuring. The Company will continue to publish
announcements regarding progress of the proposed financial
restructuring at appropriate points in the process.
Revenue
Revenue recognised for the year was $180.1 million, with an
average realised price of $35.2/bbl across 12 cargoes (comprising
5.1 million barrels). Whilst the average Dated Brent price for the
year was $41.7/bbl, under the sales and marketing agreement
Hurricane has in place with BP, the sale of Lancaster crude is
priced at the average of either the first or last five days of the
month of lifting (at the buyer's option). In volatile pricing
environments, such as was seen during the unprecedented months in
H1 2020, this meant that the contracted Dated Brent price was
typically lower than the spot price at date of sale.
After taking into account this timing and volatility impact, the
remaining discount to the contractual Brent price was $2.9/bbl
(2019: $3.1/bbl), representing the discount or premium offered by
the refinery purchasing the crude, BP's marketing fee, and freight
and other necessary costs incurred by BP in transporting Lancaster
crude to its ultimate destination. The refinery discounts
experienced saw significant variability during the first half of
2020 amid a highly volatile crude market. With all cargoes sold to
date having been on time, within specification and contractual
terms, Hurricane has a growing reputation as a reliable
producer.
Cost of sales
Total cost of sales was $179.8 million, including $96.6 million
of non-cash depreciation charges. Cash production costs (which
exclude depreciation and accounting movements in inventory but
include the fixed lease charges for the Aoka Mizu) were $90.6
million (2019: $66.0 million), equivalent to $17.9 per barrel
(2019: $21.8/bbl).
The decrease in cash production costs per barrel was partly due
to the revenue-linked incentive tariff for the Aoka Mizu (whereby a
reduction in realized sales prices results in a direct reduction in
production costs, partially reducing oil price risk exposure to the
Group). Excluding the incentive tariff, cash production costs
reduced from $16.7/bbl in 2019 to $14.6/bbl in 2020, driven by
higher average production rates in 2020 and cost reductions across
operations.
Impairment of oil and gas assets
As a result of the downwards revision of estimated Reserves
announced in September 2020 (which were refined and revised by ERCE
in the April 2021 CPR), revised production forecasts following the
shut in of 205/21a-7z well, and the more uncertain outlook for oil
prices, a non-cash impairment charge of $519.2 million was
recognised against the Lancaster oil and gas assets. This charge
was estimated using the best estimate of future cashflows that
could be generated from Lancaster, using a probability weighted
expected value approach which took into account the fact that a no
further activity case was most likely, and that any investment
cases to significantly enhance production through new wells would
require Bondholder approval, should the proposed financial
restructuring complete. These estimates also included management's
own forecasts of production rates using reservoir simulation
models. For further details on the impairment charge, key
assumptions and methodology used see note 2.3.1 below. These
estimates and assumptions are subject to risk and uncertainty, and
therefore changes to external factors and internal developments and
plans (including the sanction or otherwise of any work programme,
the timing thereof, oil prices, and any other intervening
developments) have the ability to significantly impact these
projections, which could lead to additional impairments or
reversals in future periods.
Impairment of intangible assets
Following the conclusion of the group's technical review and
publication of the 2021 CPR, a non-cash charge of $35.4 million was
recognised to fully impair the carrying value of the Halifax well.
The CPR did not attribute any Reserves or Contingent Resources to
Halifax, nor does the Group have any current plans or budgets for
substantive expenditure on further exploration or evaluation on
this licence. Impairments and write-offs of intangible exploration
and intangible assets included $12.1 million relating to
Hurricane's share of idle hire costs for the Paul B Loyd Jr rig,
which was contracted in anticipation of GWA drilling and/or well
abandonment activity in 2020. Following the extension of consents
to plug and abandon the 205/26b-14 Lincoln well from 2020 into
2021, and an extension of the consent to commence drilling the GWA
commitment well to 30 June 2022, the JV partners took the decision
to terminate the hire of the rig in May 2020 and settle the
remaining minimum hire costs with the rig operator.
Other profit and loss
General and administrative costs (G&A) increased from $0.4
million in 2019 to $4.2 million in 2020. Excluding the impact of
non-cash charges, net G&A before non-cash items decreased from
$3.0 million to $2.9 million primarily due to more staff and
administrative costs now included within cost of sales with 2020
representing the first full year of operations, partially offset by
an increase in professional fees included within non-staff costs as
we entered into a period of discussion with key stakeholders
towards the end of the year.
Net finance costs increased from $21.5 million in 2019 to $35.5
million in 2020, driven by the cessation of interest capitalisation
and the commencement of lease interest recognised effective at the
date of First Oil in May 2019, and the cost of hedging options
purchased in 2020 (see 'Hedging' below).
Convertible Bond accounting
The accounting for the Convertible Bond required the recognition
of an embedded derivative liability related to the equity
conversion option, with the liability effectively representing the
value to Bondholders of the conversion option at the balance sheet
date. The fair value of the embedded derivative is valued using an
option pricing model, with the key inputs being the Company's share
price and its share price volatility. Any decrease in the liability
creates a corresponding non-cash credit in the income statement.
See note 5.1 below for further details.
The fair value gain recognised during the year in relation to
the embedded derivative was $35.4 million (2019: $34.7 million
gain), primarily driven by decreases in the Company's share
price.
The gains recognised in the year do not have any impact on the
Group's cash position, amounts payable in respect of the
Convertible Bond, or on its tax position. Upon conversion or
repayment of the Convertible Bonds (or should the proposed
financial restructuring be implemented), the derivative liability
will be released to the Income Statement. Should the conversion
rights not be exercised (for example, as a result of the proposed
financial restructuring), a taxable gain of $39.0 million would
arise (being the amount of the embedded derivative initially
recognised on issuing the Convertible Bonds in 2017).
Hedging
In June 2020, Hurricane hedged a portion of its forecast
production for the second half of 2020. A total of 1.8 million
barrels (equivalent to c.10,000 bopd), was hedged through the
purchase of put options with an average strike price of $35/bbl
(Dated Brent). The average strike price of $35/bbl represented a
floor for the hedged volumes with Hurricane retaining any upside in
oil prices above this level. The cost of acquiring the put options
was $3.4 million, and the options expired out of the money in
December 2020. Under the terms of the proposed financial
restructuring, so long as the Amended Bonds remain outstanding, the
Group will not be permitted to enter into any further oil price
hedging contracts.
Cashflow
The Group ended the year with $111.4 million of net free cash ,
a decrease of $22.2 million from the position at 31 December
2019.
Even with oil prices falling to historic lows during the year
and production being lower than expectations due to reservoir
performance issues and shut-in of the 205/21a-7z well for over half
of the year, the Lancaster EPS was still able to be cash
generative, contributing cash per barrel (before working capital
movements) of $17.4/bbl (2019: $37.5/bbl).
Other operating cash outflows included $3.4 million for the
purchase of term put options and $2.1 million on plugging and
abandoning the previously suspended Halifax and Whirlwind wells.
After adjusting for movements in working capital, the Group's
operating cash inflow for the year amounted to $80.2 million.
Cash capital expenditure in the period was $62.0 million
reflecting, in the most part, items previously committed to or
capital expenditure required to meet work obligations under the
Group's licences. Expenditure on GLA activities related to
preparations for gas export work, long-lead items in preparation
for future drilling activity, and the cost of scoping production
enhancement opportunities for the Lancaster field (including a
possible water injector and a side-track of the existing 205/21a-7z
well). Net cash outflows relating to GWA represented the Group's
share of its costs of the joint operation, including long-lead
items and FPSO enhancements relating to a potential future GWA
tie-back, long-lead items for the GWA commitment well and idle rig
costs of the Paul B Loyd Jr (see above).
Financing outflows of $26.8 million mainly included $17.3
million for coupon payments of the Convertible Bond and the fixed
lease repayments primarily for the Aoka Mizu.
Restricted funds
As of 31 December 2020, the Group held $51.6 million of cash and
liquid investments within restricted funds, relating to FPSO early
termination fees and decommissioning security arrangements.
Following start-up of production from the EPS, the Group is
required to set aside a contractually determined amount of cash
generated from oil sales to cover a proportion of the termination
costs of the FPSO lease should the Group wish to exit the charter
outside of contractual option periods. The balance classified as
restricted cash under this arrangement was $26.5 million (31
December 2019: $11.1 million).
As part of the original Lancaster Field Development Plan
approval, Hurricane was required to provide security for its
decommissioning liability on the Lancaster field on a post-tax
basis. This had been satisfied by way of a decommissioning bond
since February 2019. However, following the fall in oil prices in
H1 2020 and the downward revision to the Lancaster field's
Reserves, the bond provider requested Hurricane provide cash
collateral for the entire bond value. As this would provide no
benefit to Hurricane, the decommissioning bond was terminated by
mutual agreement in October 2020, and has now reverted to the
arrangement in place prior to the decommissioning bond structure,
whereby GBP16.8 million ($22.8 million) of cash security is held in
trust in order to continue meeting the obligation to provide
post-tax security for the estimated cost of decommissioning the
production wells, subsea infrastructure and related FPSO costs for
the Lancaster Early Production System. 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. Once completed, this will
result in an additional GBP11.2 million being placed into escrow
and classified as restricted cash, expected to occur in June
2021.
Decommissioning
The Group holds provisions totalling $61.2 million for the
anticipated cost of decommissioning its suspended and producing
wells and associated infrastructure. Current provisions comprise
the cost of plugging and abandoning the Lincoln 205/26b-14 and the
suspended Lancaster 205/21a-4z well. The estimated cost of
decommissioning the Lincoln 205/26b-14 well is $13 million, of
which Hurricane will bear 50%, and is required to be plugged and
abandoned by 31 October 2021. Non-current provisions represent the
estimated cost of plugging and abandoning the producing Lancaster
205/21a-6 and 205/21a-7z wells, removing the associated subsea
infrastructure and related FPSO costs. As at 31 December 2020,
GBP16.8 million ($22.8 million) of cash was held in trust under
decommissioning security agreements in respect of the Lancaster EPS
with an additional GBP11.2 million ($15.7 million) expected to be
added into trust in June 2021 (see 'Restricted funds' above).
During the year, the Halifax and Whirlwind wells were successfully
plugged and abandoned at a cost of $2.1 million.
Tax
The Group recognised a total tax charge for 2020 of $54.2
million, all of which related to deferred tax and was non-cash. At
31 December 2019, following commencement of production from the
Lancaster EPS and estimates of future taxable profits, a deferred
tax asset and corresponding deferred tax credit of $54.3 million
was recognised in respect of trading losses accumulated to date. As
a result of the 2021 CPR and technical review (and associated
impairment of assets) estimates of future taxable profits have been
revised downwards meaning that it is now not forecast that there
will be sufficient future taxable profits against which to offset
all of these tax losses. The deferred tax asset has therefore been
written down to the estimated amount of recoverable tax losses,
resulting in a net non-cash tax charge of $54.2 million in the
year.
Tax losses
Due to the nature of the Group's business, it has accumulated
significant tax losses since incorporation. The Group has $468.7
million of ring-fenced trading losses and other allowances and
supplementary charge losses of $707.8 million, which have no expiry
date and would be available for offset against future trading
profits, and $383.5 million of capital allowances available against
future ring-fenced trading profits. The Group also has pre-trading
expenditure of $119.3 million, for which tax relief may be
available should the Group's remaining licences reach the
development stage.
Brexit
Management continues to monitor the impact of the UK's
withdrawal from the European Union, which took effect from 31
January 2020, although in some instances there is still effectively
a transition period until June 2021 (with respect to customs
protocols and visa requirements). Some changes have been made to
manifest and shipping processes to reflect known requirements. Firm
decisions or guidance regarding final requirements remain subject
to change; however, to date, the Group has not experienced any
significant delays to goods or increased tariffs. As the overall
proportion of EU-sourced suppliers is not significant, the Group's
licences and activities are entirely based within the UK, and all
crude oil sales are made to a UK customer; the Group therefore does
not consider the ongoing implications of Brexit to be a significant
risk. Management continues to monitor and engage with industry to
ensure the Group is best placed to meet any new requirements as and
when these are known.
Richard Chaffe
Chief Financial Officer
Going concern statement
The Group ended the year with $166.5 million of cash and cash
equivalents and liquid investments, of which $114.9 million was
unrestricted. After adjusting for working capital items, net free
cash at 31 December 2020 was $111.4 million. The Group's most
significant long-term liabilities are the Convertible Bond in issue
of $230 million with a coupon of 7.5% payable quarterly in arrears,
which matures in July 2022 (and which, as outlined below and
elsewhere in this document, the Group is currently seeking to
restructure), 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 above
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.
Proposed financial restructuring
The proposed financial restructuring, expected to complete in
June 2021 subject to Bondholder approval and court sanction, will
primarily comprise:
-- a reduction of the Convertible Bond principal outstanding
from $230 million to $180 million; in exchange for the allotment
and issue of new shares to existing Bondholders representing
approximately 95% of the Group's enlarged issued share capital
after completion of the transaction;
-- the Amended Bonds carrying an annual coupon rate of 9.4%
(cash pay) plus 5.0% (payment in kind), interest accruing
quarterly; with a mandatory excess cash sweep mechanism to redeem
payment in kind interest and principal at each interest payment
date;
-- the provision of certain security and subsidiary guarantees;
-- the maturity date of the Amended Bonds extended to 31 December 2024; and
-- the Amended Bonds now containing a key financial covenant
that requires the Group's liquidity (being consolidated cash and
cash equivalents of the Group that are not subject to any security
interests or held under escrow arrangements) to be not less than
$45 million until cessation of production from the Lancaster
field.
The proposed financial restructuring is also dependent on
certain conditions precedent being satisfied or waived by 75% of
the participating Bondholders by value; the key condition being
consent from the Regulator to an amendment to the Lancaster Field
Development Plan to permit production with flowing bottom hole
pressure up to 300 psi below the bubble point of the fluid (1,605
psia at 1,240 metres TVDSS).
There is no guarantee that the conditions will be satisfied (or
waived, if applicable), in which case the proposed financial
restructuring would not be implemented on its current terms or
possibly at all.
Assessment of going concern - base case (which assumes
implementation of the proposed financial restructuring)
The directors have performed a robust assessment of the going
concern assumption, considering the Group's ability to continue as
a going concern from the date of approval of these Financial
Statements through to 31 July 2022, (thus incorporating the
redemption date of the Convertible Bond, absent the proposed
financial restructuring) with the following key assumptions as its
base case:
-- completion of the proposed financial restructuring effective 30 June 2021;
-- Dated Brent oil price of $65/bbl for the remainder of 2021,
$64/bbl in 2022 and $62/bbl thereafter;
-- production from the P6 well alone as modelled using reservoir simulation modelling;
-- renegotiated terms of the Aoka Mizu FPSO charter; and
-- no sanction of further investment cases.
These production profiles modelled incorporated different oil
price and technical assumptions to those included in the ERCE CPR,
but were within the ranges of reserves and contingent resources
estimated by ERCE. The analysis included a review of the budget for
the year ending December 2021 and onwards, committed capital
expenditure, regret costs and longer-term forecasts and plans,
including consideration of the principal risks faced by the Group,
and taking into account the ongoing impact of the global COVID-19
pandemic on the macroeconomic situation and any potential impact to
operations.
This analysis has considered whether cash inflows from operation
of the Lancaster asset together with cash balances held, plus
amounts due from Spirit of $12.0 million in respect of the joint
venture funding, are forecast to be sufficient to allow the Group
to meet its outstanding trade and other payables of $16.4 million
and current decommissioning provisions of $15.5 million that
existed at 31 December 2020, lease payments (primarily for the Aoka
Mizu FPSO) and other operating costs, cash coupon payments and
mandatory prepayment provisions on the proposed restructured
Amended Bonds debt, and capital expenditure contracted for but not
recognised as a liability; and whether the Group would be able to
meet the minimum liquidity covenant of the Amended Bonds.
Under the base case, the Group is forecast to have sufficient
headroom on the liquidity covenant throughout the going concern
period.
Sensitivities to the base case were run where oil prices were
reduced by a flat $10/bbl, and forecast production reduced by 10%
throughout the going concern period. In these downside scenarios,
individually and in aggregate, the Group was forecast to have
headroom on the liquidity covenant throughout the going concern
period.
As a reverse stress test, it was estimated that either an
immediate reduction to the oil price to $40/bbl flat, a reduction
to the forecast production rates by approximately 40%, or a
complete cessation of production for approximately 4 months during
the going concern window could cause a breach of the liquidity
covenant. It is likely that these circumstances would also
constitute an event of default by virtue of being a material
adverse event or events under the terms of the Amended Bonds.
Assessment of going concern - proposed financial restructuring
does not complete
Should the proposed financial restructuring not go ahead, both
under the production simulations and oil price assumptions used in
the base case above, or any reasonably possible movement in oil
prices, production rates and other assumptions (individually or in
aggregate), the directors do not forecast a scenario where there
would be sufficient free cash available to fully repay the $230
million principal due on the Convertible Bond in July 2022. As such
the ability of the Group to continue trading as a going concern
would depend upon the occurrence of one or more of the
following:
-- a significant successful equity raise;
-- Bondholders and creditors providing further financial waivers and/or amendments;
-- the Group agreeing alternative plans for a proposed financial
restructuring with stakeholders.
However, in the opinion of the directors, the possibilities of
these scenarios being successful is remote; and should the proposed
financial restructuring not complete, it is likely that there would
be a controlled wind-down of operations followed by an insolvent
liquidation of the Group.
Conclusion
Based on all required court and regulatory approval processes
being complete and the required percentage of the Group's
Bondholders by value having voted in favour of the proposed
financial restructuring, the proposed financial restructuring is
expected to complete in June 2021. The Bondholder approval requires
the support of 75% (by value) of the Bondholders present
(virtually) or by proxy and voting at a meeting convened by the
court. As of 24 May 2021, in excess of 75% by value of Bondholders
had acceded to a lock-up agreement agreeing to support the proposed
financial restructuring. As a result of the going concern
assessment presented above, and on the assumption that the proposed
financial restructuring completes in the timeframe outlined, 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.
However, successful completion of the proposed financial
restructuring is subject to, inter alia, Bondholder approval and
the Court sanctioning the proposal, and as such is outside of the
Group's control. The directors therefore acknowledge that the
events and conditions described above, relating to the
uncertainties regarding management's ability to complete the
restructuring and (should it not complete) management's ability to
complete an alternative restructuring and prevent a controlled
wind-down and/or insolvent liquidation of the Company, together in
aggregate give rise to a material uncertainty that may cast
significant doubt on the Group's and Company's ability to continue
as a going concern.
As at the date of this document, the proposed financial
restructuring is an ongoing process and is subject, inter alia, to
the approval of the requisite majority (in value) of Bondholders
and the sanction of the High Court of Justice. There will also be a
Court-convened meeting of shareholders to vote on the proposed
financial restructuring. The Company will continue to publish
announcements regarding progress of the proposed restructuring at
appropriate points in the process.
Group Statement of Comprehensive Income
Year ended Year ended
Notes 31 Dec 2020 31 Dec 2019
$'000 $'000
Revenue 2.1 180,083 170,283
Cost of sales 2.2 (179,816) (118,453)
--------------------------------------- ----- ----------- -----------
Gross profit 267 51,830
General and administrative expenses (4,229) (400)
Impairment of oil and gas assets 2.3 (519,152) -
Impairment of intangible exploration
and evaluation assets and exploration
expense written off 2.4 (47,945) (66,468)
--------------------------------------- ----- ----------- -----------
Operating loss (571,059) (15,038)
Finance income 2,696 1,741
Finance costs (38,160) (23,206)
Fair value gain on Convertible Bond
embedded derivative 5.1 35,431 34,691
Loss before tax (571,092) (1,812)
Tax 6.1 (54,233) 60,487
--------------------------------------- ----- ----------- -----------
Total comprehensive (loss)/profit
for the year (625,325) 58,675
--------------------------------------- ----- ----------- -----------
Cents Cents
(Loss)/earnings per share - basic 3.1 (31.43) 2.97
(Loss)/earnings per share - diluted 3.1 (31.43) 1.70
--------------------------------------- ----- ----------- -----------
All results arise from continuing operations.
Group Balance Sheet
Notes 31 Dec 2020 31 Dec 2019
$'000 $'000
Non-current assets
Intangible exploration and evaluation
assets 2.4 55,390 75,874
Oil and gas assets 2.3 208,027 796,155
Other non-current assets 2,605 3,080
Deferred tax assets 78 54,311
Liquid investments 4.1 22,811 -
Cash and cash equivalents 4.1 - 3,065
-------------------------------------- ----- ----------- -----------
288,911 932,485
-------------------------------------- ----- ----------- -----------
Current assets
Inventory 2.2 11,285 9,945
Trade and other receivables 14,524 50,435
Cash and cash equivalents 4.1 143,703 168,369
-------------------------------------- ----- ----------- -----------
169,512 228,749
-------------------------------------- ----- ----------- -----------
Total assets 458,423 1,161,234
-------------------------------------- ----- ----------- -----------
Current liabilities
Trade and other payables (16,356) (72,369)
Lease liabilities 5.2 (18,479) (9,501)
Decommissioning provisions (15,466) (12,484)
-------------------------------------- ----- ----------- -----------
(50,301) (94,354)
-------------------------------------- ----- ----------- -----------
Non-current liabilities
Lease liabilities 5.2 (78,842) (89,685)
Convertible Bond liability 5.1 (216,034) (206,604)
Convertible Bond embedded derivative 5.1 (885) (36,316)
Decommissioning provisions (45,675) (43,190)
-------------------------------------- ----- ----------- -----------
(341,436) (375,795)
-------------------------------------- ----- ----------- -----------
Total liabilities (391,737) (470,149)
-------------------------------------- ----- ----------- -----------
Net assets 66,686 691,085
-------------------------------------- ----- ----------- -----------
Equity
Share capital 2,885 2,883
Share premium 822,458 821,910
Share option reserve 21,443 20,828
Own shares reserve (923) (684)
Foreign exchange reserve (90,828) (90,828)
Accumulated deficit (688,349) (63,024)
-------------------------------------- ----- ----------- -----------
Total equity 66,686 691,085
-------------------------------------- ----- ----------- -----------
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 2019 2,843 813,681 24,067 (380) (90,828) (121,699) 627,684
Profit for the period - - - - - 58,675 58,675
New shares issued
under warrants and
rights 39 7,743 - - - - 7,782
New shares issued
under employee share
schemes 1 486 - (393) - - 94
Share-based payments - - (3,239) 89 - - (3,150)
---------------------- -------- ------- ------- ---------- -------- ----------- ---------
At 31 December 2019 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
---------------------- -------- ------- ------- ---------- -------- ----------- ---------
Group Cash Flow Statement
Year ended Year ended
Notes 31 Dec 2020 31 Dec 2019
$'000 $'000
Cash flows from operating activities
Operating loss (571,059) (15,038)
Adjustments for:
Depreciation of property, plant
and equipment 2.3 97,136 63,161
Impairment of oil and gas assets 2.3 519,152 -
Impairment of intangible exploration
and evaluation assets
and exploration expense written
off 2.4 47,945 66,468
Share-based payment charge/(credit) 821 (3,150)
Purchase of derivative financial
instruments (3,420) -
Decommissioning spend (2,108) (12)
-------------------------------------------- ----- ----------- -----------
Operating cash flow before working
capital movements 88,467 111,429
Movement in receivables 159 (2,559)
Movement in payables (10,352) 8,912
Movement in crude oil, fuel and
chemicals inventories 2.2 1,946 (5,613)
Net cash inflow from operating activities 80,220 112,169
-------------------------------------------- ----- ----------- -----------
Cash flows from investing activities
Interest received 1,227 1,438
(Increase)/decrease in liquid investments (22,811) 21,668
Expenditure on oil and gas assets (23,396) (52,878)
Expenditure on other fixed assets (69) (289)
Expenditure on intangible exploration
and evaluation assets (35,269) (2,265)
Movement in spares and supplies inventories 2.2 (3,286) 239
Tax refund relating to R&D expenditure 6.1 - 6,235
-------------------------------------------- ----- ----------- -----------
Net cash used in investing activities (83,604) (25,852)
-------------------------------------------- ----- ----------- -----------
Cash flows from financing activities
Convertible Bond interest paid 5.1 (17,250) (17,250)
Lease repayments 5.2 (9,658) (5,556)
Interest and other finance charges
paid (15) (1,539)
New shares issued under warrants
and rights - 7,782
New shares issued under employee
share schemes 105 94
-------------------------------------------- ----- ----------- -----------
Net cash used in financing activities (26,818) (16,469)
-------------------------------------------- ----- ----------- -----------
(Decrease)/increase in cash and cash
equivalents (30,202) 69,848
-------------------------------------------- ----- ----------- -----------
Cash and cash equivalents at beginning
of year 4.1 171,434 101,831
Net (decrease)/increase in cash and
cash equivalents (30,202) 69,848
Effects of foreign exchange rate
changes 2,471 (245)
-------------------------------------------- ----- ----------- -----------
Cash and cash equivalents at end
of year 4.1 143,703 171,434
-------------------------------------------- ----- ----------- -----------
Notes
Section 1: General information
1.1 Basis of preparation
The consolidated Financial Statements of Hurricane Energy plc
for the year ended 31 December 2020 were authorised for issue by
the directors on 24 May 2021. 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.
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:
-- Amendments to References to Conceptual Framework in IFRS Standards;
-- Amendments to IFRS 3 - 'Definition of a Business'; and
-- Interest Rate Benchmark Reform (Amendments to IFRS 9, IAS 39 and IFRS 7)
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 2020, 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:
-- Amendments to IFRS 9, IAS 39, IFRS 7, IFRS 4 and IFRS 16 -
Interest Rate Benchmark Reform (effective from 1 January 2021);
-- Annual Improvements to IFRS Standards 2018-2020 Cycle (effective from 1 January 2022);
-- Amendments to IFRS 3 - Reference to Conceptual Framework (effective from 1 January 2022); and
-- Amendments to IAS 16 - Proceeds before Intended Use (effective from 1 January 2022).
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 2020 or 2019, but is derived from those accounts. A
copy of the statutory accounts for 2019 has been delivered to the
Registrar of Companies and those for 2020 will be delivered
following the Company's annual general meeting. The auditor has
reported on the 2020 accounts; their audit report was unqualified,
but did draw attention to a material uncertainty that exists which
may cast significant doubt on the Group's ability to continue as a
going concern. Further information relating to the going concern
assumption, including details in respect of the material
uncertainty, is provided in the 'Going Concern' section above and
in note 1.3 below.
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 presumption of going concern is made on the assumption that
the proposed financial restructuring of the Group's existing
Convertible Bonds is successfully implemented (see the 'Going
Concern' section above and note 7.3 below). Should the proposed
financial restructuring not go ahead, the Group is likely to be
unable to repay the principal of $230 million due on the
Convertible Bonds on maturity in July 2022.
As implementation of the proposed financial restructuring is
dependent on all required court and regulatory approval processes
being complete and the required percentage of the Group's
Bondholders by value having voted in favour, a material uncertainty
exists that may cast significant doubt as to the presumption of the
Group's ability to continue as a going concern.
1.4 Significant events and changes in the period
In September 2020, following the initial conclusions of its
technical review, the Group announced a significant reduction to
its unaudited best estimates of Reserves and Contingent Resources
from the Lancaster field. These estimates were further revised and
refined in an updated CPR, announced in April 2021.
In the first half of 2020, oil prices declined sharply due to
supply and demand factors, which included the impact of the
COVID-19 pandemic and increases in Saudi Arabian production, with
Dated Brent falling from a high of US$69/bbl in early January to a
low of US$13/bbl in April, before stabilising to the US$40-$45/bbl
range for most of the remainder of the year. As a result, average
realised oil price per barrel was significantly lower than 2019
(note 2.1), which in turn has led to pressure on the Group's
liquidity and capital resources.
The impact of these events and changes in estimates gave rise to
an impairment charge against oil and gas assets of $519.2 million
(note 2.3), an impairment charge against intangible exploration and
evaluation assets of $35.4 million (note 2.4) and a write-off of
deferred tax assets of $54.2 million (note 6.1).
For further discussion about the Group's performance and
financial position, see the Chief Executive Officer's Review and
Chief Financial Officer's Review above.
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
2020 2019
$'000 $'000
Oil sales 180,083 170,283
Revenue from contracts with customers 180,083 170,283
-------------------------------------- ---------- ----------
Cargoes sold 12 7
Sales volumes (thousand bbl) 5,112 2,874
Average sales price realised ($/bbl) $35.2/bbl $59.3/bbl
2.2 Cost of sales and inventory
Cost of sales:
Year ended Year ended
31 Dec 31 Dec
2020 2019
Note $'000 $'000
Operating costs 65,107 44,915
Depreciation of oil and gas assets - owned 2.3 84,756 54,406
Depreciation of oil and gas assets - leased 2.3 11,828 8,210
Movement in crude oil inventory 1,733 (4,424)
Variable lease payments 5.2 16,392 15,346
-------------------------------------------- ---- ---------- ----------
179,816 118,453
-------------------------------------------- ---- ---------- ----------
Inventory:
31 Dec 2020 31 Dec 2019
$'000 $'000
Crude oil 2,691 4,424
Fuel and chemicals 1,336 1,549
Spares and supplies 7,258 3,972
-------------------- ----------- -----------
11,285 9,945
-------------------- ----------- -----------
The amount of crude oil inventory recognised as an expense in
the year was $155.2 million (2019: $93.5 million).
2.3 Oil and gas assets
Leased Owned Total
Note $'000 $'000 $'000
Cost
At 1 January 2019 - 727,816 727,816
Additions 96,361 26,189 122,550
Changes to decommissioning estimates 4,986 3,419 8,405
At 31 December 2019 101,347 757,424 858,771
Additions - 23,652 23,652
Changes to decommissioning estimates 474 3,482 3,956
At 31 December 2020 101,821 784,558 886,379
--------------------------------------------- -------- --------- ---------
Depreciation and impairment
At 1 January 2019 - - -
Depreciation charge for the year (8,210) (54,406) (62,616)
At 31 December 2019 (8,210) (54,406) (62,616)
Depreciation charge for the year (11,828) (84,756) (96,584)
Provision for impairment 2.3.1 (60,166) (458,986) (519,152)
At 31 December 2020 (80,204) (598,148) (678,352)
--------------------------------------------- -------- --------- ---------
Carrying amount at 31 December 2019 93,137 703,018 796,155
--------------------------------------------- -------- --------- ---------
Carrying amount at 31 December 2020 21,617 186,410 208,027
--------------------------------------------- -------- --------- ---------
Included within the cost of owned oil and gas assets is $42.8
million of capitalised borrowing costs (31 December 2019: $42.8
million), and $94.7 million (31 December 2019: $92.1 million) of
assets not currently subject to depreciation (as they relate to
non-producing parts of the Lancaster field).
Oil and gas assets held under leases comprise solely the Aoka
Mizu FPSO bareboat charter, which commenced in May 2019 (see note
5.2).
The total amount of depreciation charged to oil and gas assets
and other fixed assets was $97.1 million (2019: $63.2 million).
2.3.1 Impairment of oil and gas assets
An impairment charge of $519.2 million was recognised against
oil and gas assets in the period, allocated pro-rata to owned and
leased assets based on their respective carrying values
pre-impairment.
The triggers for the impairment test were the downward revision
of estimated Reserves from Lancaster, the decline in oil prices
across the first half of 2020 and the market capitalisation of the
Company falling below its consolidated net assets. The recoverable
amount was determined based on management's best estimate of value
in use, using key assumptions, judgements and estimates as outlined
below, and taking into account the status of the Group's proposed
financial restructuring (see note 7.3) and the potential investment
cases under consideration.
The estimate of value in use was made using the expected cash
flow approach. Under this approach, the directors considered four
scenarios and assigned a probability weighting to each in order to
arrive at a risk-adjusted probability cash flow projection. The
four scenarios considered, and the percentage probability assigned
to each by management for the purposes of the expected cash flow
approach, were:
-- Wind-down scenario (10%) - whereby the proposed financial
restructuring does not complete, and there is a controlled
wind-down of production at the Lancaster field, ceasing in June
2022 (at the end of the initial charter term of the Aoka Mizu
FPSO);
-- No further activity (NFA) scenario (50%) - whereby there is
no further investment in the Lancaster field, with operations
winding down when production becomes uneconomic;
-- 'P8 2022' scenario (30%) - whereby an investment case to
drill a side-track of the existing 205/21a-7z well is sanctioned,
and drilled in spring 2022; and
-- 'P8 + WI 2023' scenario (10%) - whereby an investment case to
drill a water injector well is sanctioned (following completion of
the 'P8 2022' case) and drilled in summer 2023.
Under the terms of the proposed financial restructuring, the
latter three scenarios are predicated, inter alia, on the support
of Bondholders and achieving consent from the regulator to permit
production with flowing bottom hole pressure up to 300 psi below
bubble point. The scenarios also assume renegotiation of some terms
of the Aoka Mizu FPSO charter which would mitigate the impact of
the early termination fee that would otherwise become payable upon
cessation of production outside of contractual option periods.
These conditions have been taken into account when assigning the
likelihood of outcomes of each scenario.
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 profiles and operating performance primarily based
on internal estimates and reservoir simulation models, as these are
believed to provide the most accurate forecast of likely future
activities. (The production profiles modelled incorporated
different oil price and technical assumptions to those included in
the ERCE CPR, but were within the ranges of Reserves and Contingent
Resources estimated by ERCE);
-- the estimated capital cost of a side-track of the 205/21a-7z
well to commence production in summer 2022 (both with and without
drilling an additional well for the purposes of water injection),
based, where possible, on quotes and contracts with key suppliers
and contractors;
-- subsequent forecast increases in production performance due
to the additional volumes (and, under a water injector scenario,
additional pressure support) over and above estimated production in
a 'no further activity' case;
-- Dated Brent oil price assumptions (in real terms) of $52/bbl
average for 2021, rising to $57/bbl in 2022, $58/bbl in 2023 and
$57/bbl in 2024 and thereafter (being management's best estimate of
future oil prices as at 31 December 2020, as required by IAS
36);
-- operating cost assumptions based on latest budgets, contracts
and information from key suppliers; and
-- a pre-tax real discount rate of 9.4%.
The sensitivity of changes to some of these key estimates and
assumptions which have a material impact are estimated as
follows:
Decrease/(increase) to
impairment charge
$'000
--------------------------------- -----------------------
Oil price assumption:
$5/bbl increase to price curve 44,277
$5/bbl decrease to price curve (44,292)
Forecast production rates:
10% increase 44,802
10% decrease (44,503)
--------------------------------- -----------------------
The sensitivities disclosed are considered in isolation and a
result of changing only one variable, and do not take into account
any change to the likelihood of a potential scenario occurring as a
result of changes to those assumptions.
A $5/bbl increase or decrease to the forecast oil price are
considered to be reasonably possible based on oil price volatility,
and a 10% increase or decrease to forecast production rates are
considered to be reasonably possible based on experienced uptime
and production levels.
The impact of assuming the Aoka Mizu FPSO charter continues on
its current terms (and thus crystallising an early termination fee
in some scenarios) would be to increase the impairment charge by
$13.3 million.
The sensitivity of the impairment charge from using an
individual scenario instead of the expected cash flow approach is
as follows:
(Increase)/decrease to
impairment charge
$'000
--------------------- -----------------------
Wind-down (106,836)
No further activity (10,133)
P8 2022 20,155
P8 + WI 2023 97,037
--------------------- -----------------------
2.4 Intangible exploration and evaluation assets
Year ended Year ended
31 Dec 2020 31 Dec 2019
Note $'000 $'000
At 1 January 75,874 131,526
Additions 25,623 6,619
Exploration expenditure written off 2.4.1 (12,079) (66,468)
Provision for impairment 2.4.1 (35,397) -
Changes to decommissioning estimates 1,369 4,197
---------------------------------------------- ----------- -----------
At 31 December 55,390 75,874
---------------------------------------------- ----------- -----------
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 South),
Warwick (licence P2294) and Halifax (licence P2308).
With effect from September 2020, the P2294 licence that holds
the Warwick assets was extended into its second term, which expires
in August 2023. In November 2020, the P2308 licence which holds the
Halifax assets was also extended into its second term, which
expires in November 2024.
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.
$12.1 million of exploration and evaluation expenditure was
written off in the year, comprising the Group's share of standby
costs for the Paul B Loyd Jr rig, which was not used for any
drilling campaigns during 2020 following the OGA granting an
extension to the licence commitments on the Lincoln field in light
of the COVID-19 pandemic. See the Chief Executive Officer's Review
and Chief Financial Officer's Review above for further details.
A further $0.5 million of exploration expense was written off in
the year relating to changes in decommissioning estimates for the
Whirlwind well (which was fully written-off in December 2019).
Following the conclusion of the group's technical review and
finalisation of the 2021 CPR, provision for impairment of $35.4
million has been recognised in the year, being the full carrying
amount of exploration and evaluation expenditure attributable to
the Halifax licence, as the revised estimates do 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.
Although the 2021 CPR estimated a reduction in Contingent
Resources attributable to the Lincoln subarea (as compared to the
December 2017 RPS Energy West of Shetland CPR) the directors have
concluded that no impairment to exploration and evaluation assets
is necessary at this time as economic analysis shows the potential
for its carrying amount to be recovered in full through successful
development in conjunction with the Warwick area. However, any
appraisal and development activity would involve a significant
financial commitment for the Group (and its joint operation
partner); and, under the terms of the proposed financial
restructuring, the Group would need to seek approval from
Bondholders in order to proceed with significant capital
expenditure on GWA (including the licence obligation to drill a
commitment well on the Lincoln subarea). The directors would also
consider their ability to realise value from the licences via sale
or farm-out transaction, subject to regulatory, Bondholder and
joint operation partner approval. It is a condition of the licence
for the Lincoln subarea that, if the Lincoln commitment well is not
drilled, the Lincoln subarea be relinquished by the joint venture
partners. In the event of a relinquishment, the carrying value of
exploration and evaluation assets relating to Lincoln would be
written off in full.
On 12 December 2019, the Group executed a deed of variation with
the OGA, granting a five-year extension to its P1368 licence (which
covered the Lincoln, Lancaster, Whirlwind and Strathmore subareas)
to December 2024. As part of this extension agreed with the OGA,
the Whirlwind and Strathmore subareas were relinquished resulting
in a write-off of $66.5 million for the year ended 31 December
2019, all relating to Whirlwind. The carrying value of intangible
exploration and evaluation assets relating to Strathmore was
previously fully impaired in 2017.
Section 3: Income Statement
3.1 Earnings per share
Year ended Year ended
31 Dec 2020 31 Dec 2019
$'000 $'000
(Loss)/profit attributable to holders of Ordinary Shares in the Company used in
calculating basic earnings per share (being (loss)/profit
after tax) (625,325) 58,675
Add back impact of:
Convertible Bond - interest expense not capitalised - 16,417
Convertible Bond - depreciation of interest capitalised in the year - 738
Convertible Bond - fair value gain - (34,691)
-------------------------------------------------------------------------------------- ------------- -------------
(Loss)/profit attributable to holders of Ordinary Shares in the Company used in
calculating diluted earnings per share (625,325) 41,139
-------------------------------------------------------------------------------------- ------------- -------------
Number Number
-------------------------------------------------------------------------------------- ------------- -------------
Weighted average number of Ordinary Shares used in calculating basic earnings per
share 1,989,607,524 1,978,513,120
Potential dilutive effect of:
Convertible Bond - 442,307,692
-------------------------------------------------------------------------------------- ------------- -------------
Weighted average number of Ordinary Shares and potential Ordinary Shares used in
calculating diluted earnings per share 1,989,607,524 2,420,820,812
-------------------------------------------------------------------------------------- ------------- -------------
Cents Cents
-------------------------------------------------------------------------------------- ------------- -------------
Basic (loss)/earnings per share (31.43) 2.97
Diluted (loss)/earnings per share (31.43) 1.70
-------------------------------------------------------------------------------------- ------------- -------------
The effect of warrants, share awards and options outstanding in
2020 was antidilutive as the Group incurred a loss. The impact of
the conversion feature included within the Convertible Bond in 2020
was also antidilutive for the same reason.
The impact of the VCP and PSP awards was antidilutive in 2019
because market-based conditions for both schemes had not been met
at the balance sheet date, and the impact of other employee share
options was antidilutive in 2019 as the adjusted exercise prices
were in excess of the average market price of Ordinary Shares
during the relevant periods.
Section 4: Cash
4.1 Cash and cash equivalents and liquid investments
31 Dec 2020 31 Dec 2019
------------------------------------ ------------------------------------
Restricted Unrestricted Total Restricted Unrestricted Total
$'000 $'000 $'000 $'000 $'000 $'000
--------------------------------- ----------- ------------- -------- ----------- ------------- --------
Current cash and cash
equivalents 28,792 114,911 143,703 11,778 156,591 168,369
Non-current cash and
equivalents - - - 3,065 - 3,065
--------------------------------- ----------- ------------- -------- ----------- ------------- --------
Cash and cash equivalents
(per cash flow statement) 28,792 114,911 143,703 14,843 156,591 171,434
Liquid investments 22,811 - 22,811 - - -
--------------------------------- ----------- ------------- -------- ----------- ------------- --------
Total cash and cash equivalents
and liquid investments 51,603 114,911 166,514 14,843 156,591 171,434
--------------------------------- ----------- ------------- -------- ----------- ------------- --------
The carrying amounts of cash and cash equivalents and liquid
investments are considered to be materially equivalent to their
fair values.
The movement in restricted and unrestricted cash, cash
equivalents and liquid investments is as follows:
Year ended 31 Dec Year ended 31 Dec
2020 2019
------------------------------------- -------------------------------------
Restricted Unrestricted Total Restricted Unrestricted Total
$'000 $'000 $'000 $'000 $'000 $'000
--------------------------- ----------- ------------- --------- ----------- ------------- ---------
At 1 January 14,843 156,591 171,434 40,162 83,000 123,162
Operating cash flows - - 78,272 78,272 - 112,169 112,169
Change in Lancaster EPS
decommissioning security
arrangements 22,811 (22,811) - (21,668) 21,668 -
Capital expenditure and
other investing cash
flows - (58,845) (58,845) (2,520) (45,000) (47,520)
Financing cash flows - (26,818) (26,818) (12,938) (3,531) (16,469)
Movement in FPSO early
termination reserve 14,807 (14,807) - 11,735 (11,735) -
Net release of other
restricted funds (892) 892 - (363) 363 -
Foreign exchange rate
changes 34 2,437 2,471 435 (343) 92
--------------------------- ----------- ------------- --------- ----------- ------------- ---------
At 31 December 51,603 114,911 166,514 14,843 156,591 171,434
--------------------------- ----------- ------------- --------- ----------- ------------- ---------
Included within restricted cash and cash equivalents is $26.5
million (2019: $11.7 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. The remaining $2.3 million of restricted cash
comprises decommissioning security in place for the suspended
Lancaster 205/21a-4z well.
The $22.8 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 held in trust (classified within
restricted liquid investments) until February 2019 when it was
transferred into a decommissioning bond, and subsequently released
to unrestricted cash during 2019 as the bond conditions were
satisfied. Following the downwards revision of Reserves 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 April
2021, the regulator gave notice of its intention to formally
request that an additional GBP11.2 million relating to this
decommissioning security be lodged by the Group - see note 7.2.
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%.
Subsequent to the balance sheet date, the Group entered into a
lock-up agreement with certain of its Bondholders in order to enter
into a proposed financial restructuring which will, if approved,
significantly amend the terms of the existing Convertible Bonds;
see note 7.3 for further details.
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
2019 198,364 71,007 269,371
Cash interest paid (17,250) - (17,250)
Fair value gains - (34,691) (34,691)
Interest charged 25,490 - 25,490
------------------------------- -------------- -------------------- --------
Carrying value at 31 December
2019 206,604 36,316 242,920
Cash interest paid (17,250) - (17,250)
Fair value gains - (35,431) (35,431)
Interest charged 26,680 - 26,680
Carrying value at 31 December
2020 216,034 885 216,919
------------------------------- -------------- -------------------- --------
Fair value at 31 December
2019 235,852 36,316 272,168
------------------------------- -------------- -------------------- --------
Fair value at 31 December
2020 102,615 885 103,500
------------------------------- -------------- -------------------- --------
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 2020. 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 2020 used a share
price volatility assumption of 118.2% (2019: n/a) and the price of
one Hurricane Energy plc Ordinary Share as at the balance sheet
date of GBP0.025 (2019: n/a). The sensitivity of a reasonably
possible increase or decrease of those inputs to the Group's profit
before tax for the period ended 31 December 2020 is summarised
below, assuming all other variables were held constant:
(Loss)/
gain
$'000
------------------------------------ ---------
Share price volatility assumption:
20% increase (989)
20% decrease 605
Share price at balance sheet date:
GBP0.05 increase (7,656)
GBP0.02 decrease 871
------------------------------------ ---------
Should the proposed financial restructuring be implemented, the
existing conversion rights attached to the Convertible Bonds will
be amended and the value of the existing embedded derivative
reduced to nil at the effective implementation date.
The valuation as at 31 December 2019 was derived by deducting
the estimated fair value of the debt component (using an equivalent
bond yield of 7.2% estimated from average adjusted bond yields from
similar oil and gas E&P companies) from the quoted market value
of the Convertible Bond. The valuation methodology has changed due
to the previous methodology not being appropriate where the market
value of the Convertible Bond is below its par value.
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 2020 31 Dec 2019
$'000 $'000
At 1 January 99,186 3,323
New leases- - 96,361
Cash payments of principal and interest (9,658) (5,556)
Interest charged 7,702 4,972
Foreign exchange movements 91 86
---------------------------------------- ----------- -----------
At 31 December 97,321 99,186
---------------------------------------- ----------- -----------
Of which:
Current 18,479 9,501
Non-current 78,842 89,685
---------------------------------------- ----------- -----------
97,321 99,186
---------------------------------------- ----------- -----------
In May 2019, the Group's bareboat charter of the Aoka Mizu FPSO
commenced. Under the contract, 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. These variable payments are excluded
from the measurement of the lease liability, and instead are
recognised as an expense in the period in which sales are made.
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, which are classified within restricted cash (see note
4.1).
The charges to the income statement in respect of leases during
the year included the following:
Year ended Year ended
31 Dec 2020 31 Dec 2019
$'000 $'000
Depreciation charge of right-of-use assets:
Oil and gas assets (included within cost of sales) 11,828 8,210
Other fixed assets (included within general and
administrative expenses) 340 337
---------------------------------------------------- ----------- -----------
12,168 8,547
---------------------------------------------------- ----------- -----------
Lease interest (included within finance costs) 7,702 4,972
Variable lease payments (included within cost of
sales) 16,392 15,346
The total gross cash outflow for leases for the year was $46.9
million, of which $10.1 million was recovered from the Group's
joint operation partner.
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). The expense
relating to low-value leases and other short-term leases recognised
in the income statement was not material.
Section 6: Tax
6.1 Tax charge for the year
Year ended Year ended
31 Dec 2020 31 Dec 2019
$'000 $'000
UK corporation tax
Current tax - prior years - 6,259
------------------------------------------------- ----------- -----------
Total current tax - 6,259
------------------------------------------------- ----------- -----------
Deferred tax - current year (44,501) 90,226
Deferred tax - prior year (9,732) -
Effect of changes in tax rates - (35,998)
------------------------------------------------- ----------- -----------
Total deferred tax (54,233) 54,228
------------------------------------------------- ----------- -----------
Tax (charge)/credit per income statement (54,233) 60,487
------------------------------------------------- ----------- -----------
Loss on ordinary activities before tax (571,092) (1,812)
------------------------------------------------- ----------- -----------
Loss on ordinary activities multiplied by
standard combined rate of corporation tax
in the UK applicable to oil and gas companies
of 40% (2019: 40%) 228,437 725
Effects of:
R&D tax credit - 6,259
Expenses not deductible for tax purposes (4,656) (1,724)
Income not chargeable for tax purposes 15,138 4,211
Items taxed at rates other than the standard
rate of 40% (24) (278,873)
Ring-fence expenditure supplement 22,769 22,057
Recognition of deferred tax not previously
recognised - 307,832
Prior period deferred tax (9,732) -
Losses not recognised (306,165) -
------------------------------------------------- ----------- -----------
Total tax (charge)/credit for the year (54,233) 60,487
------------------------------------------------- ----------- -----------
Income not chargeable for tax purposes primarily relates to the
tax effect of the fair value gain on the Convertible Bond embedded
derivative (see note 5.1).
In 2018 the Group made a claim under the SME research and
development tax relief scheme in respect of the 2016 and 2017
financial years and has surrendered the resulting losses for a
payable tax credit. $6.2 million was received in respect of this in
April 2019, classified within cash flows from investing activities
as the original expenditure giving rise to the credit was reported
within investing activities.
Section 7: Subsequent events
7.1 CPR
In April 2021, an updated CPR on the Group's assets was
published, which gave an updated estimate of the hydrocarbon
Reserves and Contingent Resources as at 31 December 2020, thus
providing additional evidence of conditions that existed as at the
balance sheet date. The results of this CPR have therefore been
reflected within these Financial Statements, by taking into account
these estimates within the impairment test for oil and gas assets
(note 2.3.1) and giving rise to a full impairment of exploration
and evaluation expenditure attributable to the Halifax licence, as
the CPR did not attribute any Reserves or Contingent Resources to
that area (note 2.4.1).
7.2 Decommissioning security
In April 2021, the Offshore Petroleum Regulator for Environment
and Decommissioning gave notice of its intention to formally
request that the Company increase the amount of decommissioning
security for the Lancaster field by GBP11.2 million ($15.7
million), in order for the security to be in place on a pre-tax
basis. The Group therefore expects to place this amount into
restricted funds shortly after the receipt of the formal request,
expected to be in June 2021.
7.3 Proposed financial restructuring
On 30 April 2021, the Group entered into a lock-up agreement
(LUA) with an ad hoc group of Bondholders (the Ad Hoc Committee;
representing approximately 69% by value of the Group's Convertible
Bonds outstanding), pursuant to a proposed financial restructuring
plan (the proposed financial restructuring). As at the date of this
report, in excess of 75% by value of Bondholders had signed or
acceded to the LUA.
As a result of entering into the LUA, an Event of Default has
occurred pursuant to the terms and conditions of the Convertible
Bonds. As the Company's ability to repay the Convertible Bonds at
maturity is dependent on the implementation of the proposed
financial restructuring, a Potential Event of Default (as defined
in the Trust Deed) has also arisen. The Group has provided notice
of the Event of Default and Potential Event of Default to the
Trustee. Noting that in excess of 75% by value of Bondholders had
signed or acceded to the LUA, and the LUA contains certain
forbearances and an agreement not to take or encourage any action
which would, or would reasonably be expected to, delay, frustrate,
impede or prevent the implementation or consummation of the
proposed financial restructuring, the Group does not expect the
Bondholders to take action in relation to the Event of Default
while the LUA is in effect.
The main components of the proposed financial restructuring
are:
-- a debt for equity conversion, which entails (amongst other things):
o a release of approximately $50 million of the outstanding
principal amount under the Convertible Bonds in consideration for
the allotment and issue of Ordinary Shares in the Company
representing in aggregate approximately 95% of the total number of
fully diluted issued shares of the Company immediately following
the effective date of the proposed financial restructuring; and
o various amendments to the terms and conditions of the
remaining $180 million of Convertible Bonds and associated
documents in accordance with the revised terms detailed below,
including the provision of security and subsidiary guarantees;
and
-- a revised business strategy for the Group which contemplates:
(i) an extended production case (which would see production from
the Lancaster 205/21a-6 well continue until its economic limit is
reached); and (ii) subject to approval by the Bondholders, an
opportunity for subsequent investments in the Lancaster field
(which, at the time of entering into the LUA, envisaged the
drilling of a side-track of the existing 205/21a-7z well in 2022,
potentially followed by the drilling of a water injector well in
2023).
Amended Bonds
If implemented, the proposed financial restructuring would
result in the release of $50 million of the outstanding principal
amount of the Convertible Bonds, such that the amount due on
maturity of the Amended Bonds will be up to $180 million. Under the
terms of the Amended Bonds, the cash coupon on the Convertible
Bonds would be increased from 7.5% to 9.4% per annum, an additional
payment-in-kind (PIK) interest at a rate of 5% per annum would be
introduced and the maturity date would be extended to December
2024. A mandatory prepayment provision, whereby excess cash flow
generated by the Group will be applied in mandatory redemption of
the Amended Bonds on each interest payment date, and various
general, restrictive and information covenants will be added to the
Amended Bonds, with a key financial covenant being that the
liquidity of the Group (being consolidated cash and cash
equivalents of the Group that are not subject to any security
interests or held under escrow arrangements) must be no less than
$45 million until cessation of production from the Lancaster
field.
If implemented, the proposed financial restructuring would
result in the removal of the existing conversion options of the
Convertible Bonds, and the introduction of a new maturity
conversion option exercisable by the Company after December 2024
provided that, amongst other things, all production at Lancaster
has ceased permanently and all remaining free cash of the Group has
been applied towards outstanding liabilities under the Amended
Bonds, all of which is intended to ensure continuing solvency for
the Company. This conversion option would, in the circumstances
outlined above, allow the Company to convert any remaining
outstanding Amended Bonds into Ordinary Shares of the Company. The
Amended Bonds will be secured by certain assets, undertakings,
property, interests and rights of the Company (Hurricane Energy
plc), Hurricane Holdings Limited and Hurricane GLA Limited (both
being subsidiaries of the Company), and additional guarantees will
be granted by certain Company subsidiaries.
Implementation of the proposed financial restructuring
To implement the proposed financial restructuring, it is
proposed that an English Restructuring Plan under Part 26A of the
Companies Act 2006 will be utilised, which will require the support
of 75% (by value) of the Bondholders voting at a meeting convened
by the court. The convening hearing of the court was held on 21 May
2021. The Bondholder plan meeting convened by the court has been
scheduled for 11 June 2021. The court has also convened a plan
meeting of shareholders, at which shareholders will be asked to
vote on the proposed financial restructuring. The shareholder plan
meeting will take place on 11 June 2021 following the Bondholder
plan meeting. The outcome of those plan meetings will be published
by the Company shortly after the conclusion of the meetings.
Subject to the outcome of the Bondholder plan meeting, the
Company expects the sanction hearing of the court, at which the
court will be asked to sanction the proposed restructuring plan, to
commence on or around 21 June 2021. The Company will make an
announcement regarding the outcome of the sanction hearing as soon
as possible after that hearing concludes.
Unless waived by a 75% majority in value of the Bondholders who
are party to or have acceded to the LUA, the implementation of the
proposed financial restructuring is conditional on, inter alia,
receiving consent from the OGA to amend the Lancaster Field
Development Plan to permit production with flowing bottom hole
pressure up to 300 psi below the bubble point of the fluid (1,605
psia at 1,240 metres TVDSS).
Failure to implement the proposed financial restructuring
In the event that the proposed financial restructuring (a) is
not approved by Bondholders and shareholders at the Bondholder plan
meeting and shareholder plan meeting, respectively; or (b) is
approved by Bondholders but not by shareholders, and is not
sanctioned by the Court; or (c) is approved by Bondholders and
shareholders, but is not sanctioned by the Court, the proposed
financial restructuring will not be capable of being implemented.
In that scenario, given the circumstances, there would be
insufficient time to seek, and it is most unlikely that the Company
would be able to obtain, the requisite level of Bondholder consent
to implement any alternative transaction outside of a controlled
wind-down of the Group's operations followed by an insolvent
liquidation of the Company and its subsidiaries.
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.
--------------------- --------------------------------------------------------------
AIM The AIM market of the London Stock Exchange
--------------------- --------------------------------------------------------------
Amended Bond(s) $180 million of 14.4% convertible bonds due December
2024; being the Convertible Bond(s) amended and restated
following completion of the proposed financial restructuring
--------------------- --------------------------------------------------------------
Aoka Mizu Aoka Mizu FPSO
--------------------- --------------------------------------------------------------
bbl Barrel
--------------------- --------------------------------------------------------------
Bluewater Bluewater Energy Services and affiliates
--------------------- --------------------------------------------------------------
Bondholder A holder of one or more the Company's Convertible Bonds
or, should the proposed financial restructuring proceed,
the Company's Amended 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
--------------------- --------------------------------------------------------------
CEO Chief Executive Officer
--------------------- --------------------------------------------------------------
CFO Chief Financial Officer
--------------------- --------------------------------------------------------------
Company Hurricane Energy plc and/or its subsidiaries
--------------------- --------------------------------------------------------------
coned The production of fluids as a result of drawdown pressures
during production overcoming the natural buoyancy forces
that segregate oil, water and gas
--------------------- --------------------------------------------------------------
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 ongoing to justify commercial development in the foreseeable
Pending future.
--------------------- --------------------------------------------------------------
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 $230million of 7.5% convertible bonds issued by the
Bond(s) Company in July 2017
--------------------- --------------------------------------------------------------
COO Chief Operations Officer
--------------------- --------------------------------------------------------------
COVID-19 Coronavirus
--------------------- --------------------------------------------------------------
CPR Competent Persons Report
--------------------- --------------------------------------------------------------
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
--------------------- --------------------------------------------------------------
FVTPL Fair value through profit and loss
--------------------- --------------------------------------------------------------
G&A General and Administrative costs
--------------------- --------------------------------------------------------------
GBP British Pounds Sterling
--------------------- --------------------------------------------------------------
GHG Greenhouse Gas (i.e. Carbon Dioxide, Methane, Nitrous
Oxide, Chlorofluorocarbon-12, Hydrofluorocarbon-23,
Sulphur Hexafluoride, Nitrogen Trifluoride)
--------------------- --------------------------------------------------------------
GLA Greater Lancaster Area, comprising the 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
--------------------- --------------------------------------------------------------
Hurricane Hurricane Energy plc, together with its subsidiaries
--------------------- --------------------------------------------------------------
IAS International Accounting Standard
--------------------- --------------------------------------------------------------
IFRS International Financial Reporting Standards
--------------------- --------------------------------------------------------------
IPO Initial Public Offering
--------------------- --------------------------------------------------------------
JV Joint venture
--------------------- --------------------------------------------------------------
LLIs Long-Lead Items
--------------------- --------------------------------------------------------------
LTIP Long term incentive plan
--------------------- --------------------------------------------------------------
LUA Lock-up agreement
--------------------- --------------------------------------------------------------
Mbbl Thousand barrels of oil
--------------------- --------------------------------------------------------------
MMbbl Million barrels of oil
--------------------- --------------------------------------------------------------
NFA case The terms of the proposed financial restructuring agreed
between Hurricane and its Bondholders requires implementation
of a no further activity case for Lancaster, based on
production from the 205/21a-6 well alone, and requires
that Hurricane executes a planned wind-down of operations
starting when production from the Lancaster field is
no longer economic.
--------------------- --------------------------------------------------------------
OGA Oil and Gas Authority
--------------------- --------------------------------------------------------------
OGUK Oil & Gas trade association for the United Kingdom
--------------------- --------------------------------------------------------------
Ordinary Shares Ordinary shares in the Company of GBP0.001 each
--------------------- --------------------------------------------------------------
OWC Oil water contact
--------------------- --------------------------------------------------------------
P&A Plug and abandon
--------------------- --------------------------------------------------------------
P8 The proposed sidetrack to be drilled from the 205/21a-7z
horizontal producer well
--------------------- --------------------------------------------------------------
PRMS Petroleum Resources Management System
--------------------- --------------------------------------------------------------
PSP Performance Share Plan
--------------------- --------------------------------------------------------------
psia Pounds per square inch (absolute) unit of pressure
--------------------- --------------------------------------------------------------
R&D Research & Development
--------------------- --------------------------------------------------------------
Regret costs Amounts that remain payable under contracts on cancellation
of a project
--------------------- --------------------------------------------------------------
Regulator Oil and Gas Authority, Department for Business Energy
and Industrial Strategy, 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
--------------------- --------------------------------------------------------------
RPS RPS Energy Consultants Ltd
--------------------- --------------------------------------------------------------
SME Small and medium sized enterprises
--------------------- --------------------------------------------------------------
SPE The Society of Petroleum Engineers
--------------------- --------------------------------------------------------------
Spirit or Spirit Spirit Energy Limited
Energy
--------------------- --------------------------------------------------------------
stb/d/psi Stock tank barrels of oil per day per pound per square
inch of drawdown
--------------------- --------------------------------------------------------------
SURF Subsea, Umbilical, Risers, Flowlines
--------------------- --------------------------------------------------------------
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
--------------------- --------------------------------------------------------------
WI Water injector
--------------------- --------------------------------------------------------------
Appendix B: Non-IFRS measures
Underlying profit before tax
Underlying profit before tax is defined as profit before tax
under IFRS, before fair value gains or losses on the Convertible
Bond embedded derivative, fair value gains or losses on unhedged
derivative financial instruments, impairment and write-offs of
intangible exploration and evaluation assets, impairment of oil and
gas assets 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 items and transactions within the income statement. These
are the volatile non-cash impact of the Convertible Bond embedded
derivative movement (the valuation of which is largely outside
management's control) and gains or losses arising from write-offs
and impairments of oil and gas and exploration and evaluation
assets, and disposals of assets or subsidiaries which do not
reflect the Group's core business. Fair value gains or losses on
derivatives not designated as hedging instruments in a hedging
relationship have been added to the items excluded from underlying
profit before tax as the Group entered into such contracts for the
first time during 2020. These fair value movements are excluded
from underlying profit before tax as movements are wholly due to
movements in oil price which is not within management's
control.
Year ended Year ended
Notes 31 Dec 2020 31 Dec 2019
$'000 $'000
Loss before tax (IFRS measure) (571,092) (1,812)
Add back:
Fair value gain on Convertible Bond
embedded derivative 5.1 (35,431) (34,691)
Fair value loss on unhedged derivative
financial instruments 3,420 -
Impairment and write-off of intangible
exploration and evaluation assets 2.4 47,945 66,468
Impairment of oil and gas assets 2.3 519,152 -
Underlying (loss)/profit before tax (36,006) 29,965
---------------------------------------- ----- ----------- -----------
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 cost 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
31 Dec 31 Dec
2020 2019
Note $'000 $'000
Cost of sales (IFRS measure) 2.2 179,816 118,453
Less:
Depreciation of oil and gas assets - owned (84,756) (54,406)
Depreciation of oil and gas assets - leased 2.3 (11,828) (8,210)
Movements in crude oil inventory (1,733) 4,424
Add: 2.3
Fixed lease payments payable on oil and
gas assets 9,150 5,761
--------------------------------------------- ---- ---------- ----------
Cash production costs 2.2 90,649 66,022
--------------------------------------------- ---- ---------- ----------
Variable lease payments (incentive tariff) (16,392) (15,346)
Cash production costs (excluding incentive
tariff) 74,257 50,676
--------------------------------------------- ---- ---------- ----------
Production volumes 5,078 kbbl 3,030 kbbl
Cash production costs per barrel $17.9/bbl $21.8/bbl
Cash production costs per barrel (excluding $14.6/bbl $16.7/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 par 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 2020 31 Dec 2019
$'000 $'000
Cash and cash equivalents (IFRS measure) 4.1 143,703 171,434
Add:
Trade and other receivables 14,524 50,435
Derivative financial instruments - -
Less:
Restricted cash and cash equivalents 4.1 (28,792) (14,843)
Prepayments (1,644) (1,066)
Trade and other payables (16,356) (72,369)
Net free cash 111,435 133,591
----------------------------------------- ---- ----------- -----------
Par value of Convertible Bond 5.1 (230,000) (230,000)
----------------------------------------- ---- ----------- -----------
Net debt (118,565) (96,409)
----------------------------------------- ---- ----------- -----------
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