TIDMHUR
RNS Number : 6811Y
Hurricane Energy PLC
11 September 2020
11 September 2020
Hurricane Energy plc
("Hurricane", the "Company", or the "Group")
Half-year Results 2020
&
Technical Update
Hurricane Energy plc, the UK based oil and gas company focused
on hydrocarbon resources in naturally fractured basement
reservoirs, provides its 2020 interim report and half-year results
for the period ended 30 June 2020. The Company also announces the
initial results from the Technical Review of its West of Shetland
assets which commenced in June 2020.
2020 Interim results summary
Technical Review
-- Since announcing a Technical Review on 8 June 2020, a
strengthened Hurricane sub-surface team has performed a
comprehensive reassessment of the Lancaster field.
-- The Lancaster field is more complex than previously thought.
Preliminary analysis suggests that rather than being primarily a
basement reservoir, Lancaster has important oil-bearing sandstones
onlapping the basement flanks, which may contain significant
volumes of oil. Further work is required in order to understand
their impact on current reservoir performance and their ultimate
potential.
-- The Lancaster oil water contact ("OWC") is now estimated to
be at 1,330 metres TVDSS, compared to the range of 1,597-1,678
metres TVDSS in the Company's 2017 Competent Person's Report ("2017
CPR"). This shallower OWC is consistent with the observed earlier
and higher water production, and more rapid reservoir pressure
decline, than was originally anticipated.
-- Reflecting these new technical interpretations, the Company's
unaudited estimate of recovery from the two existing Lancaster
Early Production System ("EPS") wells assuming no further activity
has been reduced to 16.0 MMbbls from 37.3 MMbbls. Considering oil
produced to end August 2020, remaining 2P reserves at 1 September
2020 are estimated at 9.4 MMbbls (subject to economic limit
test).
-- Consideration of near-term future activity is being focussed
on means to provide reservoir pressure support primarily by water
injection, which if successfully implemented could significantly
add to reserves, and/or targeted development of the onlapping
sandstone reservoirs.
-- Reflecting these new technical interpretations, the Company's
unaudited estimate of 2C contingent resources in the Lancaster
field has been reduced to 58 MMbbls remaining from 486 MMbbls in
the 2017 CPR.
-- The Company's estimate of the OWC in the Lincoln field is now
1,846 metres TVDSS (+/- 50 metres), compared to a range of
2,109-2,325 metres TVDSS estimated in the Company's 2017 West of
Shetland Assets CPR ("2017 WoS CPR"). Accordingly, the Company's
unaudited estimate of 2C contingent resources for the basement
alone in the Lincoln field has been reduced to 45 MMbbls gross,
compared to 565 MMbbls gross in the 2017 WoS CPR.
-- More definitive estimates of the range of reserves and
resources will be made available in an updated CPR in Q1 2021.
Operations - Greater Lancaster Area ("GLA")
-- Hurricane continues to adhere to the strict procedures in
place for UKCS offshore activity during the COVID-19 pandemic, with
negligible disruption to the Company's operations during the
period.
-- The Aoka Mizu FPSO continues to deliver excellent uptime, with an average of 99% in H1 2020.
-- Lancaster EPS production averaged 14,600 bopd for both H1
2020 and the year to date ended August 2020. Prior to the recent
scheduled shutdown, field production of c.15,000 bopd was from the
205/21a-6 well alone on natural flow, with the 205/21a-7z well
currently shut in to manage reservoir voidage and pressure
decline.
-- In light of the revised interpretation of the OWC, the area
of the P1368 Central licence outside the determined Lancaster field
area is being voluntarily relinquished and, following
relinquishment, the Company will be released of its obligation to
drill the Lancaster commitment well.
Operations - Greater Warwick Area ("GWA")
-- Interpretation of the results of the 2019 drilling programme
and ongoing pressure monitoring of the 205/26b-14 Lincoln well have
led to a significant reappraisal of the GWA licence potential.
-- The downhole gauges installed in the suspended 205/26b-14
Lincoln well are now yielding potentially important pressure data.
Two sets of data have now been retrieved and analysed, providing
valuable insight into long distance reservoir behaviour.
-- As previously announced, the OGA has agreed to extend the
deadline for the GWA licence commitment well from 31 December 2020
to 30 June 2022.
Financial results
-- Revenues of $81.9 million in H1 2020 from seven liftings of
Lancaster crude (H1 2019: $22.5 million)
-- Despite the significant volatility in oil prices during the
period, the Company generated $21.9 million (H1 2019: $6.1 million)
of operating cash flow due to low cash production costs of
$18.2/bbl (H1 2019: $24.0/bbl)
-- Loss after tax for the period of $307.7 million (H1 2019:
Loss of $21.4 million), including $238.9 million (H1 2019: $nil)
relating to the impairment of the Lancaster field and a $34 million
credit (H1 2019 : $23.5 million charge) in relation to the fair
value of the Convertible Bond.
-- Net free cash of $106.2 million at 30 June 2020 (31 December 2019: $133.6 million).
-- Net debt of $123.8 million at 30 June 2020 (31 December 2019: $96.4 million)
Non-IFRS measures. See Appendix B for definition and
reconciliation to nearest equivalent statutory IFRS measures
Outlook
-- Lancaster EPS production for September to December 2020 is
expected to average 12,000-14,000 bopd, based on production from
the 205/21a-6 well on natural flow, expected decline rates and 95%
FPSO uptime.
-- Work continues on a possible 2021 activity programme for
Lancaster, including the provision of pressure support via water
injection, improved recovery from the existing EPS wells and
evaluation of the onlapping sandstones. This planning is expected
to be finalised before the end of 2020.
-- While no drilling is anticipated on the GWA licence during
2021, Hurricane will continue to work with the GWA stakeholders on
possible pathways towards development for the Lincoln
discovery.
-- Lower oil prices and reduced production expectations will
negatively impact anticipated future cash flows, despite the
expected reduction and deferral of licence commitment well
spending. Consequently, the Company intends to engage with all key
stakeholders regarding its forward work programme, capital
allocation and financing arrangements.
Steven McTiernan, Chairman of Hurricane, commented:
"2020 is proving to be a hugely challenging year for Hurricane.
We have had to contend with not only a significant fall in oil
prices and the effects of the COVID-19 pandemic, but also poorer
than expected reservoir performance from the Lancaster EPS.
The EPS was always intended as a long-term production test to
establish the size and production characteristics of this unique
and pioneering basement play. Basement reservoirs are subject to
profound technical risks, with difficult well conditions impacting
the effectiveness of evaluation tools, creating uncertainties which
can only be resolved by observation of actual production
performance.
It is nonetheless disappointing that the Technical Review has so
far resulted in significant reductions in reserves and resources.
On a more optimistic note, initial studies suggest water injection
could partially mitigate the reserves downgrade, and onlapping
sandstones at Lancaster could represent material upside
potential.
The Board is enormously grateful to Beverley Smith for leading
the Technical Review during a period of considerable change for the
Company. We are also most fortunate that stewardship of the Company
is now passing to Antony Maris, our new Chief Executive Officer,
who has significant experience of basement reservoir developments
and will provide strong leadership to the refreshed management
team."
Antony Maris, Chief Executive Officer Designate of Hurricane,
commented:
"Through hard work and dedication, the Hurricane team developed
the Lancaster project safely, on time and on budget, and has now
successfully operated the Lancaster EPS for 16 months. This
capability is a core strength of the business, and I am delighted
to be joining this accomplished operating team.
Following the uncertainty of recent months, as the significance
of the EPS reservoir performance has become clearer, we must now
focus on extracting value from Lancaster and our other discoveries,
while optimising the use of our significant installed
infrastructure West of Shetland. In particular, the Technical
Review has identified upside within sandstone reservoirs on the
flanks of the Lancaster field, with the potential for volumes of
recoverable oil which are significant in a UKCS context.
Furthermore, together with Spirit, we are working towards
consideration of a viable development plan for the Lincoln
field.
Our near-term priority is further technical work to refine an
activity plan for Lancaster, which we expect to be finalised by the
end of this year and executed in 2021, with an overarching focus on
capital discipline. We will be engaging with all our key
stakeholders regarding our forward work programme and financing
arrangements and updating the market on these efforts in due
course."
Contacts:
Hurricane Energy plc
Antony Maris, Chief Executive Officer Designate +44 (0)1483 862
Philip Corbett, Head of Investor Relations 820
Stifel Nicolaus Europe Limited
Nominated Adviser & Joint Corporate Broker
Callum Stewart / Simon Mensley / Ashton Clanfield +44 (0)20 7710 7600
Morgan Stanley & Co. International plc
Joint Corporate Broker
Andrew Foster / Tom Perry / Alex Smart +44 (0)20 7425 8000
Vigo Communications
Public Relations
Patrick d'Ancona / Ben Simons
hurricane@vigocomms.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. Hurricane is pursuing a phased
development of Lancaster, starting with 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 targeting
sanction of an initial stage of full field development.
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
Beverley Smith, Interim Chief Executive Officer, who is a qualified
person for the purposes of the AIM Guidance Note for Mining, Oil
and Gas Companies. Ms Smith is a chartered geologist with 30 years'
experience in the oil and gas industry.
Standard
Reserves and 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.
Interim Chief Executive Officer's Review
H1 2020 marked the first anniversary of production from the
Lancaster EPS. During the period, 2.7 MMbbls of oil was produced
from the field, taking total production since field start up in May
2019 to 6.6 MMbbls. During the first half of the year, facility
uptime on the Aoka Miza averaged an impressive 99% - continuing the
recent trend of excellent FPSO availability, which is testament to
the hard work and commitment of Hurricane's operations and
development teams and our Tier 1 contractors.
Production during H1 2020 averaged 14,600 bopd. While this
represented an increase over H2 2019 levels of 13,600 bopd,
production in the first half was lower than expected, primarily due
to a shut in of the 205/21a-7z well during May 2020. This action,
combined with a consistent increase in water production from this
well in particular, led Hurricane's Board to commission a
comprehensive technical review of the Lancaster field's geological
and reservoir models. The initial conclusions of that review have
been announced today, with the results summarised below.
The COVID-19 pandemic has posed significant challenges to UKCS
oil and gas operations. In March, a crew member on the Aoka Mizu
FPSO was evacuated to the mainland and subsequently tested positive
for COVID-19. The individual made a full recovery. The pandemic has
restricted crew movements associated with UKCS upstream operations,
limiting offshore manning to essential personnel only since March.
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.
Brent oil prices fell from $60/bbl in February 2020 to below
$20/bbl in April 2020. While oil prices have recovered to their
current level of $40/bbl, the negative impact on the Company's cash
flows has resulted in a necessary pivot away from further appraisal
and development activity to enhanced capital discipline and
preserving liquidity. Low oil prices, future production levels and
the scope and timing of future activity on the West of Shetland
portfolio may impact the Company's ability to repay or refinance
its Convertible Bond debt in full without additional funding and/or
potential dilution to shareholders.
In H1 2020, the Company generated revenues of $81.9 million,
compared to $22.4 million in H1 2019 when the Lancaster EPS was
only onstream for a short period. An operating loss of $274.5
million (H1 2019: $1.2 million operating profit), was primarily
driven by a non-cash asset impairment due to lower reserves at
Lancaster and lower oil price assumptions. Overall, the Company
reported a loss after tax of $307.7 million for H1 2020 (H1 2019:
$21.2 million loss), primarily due to the operating loss described
above and a decrease in the Company's deferred tax position
following a reassessment of future taxable profits.
At 30 June 2020, the Company had net free cash of $106.2
million, resulting in net debt of $123.8 million.
Non-IFRS measures. See Appendix B for definition and
reconciliation to nearest equivalent statutory IFRS measures.
Technical Review
In June 2020, a Technical Committee of the Board was established
to oversee a comprehensive review of the geological and reservoir
models of the Lancaster field and the GWA licence (the "Technical
Review"). While the review is yet to complete, analysis of
production performance and review of earlier well data has led to
the following initial conclusions:
Lancaster Oil Water Contact
-- The 205/21a-7z well began to produce water shortly after
field start up, and the water cut has increased steadily, with
water cuts most recently varying between 55-65%. The 205/21a-6 well
began to produce water in October 2019, with a water cut (prior to
the recent scheduled FPSO maintenance) of 18% associated with a
production rate of c.15,000 bopd.
-- A material balance analysis of the 1.1 million barrels of
water produced from the Lancaster field, with continuing increases
in water cut, now demonstrates that this large volume of water is
very unlikely to have originated from a "perched water" zone.
-- Given the observed water production, all wireline pressure,
fluid content and production test data from earlier appraisal wells
has been extensively reanalysed and complemented by learnings and
calibrations from regional aquifer pressure data and input from
third party specialists. The intersection of pressure-depth plots
supports an OWC range of 1,320-1,340 metres TVDSS.
-- Accordingly, the Company now believes that Lancaster water
production is most likely from an underlying aquifer with an OWC at
1,330 metres TVDSS. The observed water production from 205/21a-7z
suggests that the deepest part of that well at 1,329 metres TVDSS
was just above the updated interpretation of the original OWC.
Geological Model of Lancaster
-- Re-evaluation of production test data, and updated mapping
after reinterpretation of seismic and log data, suggest that
significant oil volumes are potentially present in the Victory and
Rona sandstones which onlap the Lancaster fractured basement on the
flanks of the structure. An analogous structural setting has been
documented at the Clair Field along trend to the north west of
Lancaster. Further work is required to assess the size of these
volumes.
-- The probable structural spill point of these onlapping
sandstones on the flanks of Lancaster, based on this updated
mapping exercise, is consistent with an initial OWC at 1,330 metres
TVDSS.
Lancaster Pressure Behaviour
-- Downhole pressure gauges in both Lancaster wells indicate
that reservoir pressure has declined by 120 psi after cumulative
production of 6.6 million barrels of oil. The pressure decline rate
is higher than anticipated in pre-production reservoir modelling
and consistent with a significantly shallower OWC and lower volume
of oil-in-place than that estimated in the 2017 CPR.
-- Pressure gauges in the suspended 205/26b-14 Lincoln well
exhibit a 20 psi pressure decline, most likely as a result of
production from the Lancaster field, 8 km distant. This important
observation demonstrates good regional reservoir connectivity and
that the Brynhild fault zone between Lancaster and Lincoln probably
does not seal. Retrieval of additional pressure data following the
recent scheduled Lancaster maintenance shut-in will be required to
prove conclusively that Lancaster is the cause of the
depletion.
-- While the rate of pressure decline with cumulative production
has slowed, based on current trends, well flowing pressure may
approach the "bubble point" (the point at which gas is liberated
from oil within the reservoir) during H2 2021. This may require the
existing production wells to be choked back in order to manage
potential excess gas production. Further work is underway to better
understand the impact and possible mitigations of gas liberation in
the reservoir, which may also have beneficial effects if a stable
secondary gas cap emerges.
Lancaster Material Balance and Reservoir Simulation
-- Material balance analysis shows a distinctive reduction in
the rate of pressure decline with cumulative production, suggesting
a complex reservoir system. Energy may be provided by a combination
of oil-in-place expansion (within fractured basement and separate
sandstone reservoirs), aquifer influx both from below and
laterally, a developing secondary gas cap, compaction drive and
other possible sources of energy.
-- The relative contributions from each source of reservoir
energy cannot be uniquely determined from material balance analysis
alone. An integrated approach including reservoir modelling and
updated structural analysis is therefore being used to refine
estimates of oil in place, potential recovery and provide better
predictive tools.
-- Lancaster is a significantly more complex reservoir system
than originally thought, with the onlapping sandstones appearing to
represent a significant part of the connected volume indicated by
material balance analysis. Further work is required to verify this
preliminary finding and potential implications for field
development and ultimate recovery.
-- Reservoir modelling based on the probable initial OWC at
1,330 metres TVDSS, matched to observed dynamic behaviour, suggests
that the OWC may have moved upwards by 10-15 metres since
production start and is now within the 205/21a-7z reservoir
section. This well is believed to be "coning" oil from above when
flowed at higher rates. Water production from 205/21a-6 (which at
its deepest point is some 82 metres above the initial OWC) is
considered to be "coning" water up from the aquifer and a rate
dependent water cut has been observed, as would be expected.
-- While work to refine the revised reservoir model is ongoing,
there is currently a good fit to observed pressure and water cut
performance.
Lancaster EPS Production Forecast - No Further Activity
-- On the basis of the 205/21a-6 and 205/21a-7z wells alone,
with no further activity, production levels will continue to
decline slowly from c.15,000 bopd seen immediately prior to the
recent scheduled FPSO shutdown, until well flowing pressure
approaches "bubble point" during H2 2021, at which time production
levels may need to be reduced.
-- While the 205/21a-7z well can produce at high water cuts
using the installed Electric Submersible Pump ("ESP"), the optimal
near-term production strategy is to produce the 205/21a-6 well on
its own under natural flow, leaving 205/21a-7z shut in to minimise
water production and manage reservoir voidage and pressure
declines.
-- Consequently, production guidance for the period 1 September
2020 to 31 December 2020 is 12,000-14,000 bopd, which includes the
scheduled annual FPSO shutdown which was completed on 8 September
2020 and a 95% uptime assumption for the balance of the year.
-- Assuming production would need to be choked back as well
flowing pressure approaches "bubble point" during H2 2021,
un-audited 2P estimated ultimate recovery for the Lancaster EPS
based on the two current wells and no further activity is 16.0
million barrels, of which 9.4 million barrels remain to be produced
(subject to economic limit test).
Lancaster Reserves (existing two wells and no further activity,
subject to economic limit test)
--------------------------------------------------------------------------------------------------------
Million barrels 1P 2P 3P
---------------- ---------------- ----------------
Estimated Ultimate Recovery 14.3 16.0 17.7
---------------- ---------------- ----------------
Reserves remaining (as of 1 September
2020) 7.7 9.4 11.1
---------------- ---------------- ----------------
Lancaster Remediation Options
-- A number of options to mitigate the forecast production and
pressure decline rates of the Lancaster EPS are under active
evaluation.
-- The primary option is to manage reservoir voidage and
pressure decline by initiating water injection. Feasibility studies
are underway to determine optimum timing, cost, location and design
of a water injection well and facilities, including any adaptations
required to the existing water injection capabilities on the Aoka
Mizu. These studies are targeting a decision on possible 2021
activity by the end of 2020. The Company's preliminary estimate for
the cost of a water injection well is $70-80 million gross, which
includes drilling, tie-back and FPSO modifications
-- Given the constraints on operating West of Shetland during
the winter months, the Company does not believe that it will be in
a position to commence any activity until Q2 2021 at the
earliest.
Lancaster Contingent Resources
-- In light of the revised interpretation of the OWC in the
Lancaster field, the Company is voluntarily relinquishing the P1368
Central licence acreage outside of the determined Lancaster field
area.
-- At present, Hurricane has a commitment to drill a well on the
Lancaster licence during 2021, with the objective of providing
evidence in support of the historical deep OWC model. In light of
the revised interpretation of the OWC and pending finalisation of
the voluntary relinquishment announced today, the Company will be
released of its well obligation, enabling reallocation of this
potential cost towards activity focused on enhancing
production.
-- The Company's estimate of contingent resources in Lancaster
has been reduced significantly compared to the 2017 CPR, which
assumed significantly deeper OWC cases. Revised contingent resource
estimates are provided below:
Lancaster contingent resources
----------------------------------------------------------------------------
Million barrels 1C 2C 3C
-------------- -------------- --------------
Lancaster 26 58 90
-------------- -------------- --------------
Note: Does not include any economic limit test
Lancaster Production Operations
During the first half of the year, the Lancaster EPS produced
2.7 million barrels of crude, compared to 0.5 million barrels in H1
2019 when the field was only onstream for a short period following
production start-up in May 2019. In total, seven cargoes were
lifted during the first half of 2020.
The Aoka Mizu FPSO has continued to demonstrate excellent
availability, averaging 99% uptime in the first half of 2020 and
96% in total since production commenced in May 2019. A scheduled
annual maintenance took place over five days in early September
2020, with production restarted on 8 September 2020.
As previously stated by the Company, the Lancaster EPS is
essentially a long-term production test of the Lancaster fractured
basement reservoir, with the ultimate objective of gathering data
to refine reserves and resources estimates and inform future
development phases. During early 2020, the Lancaster EPS production
wells underwent a series of tests, firstly to establish the
characteristics of the 205/21a-6 well, and then both the 205/21a-6
well and 205/21a-7z well on natural flow to establish a longer-term
target rate. Initially, both wells were able to produce at a
combined rate of c.20,000 bopd, albeit with increasing water
production which had not been expected early in the life of the
EPS.
On 22 May 2020, the Company announced the shut in of the
205/21a-7z well following evidence of flow instability, with the
205/21a-6 well maintained on natural flow. In early June 2020 and
following a relaxation of COVID-19 restrictions on UKCS activity,
Hurricane commenced commissioning of the ESPs installed in the
Lancaster production wells, which allowed for the 205/21a-7z well
to return to production at a reduced rate.
In August 2020, following a brief controlled shutdown of the
Aoka Mizu FPSO for minor repairs, the Company commenced a period of
further testing on the 205/21a-6 well to provide additional data in
support of the Technical Review. As stated above, the Company plans
to produce the 205/21a-6 well on a standalone basis in the
near-term, leaving the 205/21a-7z well shut in to minimise water
production and maximise pressure support from the aquifer.
The Lancaster EPS was producing at c.15,000 bopd from the
205/21a-6 well immediately prior to the recent scheduled FPSO
maintenance shutdown, and has averaged c.14,500 bopd to date in H2
2020. Based on current plans, the Company expects the Lancaster EPS
to produce 12,000 -14,000 bopd from September to December 2020
(inclusive) and intends to give production guidance for 2021 early
next year once there is better definition on the 2021 work
programme.
Greater Warwick Area
Following the results of the 2019 drilling programme, the GWA JV
(Hurricane 50%, Spirit Energy 50%) has spent the first half of 2020
reassessing its understanding of the GWA licence potential. In
March 2020, the GWA JV signed a cost allocation agreement,
adjusting certain terms relating to Spirit Energy's original
farm-in in 2018. The full detail of this agreement can be found in
the press release dated 6 March 2020.
In light of the significant restrictions on UKCS activity as a
result of the COVID-19 pandemic, the OGA agreed to extend the
deadline for the GWA licence commitment well from 31 December 2020
to 30 June 2022.
Lincoln
In July 2020, pressure data from the downhole gauges in the
205/26b-14 well was retrieved, which indicated 20 psi depletion at
Lincoln, interpreted to be due to the effect of Lancaster
production some 8 km distant. This suggests that the Brynhild fault
is not sealing, and that the OWC at Lincoln is likely to be close
to the structural closure, as at Lancaster. While limited available
data on Lincoln is not definitive, a base case OWC is now estimated
to be at 1,846 metres TVDSS (+/- 50 metres).
As previously announced, the OGA had given notice of a proposed
field determination area over local structural closure at the
Lincoln discovery, which was subsequently accepted by the GWA
JV.
The Company's preliminary contingent resource volumes using the
OWC range above are shown below, for the Lincoln basement structure
only.
Indicative basement contingent resources (gross) - Hurricane
estimates
-----------------------------------------------------------------------------------------
Million barrels 1C 2C 3C
-------------- -------------- --------------
Lincoln contingent resources 24 45 79
-------------- -------------- --------------
Note: Not subject to any economic limit test
Work is ongoing to map the onlapping Mesozoic section on the
flanks of the Lincoln basement structure. Contingent resources
estimates are subject to revision as this work progresses.
Hurricane continues to work with all GWA stakeholders on the
best way forward for the Lincoln discovery. The GWA JV has a
commitment to plug and abandon the 205/26b-14 Lincoln well by 30
June 2021 at an estimated total cost of $12 million gross.
Warwick
To date, Hurricane's Technical Review has not incorporated an
updated assessment of Warwick. However, the conclusion of the
Technical Review is likely to lead to a significant downgrade of
the prospective resources attributed to Warwick in the 2017 WoS
CPR.
Halifax
To date, the Technical Review has not incorporated an updated
assessment of Halifax. However, the conclusion of the Technical
Review is likely to lead to a significant downgrade of the 2C
resources attributed to Halifax in the 2017 WoS CPR.
Completion of Technical Review and CPR
The Technical Committee's work has yet to be completed and
further updates will be announced when appropriate. It is still the
Company's intention that the final conclusions will be integrated
into an updated Competent Person's Report covering all of its West
of Shetland assets, which the Company anticipates will be released
no later than the end of Q1 2021.
ESG and Gas Export Update
In April 2020, Hurricane published its first standalone
Environmental, Social and Governance report. The ESG report covered
Hurricane's approach to ESG and performance across its operations
for the 2019 calendar year. It is Hurricane's intention to enhance
its ESG disclosures going forward, including but not limited to,
aligning its reporting with the Task Force on Climate-related
Financial Disclosures' recommendations, alignment of the Company's
activities and objectives with the UN's Sustainable Development
Goals and meeting the requirements of the UK's Streamlined Energy
and Carbon Reporting ("SECR") policy.
Currently, associated gas production from the Lancaster EPS is
partially used as fuel gas on the Aoka Mizu FPSO, with the
remainder flared under the consent within the approved Field
Development Plan. Further development of the Company's West of
Shetland licences may require the development of a gas export
solution. As part of the first phase of the Spirit Energy farm-in
to the GWA licence, long lead items for gas export have been
purchased. The Company remains fully committed to reducing its
greenhouse gas emissions where it is economically and commercially
viable to do so, and fully supports OGUK's commitment for a net
zero basin by 2050.
Corporate
On 27 February 2020, it was announced that Chief Financial
Officer, Alistair Stobie, had resigned by mutual agreement with the
Board. Richard Chaffe, formerly Head of Finance, was appointed
Acting CFO and subsequently confirmed as Chief Financial Officer
and an executive director of the Company in June 2020.
On 8 June 2020, it was announced that Dr Robert Trice had
resigned as Chief Executive Officer and a Director of the Company
by mutual consent with the Board. Ms Beverley Smith, a
non-executive director of Hurricane, was appointed Interim CEO.
On 8 July 2020, Hurricane was deeply saddened to report that
Neil Platt, Chief Operations Officer and executive director of the
Company, had passed away. Mr Platt was a hugely respected colleague
and his passion, enthusiasm and technical excellence were integral
to Hurricane's growth over the past decade. His leadership was
pivotal to the successful delivery and operation of the Lancaster
EPS.
Steve Holmes, Production Operations Director, was appointed
Acting Chief Operations Officer with the Company pleased to confirm
his appointment as Chief Operations Officer on 11 September
2020.
On 21 August 2020, it was announced that Antony Maris had been
appointed as a Director of the Company and CEO Designate. He
formally assumed the role of CEO following the publication of these
financial results, with Beverley Smith returning to her
non-executive role.
Mr Maris brings 35 years of wide-ranging oil and gas sector
technical and business leadership experience to Hurricane. Prior to
joining the Company, he spent 15 years with Pharos Energy plc
(previously SOCO International plc) where he was Chief Operating
Officer from 2012 to early 2020. In this role, he was responsible
for the development and operation of several oilfields, in joint
venture with local and other parties, including fractured basement
reservoirs offshore Vietnam and onshore Yemen. Pharos Energy's
Vietnam assets, which delivered 60,000 bopd gross peak volumes,
contributed significantly to Vietnam's overall hydrocarbon output.
He was awarded the Friendship Order Medal by the Vietnam Government
for his significant contribution to exploration and production
activities.
Outlook
Hurricane's near-term priority is to evaluate options to
mitigate forecast production declines at Lancaster by water
injection or other means, and to assess the potential of the
sandstones which onlap the Lancaster basement. This work is
expected to conclude before the end of 2020 with a strong focus on
prudent capital allocation. In addition, work will continue on
Lincoln with the objective of considering possible pathways towards
development.
The Company will, in parallel, be engaging with its key
stakeholders regarding the forward work programme and financing
arrangements in order to maximise the value of its assets.
Despite the reductions in Lancaster reserves and resources
announced today, Hurricane's asset base remains significant in a
wider UKCS context and the Company has a valuable base of installed
infrastructure from which to exploit further upside.
Beverley Smith
Interim Chief Executive Officer
10 September 2020
Financial Review
Highlights
First half 2020 Full year 2019 First half 2019
Production 2,658 kbbl 3,030 kbbl 528 kbbl
---------------- --------------- ----------------
Production rate* 14,600 bopd 12,900 bopd 10,400 bopd
---------------- --------------- ----------------
Sales volumes 2,747 kbbl 2,874 kbbl 356 kbbl
---------------- --------------- ----------------
Revenue $81.9m $170.3m $22.5m
---------------- --------------- ----------------
Average sales price realised $29.8/bbl $59.3/bbl $63.2/bbl
---------------- --------------- ----------------
Cash production cost per barrel $18.2/bbl $21.8/bbl $24.0/bbl
---------------- --------------- ----------------
Operating cash inflow/(outflow) $21.9m $112.2m $6.1m
---------------- --------------- ----------------
Closing net free cash $106.2m $133.6m $48.4m
---------------- --------------- ----------------
Net debt $123.8m $96.4m $181.6m
---------------- --------------- ----------------
Underlying profit/(loss) before tax $(40.2)m $30.0m $4.0m
---------------- --------------- ----------------
Profit/(loss) after tax $(307.8)m $58.7m $(21.2)m
---------------- --------------- ----------------
* Rounded to nearest 100 bopd; 2019 rates calculated from First
Oil in 2019.
Non-IFRS measures. See Appendix B for definition and
reconciliation to nearest equivalent statutory IFRS measures.
During the first half of 2020, over 2.7 million barrels of
Lancaster crude were sold across seven cargoes, generating $81.9
million in revenue. Despite the low oil prices seen across the
period, the Group was still able to generate positive cash flow
from operations of $21.9 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.
The Group exercised tight capital discipline, with $35.8 million
spent on capital expenditure.
Revenue
Revenue for the period was $81.9 million, with an average price
realised of $29.8/bbl across seven cargoes, versus an average Dated
Brent price for the period of $40.1/bbl. Under the sales and
marketing agreement with BP, the sale of Lancaster crude is priced
at either the first five or last five days of the month of lifting
(at buyer's option). In volatile pricing environments, such as was
seen during February to April 2020, this meant that the applicable
Dated Brent price was, on average, lower than the spot price at
date of sale.
The average discount to Brent realized was $4.2/bbl
(representing the discount or premium offered by the refinery
purchasing the crude, BP's marketing fee, and the freight costs
incurred by BP in transporting crude to its ultimate destination).
The discounts and premia experienced saw significant variability
during the first half of 2020 amid a volatile crude market; but
with all cargoes sold to date having been on time, within
specification and contractual terms, Hurricane has a growing
reputation of being a reliable producer. With crude markets
stabilising, average discounts to Brent in the second half of 2020
thus far have been significantly better than the first half of the
year.
Cost of sales
Total cost of sales was $101.5 million, including $55.6 million
of depreciation charges (calculated on a unit-of-production basis).
Cash production costs (which exclude depreciation and accounting
movements in inventory but include the fixed lease charges for the
Aoka Mizu) were $48.3 million, equivalent to $18.2/bbl versus
$21.8/bbl in 2019. The decrease in cash production costs per barrel
was primarily 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 (full year 2019) to
$15.2/bbl in 2020, driven by higher production rates in 2020.
Impairment of oil and gas assets
Following the initial conclusions of the Technical Review (see
above), the associated downwards revision of estimated recoverable
reserves and the decline in oil prices during the year, a non-cash
impairment charge of $238.9 million has been recognised against the
producing Lancaster oil and gas assets. The impairment charge was
calculated based on expected future cashflows from the Lancaster
EPS, using a number of forecast production profiles (both with and
without the cost and benefits of a water injection programme) and
probability weighted according to our best estimates of the most
likely outcomes. For further details on the impairment charge, key
assumptions and methodology used see notes 1.4.1 and 2.3 to the
interim financial statements. 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 water injection programme, an updated CPR
assessment of the Lancaster field, and any other intervening
developments) have the ability to significantly impact these
projections, which could lead to additional impairments or future
reversals in future periods.
Impairment of intangible assets
Impairments and write-offs of intangible exploration and
intangible assets included $12.5 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 to June 2021, and to commence
drilling the GWA commitment well by 30 June 2022, the JV partners
took the decision to terminate the hire of the rig in June 2020,
and settle the remaining minimum hire costs with the rig
operator.
Other profit and loss
General and administrative costs decreased from $4.5 million in
H1 2019 to $3.6 million in H1 2020, primarily due to more staff and
administrative costs now included within cost of sales and lower
non-cash share-based payment expense.
Convertible Bond accounting
The accounting for the Convertible Bond (issued in July 2017)
required the recognition of an embedded derivative liability
related to the equity conversion option. 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 to the
Financial Statements for further details.
The gains recognised do not have any impact on the Group's cash
position, amounts payable in respect of the Convertible Bond, or on
its tax position. On either conversion or repayment of the Bond,
the derivative liability will be released to the Income
Statement.
The fair value gain recognised during the period in relation to
the embedded derivative was $34.0 million, primarily driven by
decreases in the Company's share price in the period.
Hedging
In June 2020, Hurricane hedged a portion of its forecast
production for the second half of 2020. A total of 1.8MMbbls
(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 represents 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. As oil prices increased in June, a fair value loss on the
derivatives was recognised of $0.8 million, included within net
finance costs.
Cashflow
At 30 June 2020, the Group had $106.2 million of net free cash
(being unrestricted cash net of payables and accruals and including
trade receivables), a decrease of $27.4 million from 31 December
2019.
Even with oil prices at historic lows, the Lancaster EPS was
still able to be cash positive. Average realised sales price was
$29.8/bbl and cash production costs were $18.2/bbl, generating cash
per barrel (before working capital movements) of $11.6/bbl in H1
2020.
Other operating cash outflows included $3.4 million for the
purchase of term put options and $2.1 million on decommissioning
the previously suspended Halifax and Whirlwind wells. After
adjusting for movements in working capital (including proceeds of
$17 million from the end of June cargo sale received on 1 July
2020), the Group's operating cash inflow amounted to $21.9
million.
Capital expenditure in the period was $35.8 million. Expenditure
on GLA activities related to preparations for gas export work, and
long-lead items in preparation for future drilling activity. Net
cash outflows relating to GWA represented the Group's share of its
costs of the joint operation, including long-lead items relating to
a potential future GWA tie-back, idle rig costs of the Paul B Loyd
Jr, and the timing impact of expenditure incurred by the Group as
operator before recovery of costs from Spirit.
Financing outflows of $13.4 million mainly included coupon
payments of the Convertible Bond and fixed lease repayments
primarily for the Aoka Mizu.
Following start-up of production from the EPS, the Group is
required to set aside a certain amount of cash generated from oil
sales to cover some of the termination costs of the FPSO lease
should it wish to exit the charter before the end of the contract
term. At 30 June 2020, this amounted to $20.1 million and was
classified as restricted cash. In addition to the above, the Group
currently provides post tax security for its decommissioning
liability for the Lancaster field by way of a decommissioning bond.
Should it be necessary to replace this with cash security this
would result in up to an additional $36 million of unrestricted
cash moving to restricted cash.
Tax
The Group recognised a total tax charge for H1 2020 of $49.3
million, all related to deferred tax. 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 Technical Review, 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 tax charge of $49.3 million in the period.
Principal risks
There are a number of potential risks and uncertainties which
could have a material impact on the Group's performance. Certain of
these risks impacted the Company in the first half of 2020 and
could continue to impact the Company over the remaining six months
of 2020 and could cause actual results to differ materially from
expected and historical results. The Group's principal risks are as
follows:
-- Substantial capital requirements
-- Exploration, appraisal and development operational risks
-- Production operational risks
-- Geological and reservoir risk
-- Regulatory
-- Oil price fluctuations
-- Third-party infrastructure
-- Development project delivery
-- Health, Safety and Environmental
-- Compliance
-- Joint venture partners
-- Strategy
-- Climate change and energy transition
The principal risks and uncertainties, along with the mitigation
measures in place to reduce risks to acceptable levels, are
consistent with those as at 31 December 2019. The risks associated
with COVID-19 (primarily with regards to disruption to operations
and adverse impact on commodity prices) and Brexit (primarily with
regards to potential regulatory impacts) are included within the
existing principal risks above.
Further information on the above principal risks and
uncertainties, and the manner in which they are managed and
mitigated, is provided on pages 18 to 23 of the Group's 2019 Annual
Report and Group Financial Statements.
Related party transactions
There have been no new material related party transactions in
the period and there have been no material changes to the related
party transactions described in note 7.3 to the Consolidated
Financial Statements contained in the 2019 Annual Report and
Accounts.
Going concern
At the time of preparation of these Interim Financial
Statements, the Directors have a reasonable expectation that the
Group has adequate resources to continue to operate and meet its
liabilities as they fall due for the foreseeable future, a period
considered to be at least twelve months from the date of signing
these Financial Statements. For this reason, they continue to adopt
the Going Concern Basis for preparing the Interim Financial
Statements. Further details are described in Note 1.2 in the
interim financial statements.
Independent Review Report to Hurricane Energy plc
We have been engaged by the Company to review the condensed set
of financial statements in the half-yearly financial report for the
six months ended 30 June 2020 which comprises the condensed
consolidated statement of comprehensive income, the condensed
consolidated balance sheet, the condensed consolidated statement of
changes in equity, the condensed consolidated cash flow statement
and related notes 1 to 7. We have read the other information
contained in the half-yearly financial report and considered
whether it contains any apparent misstatements or material
inconsistencies with the information in the condensed set of
financial statements.
Directors' responsibilities
The half-yearly financial report is the responsibility of, and
has been approved by, the directors. The directors are responsible
for preparing the half-yearly financial report in accordance with
the AIM Rules of the London Stock Exchange.
As disclosed in note 1, the annual financial statements of the
Group are prepared in accordance with IFRSs as adopted by the
European Union. The condensed set of financial statements included
in this half-yearly financial report has been prepared in
accordance with International Accounting Standard 34 "Interim
Financial Reporting," as adopted by the European Union.
Our responsibility
Our responsibility is to express to the Company a conclusion on
the condensed set of financial statements in the half-yearly
financial report based on our review.
Scope of review
We conducted our review in accordance with International
Standard on Review Engagements (UK and Ireland) 2410 "Review of
Interim Financial Information Performed by the Independent Auditor
of the Entity" issued by the Financial Reporting Council for use in
the United Kingdom. A review of interim financial information
consists of making inquiries, primarily of persons responsible for
financial and accounting matters, and applying analytical and other
review procedures. A review is substantially less in scope than an
audit conducted in accordance with International Standards on
Auditing (UK) and consequently does not enable us to obtain
assurance that we would become aware of all significant matters
that might be identified in an audit. Accordingly, we do not
express an audit opinion.
Conclusion
Based on our review, nothing has come to our attention that
causes us to believe that the condensed set of financial statements
in the half-yearly financial report for the six months ended 30
June 2020 is not prepared, in all material respects, in accordance
with International Accounting Standard 34 as adopted by the
European Union and the AIM Rules of the London Stock Exchange.
Use of our report
This report is made solely to the Company in accordance with
International Standard on Review Engagements (UK and Ireland) 2410
"Review of Interim Financial Information Performed by the
Independent Auditor of the Entity" issued by the Financial
Reporting Council. Our work has been undertaken so that we might
state to the Company those matters we are required to state to it
in an independent review report and for no other purpose. To the
fullest extent permitted by law, we do not accept or assume
responsibility to anyone other than the Company, for our review
work, for this report, or for the conclusions we have formed.
Deloitte LLP
Statutory Auditor
London, UK
10 September 2020
Condensed Consolidated Statement of Comprehensive Income
for the 6 months ended 30 June 2020
6 months 6 months 12 months
ended ended ended
Notes 30 Jun 2020 30 Jun 2019 31 Dec 2019
$'000 $'000 $'000
Revenue 2.1 81,871 22,462 170,283
Cost of sales 2.2 (101,476) (16,740) (118,453)
------------------------------------- ----- ----------- ----------- -----------
Gross (loss)/profit (19,605) 5,722 51,830
General and administrative
expenses (3,552) (4,542) (400)
Impairment of oil and gas
assets 2.3 (238,853) - -
Impairment of intangible exploration
and evaluation assets and
exploration expense written
off 2.4 (12,537) - (66,468)
------------------------------------- ----- ----------- ----------- -----------
Operating (loss)/profit (274,547) 1,180 (15,038)
Finance income 3.2 843 619 1,741
Finance costs 3.2 (18,730) (5,814) (23,206)
Fair value gain/(loss) on
Convertible Bond
embedded derivative 5.1 33,956 (23,466) 34,691
Loss before tax (258,478) (27,481) (1,812)
Tax 6.1 (49,262) 6,235 60,487
------------------------------------- ----- ----------- ----------- -----------
(Loss)/profit for the period (307,740) (21,246) 58,675
------------------------------------- ----- ----------- ----------- -----------
Cents Cents Cents
(Loss)/earnings per share
(basic) 3.1 (15.47) (1.08) 2.97
(Loss)/earnings per share
(diluted) 3.1 (15.47) (1.08) 1.70
------------------------------------- ----- ----------- ----------- -----------
All results arise from continuing operations.
Condensed Consolidated Balance Sheet
as at 30 June 2020
Notes 30 Jun 2020 30 Jun 2019 31 Dec 2019
$'000 $'000 $'000
Non-current assets
Intangible exploration and
evaluation assets 2.4 88,619 131,537 75,874
Oil and gas assets 2.3 513,614 844,195 796,155
Other non-current assets 2,862 3,391 3,080
Deferred tax assets 6.2 5,048 - 54,311
Cash and cash equivalents 4.1 2,881 2,967 3,065
------------------------------------- ----- ----------- ----------- -----------
613,024 982,090 932,485
Current assets
Inventory 2.2 8,870 11,232 9,945
Trade and other receivables 4.2 36,718 55,144 50,435
Derivative financial instruments 4.4 2,542 - -
Cash and cash equivalents 4.1 143,223 96,773 168,369
------------------------------------- ----- ----------- ----------- -----------
191,353 163,149 228,749
------------------------------------- ----- ----------- ----------- -----------
Total assets 804,377 1,145,239 1,161,234
------------------------------------- ----- ----------- ----------- -----------
Current liabilities
Trade and other payables 4.3 (54,952) (87,404) (72,369)
Lease liabilities 5.2 (9,463) (9,482) (9,501)
Decommissioning provisions 2.5 (12,650) - (12,484)
------------------------------------- ----- ----------- ----------- -----------
(77,065) (96,886) (94,354)
Non-current liabilities
Lease liabilities 5.2 (88,561) (90,543) (89,685)
Convertible Bond liability 5.1 (211,097) (202,250) (206,604)
Convertible Bond embedded derivative 5.1 (2,360) (94,473) (36,316)
Decommissioning provisions 2.5 (41,437) (44,401) (43,190)
------------------------------------- ----- ----------- ----------- -----------
(343,455) (431,667) (375,795)
------------------------------------- ----- ----------- ----------- -----------
Total liabilities (420,520) (528,553) (470,149)
------------------------------------- ----- ----------- ----------- -----------
Net assets 383,857 616,686 691,085
------------------------------------- ----- ----------- ----------- -----------
Equity
Share capital 5.4 2,885 2,883 2,883
Share premium 822,458 821,910 821,910
Share option reserve 21,141 26,377 20,828
Own shares reserve (1,035) (711) (684)
Foreign exchange reserve (90,828) (90,828) (90,828)
Accumulated deficit (370,764) (142,945) (63,024)
------------------------------------- ----- ----------- ----------- -----------
Total equity 383,857 616,686 691,085
------------------------------------- ----- ----------- ----------- -----------
Condensed Consolidated Statement of Changes in Equity
for the 6 months ended 30 June 2020
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
Loss for the
period - - - - - (21,246) (21,246)
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 - - 2,310 62 - - 2,372
At 30 June
2019 2,883 821,910 26,377 (711) (90,828) (142,945) 616,686
Profit for
the period - - - - - 79,921 79,921
Share-based
payments - - (5,549) 27 - - (5,522)
At 31 December
2019 2,883 821,910 20,828 (684) (90,828) (63,024) 691,085
---------------- -------- -------- -------- ---------- --------- ----------- ---------
Loss for the
period - - - - - (307,740) (307,740)
New shares
issued under
employee share
schemes 2 548 - (445) - - 105
Share-based
payments - - 313 94 - - 407
At 30 June
2020 2,885 822,458 21,141 (1,035) (90,828) (370,764) 383,857
---------------- -------- -------- -------- ---------- --------- ----------- ---------
Condensed Consolidated Cash Flow Statement
for the 6 months ended 30 June 2020
6 months 6 months 12 months
ended ended ended
Notes 30 Jun 2020 30 Jun 2019 31 Dec 2019
$'000 $'000 $'000
Cash flows from operating activities
Operating (loss)/profit (274,547) 1,180 (15,038)
Adjustments for:
Depreciation of property, plant
and equipment 2.3 55,881 11,101 63,161
Impairment of oil and gas assets 2.3 238,853 - -
Impairment of intangible exploration
and evaluation assets and exploration
expense written off 2.4 12,537 - 66,468
Share-based payment charge/(credit) 407 2,372 (3,150)
Purchase of derivative financial
instruments 4.4 (3,420) - -
Decommissioning spend 2.5 (2,100) - (12)
---------------------------------------- ----- ----------- ----------- -----------
Operating cash flow before working
capital movements 27,611 14,653 111,429
Movement in receivables (16,932) (2,968) (2,559)
Movement in payables 8,169 1,090 8,912
Movement in crude oil, fuel
and chemicals inventories 3,041 (6,662) (5,613)
Net cash from operating activities 21,889 6,113 112,169
---------------------------------------- ----- ----------- ----------- -----------
Cash flows from investing activities
Interest received 843 619 1,438
Decrease in liquid investments - 21,668 21,668
Expenditure on oil and gas assets (12,373) (30,906) (52,878)
Expenditure on other fixed assets (69) (253) (289)
Expenditure on intangible exploration
and evaluation assets (21,432) (4,217) (2,265)
Movement in spares and supplies
inventories (1,966) - 239
Tax refund relating to R&D expenditure 6.1 - 6,235 6,235
---------------------------------------- ----- ----------- ----------- -----------
Net cash used in investing activities (34,997) (6,854) (25,852)
---------------------------------------- ----- ----------- ----------- -----------
Cash flows from financing activities
Convertible Bond interest paid 5.1 (8,625) (8,625) (17,250)
Lease payments 5.2 (4,836) (701) (5,556)
Interest and other finance charges
paid (4) (6) (1,539)
New shares issued under warrants
and rights 5.4 - 7,782 7,782
New shares issued under employee
share schemes 105 94 94
---------------------------------------- ----- ----------- ----------- -----------
Net cash used in financing activities (13,360) (1,456) (16,469)
---------------------------------------- ----- ----------- ----------- -----------
(Decrease)/increase in cash and
cash equivalents (26,468) (2,197) 69,848
---------------------------------------- ----- ----------- ----------- -----------
Cash and cash equivalents at
beginning of period 171,434 101,831 101,831
Net (decrease)/increase in cash
and cash equivalents (26,468) (2,197) 69,848
Effects of foreign exchange rate
changes 1,138 106 (245)
---------------------------------------- ----- ----------- ----------- -----------
Cash and cash equivalents at
end of period 4.1 146,104 99,740 171,434
---------------------------------------- ----- ----------- ----------- -----------
Notes to the Interim Financial Statements
Section 1 General information
Hurricane Energy plc is a public company, limited by shares,
incorporated and domiciled in the United Kingdom and registered in
England and Wales under the Companies Act 2006 (registered company
number 05245689). The nature of the Group's operations and its
principal activity is exploration, development and production of
oil and gas reserves principally on the UK Continental Shelf. The
address of Hurricane Energy plc's registered office is The Wharf,
Abbey Mill Business Park, Lower Eashing, Godalming, Surrey, GU7
2QN. Hurricane Energy plc's shares are listed on the AIM market of
the London Stock Exchange.
This Interim Report and Financial Statements was approved by the
Board of Directors and authorised for issue on 10 September
2020.
This set of Interim Financial Statements for the 6 months ended
30 June 2020 is unaudited and does not constitute statutory
accounts within the meaning of section 434 of the Companies Act
2006. Audited statutory Financial Statements for the year ended 31
December 2019 were approved by the Board of Directors on 8 April
2020 and have been delivered to the Registrar of Companies. The
auditor's report on those Financial Statements was unqualified, did
not draw attention to any matters by way of emphasis and did not
contain a statement made under Section 498 of the Companies Act
2006.
1.1 Basis of preparation
The Interim Financial Statements for the six months ended 30
June 2020 have been prepared in accordance with International
Accounting Standard 34 'Interim Financial Reporting' (IAS 34) as
adopted by the European Union and the AIM Rules. These Interim
Financial Statements should be read in conjunction with the annual
Financial Statements for the year ended 31 December 2019, which
have been prepared in accordance with International Financial
Reporting Standards as adopted by the European Union (IFRS). The
consolidated income statement and related notes represent results
arising from continuing operations, there being no discontinued
operations in the periods presented. The Interim Financial
Statements have been prepared using accounting bases and policies
consistent with those used in the preparation of the audited
Financial Statements of the Group for the year ended 31 December
2019.
1.2 Going concern
The Group's business activities, together with the factors
likely to affect its future development, performance and position
are set out in the Interim Chief Executive Officer's review and
Financial Review above. The financial position of the Group, its
cash flows and liquidity position are set out in these Interim
Financial Statements.
The directors have performed a robust assessment, including a
review of the budget for the year ending 31 December 2020 and
longer-term strategic forecasts and plans, including consideration
of the principal risks faced by the Company and taking into account
the ongoing impact of the global COVID-19 pandemic on the
macroeconomic situation and any potential impact to operations. In
particular, the directors considered a number of sensitivities on
key assumptions which included downside (reverse stress)
sensitivities in relation to production rates, oil price, fixed
operating costs and foreign exchange rates, which estimated the
extent to which the key assumption would need to be adversely
impacted in order to eliminate the forecast headroom. Following
this review, the directors are satisfied that, taking into
consideration reasonably possible downside sensitivities, the Group
has adequate resources to continue to operate and meet its
liabilities as they fall due for the foreseeable future, a period
considered to be twelve months from the date of signing these
Interim Financial Statements. For this reason, they continue to
adopt the Going Concern Basis for preparing the Interim Financial
Statements.
1.3 Accounting policies
The accounting policies adopted are consistent with those of the
annual Financial Statements for the year ended 31 December 2019.
New and amended standards that became applicable for the Group in
the current reporting period have not resulted in changes to
accounting policies or retrospective adjustments.
1.4 Critical accounting judgments and key sources of estimation
uncertainty
The critical judgments made in applying those accounting
policies and the key sources of estimation uncertainty are the same
as those described in the audited Financial Statements of the Group
for the year ended 31 December 2019, except as described below.
1.4.1 Key source of estimation uncertainty - Impairment testing
of assets
The Group assesses its assets and cash generating units ('CGUs')
in each reporting period to determine whether any indicators of
impairment exist. Where indicators exist, a formal impairment test
is undertaken to estimate the recoverable amount (which is
considered to be the higher of fair value less costs of disposal
('FVLCD') and value in use ('VIU')).
At the previous reporting date (31 December 2019), it was
concluded that there were no impairment triggers in relation to the
Lancaster field and hence no formal impairment test was required.
As at 30 June 2020 a number of impairment triggers, including the
impact of the COVID-19 pandemic on global crude oil demand, were
identified and accordingly a formal impairment assessment was
undertaken which resulted in an impairment charge of $238.9 million
(see note 2.3).
For the producing Lancaster field, the recoverable amount was
based on VIU which was estimated using a discounted cash flow model
over the field's life, taking into account the cost of, and upside
expected to be generated from, future capital expenditure plans
designed to maintain sustainable production. The key assumptions
used are based on best estimates using past experience, latest
internal technical analysis and external factors, and include:
-- production profiles and operating performance based on
internal estimates and reservoir simulation models;
-- the estimated cost of a water injection capital programme and
subsequent forecast increase in production performance due to the
additional pressure support (over and above estimated production in
a 'no further activity' scenario);
-- consideration of the costs of accessing, and potential
incremental production from, the field's estimated revised 2C
contingent resources;
-- Dated Brent oil price assumptions (in real terms) of $45/bbl
for the remainder of 2020 and 2021; rising to $50/bbl in 2022 and
incrementally upwards to a long-term price of $60/bbl in 2025 and
thereafter;
-- operating cost assumptions based on latest budgets and information from key contractors;
-- foreign exchange rate of 1.3 GBP:USD; and
-- a pre-tax real discount rate of 10.3%.
Given the current uncertainty with regards to production
guidance, forward plans and the status of the Group's Technical
Review of reserves and resources, a number of forecast production
profiles were generated, with and without the cost and benefits of
a water injection programme, with the results probability weighted
using management's best estimates.
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
water injection programme, an updated CPR assessment of the
Lancaster field, and any other intervening developments) have the
ability to significantly impact these projections, which could lead
to additional impairments or future reversals in future
periods.
Sensitivity analyses performed indicate that a $5/bbl reduction
in the oil price assumption across all periods would result in an
additional impairment charge of $87 million, and a 1% increase in
the discount rate used would increase the impairment charge by $14
million. It is not practical to provide meaningful sensitivity
analysis on the outcome of the Group's Technical Review, given the
current status and complexity of that process.
Section 2 Oil and gas operations
2.1 Revenue
All revenue is derived from contracts with customers and is
comprised of one category and within one geographical location,
being the sale of crude oil from the Lancaster EPS. All sales were
made to one external customer (BP Oil International Limited).
6 months 6 months 12 months
ended ended ended
30 Jun 2020 30 Jun 2019 31 Dec 2019
$'000 $'000 $'000
Oil sales 81,871 22,462 170,283
-------------------------------------- ----------- ----------- -----------
Revenue from contracts with customers 81,871 22,462 170,283
-------------------------------------- ----------- ----------- -----------
Cargoes sold 7 1 7
Sales volumes 2,747 kbbls 356 kbbls 2,874 kbbls
Average sales price realised $29.8/bbl $63.2/bbl $59.3/bbl
2.2 Cost of sales and inventory
Cost of sales
6 months 6 months 12 months
ended ended ended
30 Jun 2020 30 Jun 2019 31 Dec 2019
Note $'000 $'000 $'000
Operating costs 36,170 9,463 44,915
Depreciation of oil and gas
assets - owned 2.3 48,348 9,423 54,406
Depreciation of oil and gas
assets - leased 2.3 7,258 1,404 8,210
Movement in crude oil inventory 2,113 (5,572) (4,424)
Variable lease payments 5.2 7,587 2,022 15,346
-------------------------------- ---- ----------- ----------- -----------
Cost of sales 101,476 16,740 118,453
-------------------------------- ---- ----------- ----------- -----------
Inventory
30 Jun 2020 30 Jun 2019 31 Dec 2019
$'000 $'000 $'000
Crude oil 2,311 5,572 4,424
Fuel and chemicals 621 1,449 1,549
Spares and supplies 5,938 4,211 3,972
---------------------- ----------- ----------- -----------
Inventory 8,870 11,232 9,945
---------------------- ----------- ----------- -----------
No net realisable value provision for inventory was held at the
balance sheet dates.
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 24,334 120,695
Changes to decommissioning
estimates 2.5 4,878 1,633 6,511
------------------------------- ---- -------- --------- ---------
At 30 June 2019 101,239 753,783 855,022
Additions - 1,855 1,855
Changes to decommissioning
estimates 2.5 108 1,786 1,894
------------------------------- ---- -------- --------- ---------
At 31 December 2019 101,347 757,424 858,771
Additions - 13,762 13,762
Changes to decommissioning
estimates 2.5 (228) (1,616) (1,844)
------------------------------- ---- -------- --------- ---------
At 30 June 2020 101,119 769,570 870,689
------------------------------- ---- -------- --------- ---------
Depreciation
At 1 January 2019 - - -
Depreciation charge for the
period (1,404) (9,423) (10,827)
------------------------------- ---- -------- --------- ---------
At 30 June 2019 (1,404) (9,423) (10,827)
Depreciation charge for the
period (6,806) (44,983) (51,789)
------------------------------- ---- -------- --------- ---------
At 31 December 2019 (8,210) (54,406) (62,616)
Depreciation charge for the
period (7,258) (48,348) (55,606)
Impairment (31,040) (207,813) (238,853)
------------------------------- ---- -------- --------- ---------
At 30 June 2020 (46,508) (310,567) (357,075)
------------------------------- ---- -------- --------- ---------
Carrying amount at 30 June
2019 99,835 744,360 844,195
------------------------------- ---- -------- --------- ---------
Carrying amount at 31 December
2019 93,137 703,018 796,155
------------------------------- ---- -------- --------- ---------
Carrying amount at 30 June
2020 54,611 459,003 513,614
------------------------------- ---- -------- --------- ---------
An impairment charge of $238.9 million was recognised against
producing oil and gas assets in the period. The triggers for the
impairment test were the downward revision of estimated recoverable
reserves as a result of the ongoing Technical Review, the decline
in oil prices across the first half of 2020 and the market
capitalisation of the Group falling below its 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 in note 1.4.1 above. The charge was allocated
pro-rata to owned and leased assets based on their respective
carrying values pre-impairment.
Oil and gas assets held under leases comprise the Aoka Mizu FPSO
bareboat charter, which commenced in May 2019 (see note 5.2).
Included within the cost of owned oil and gas assets is $42.8
million of capitalised borrowing costs.
The total amount of depreciation charged in the period
(comprising depreciation of oil and gas assets above, and
depreciation of other fixed assets) was $55.9 million (6 months
ended 30 June 2019: $11.1 million; 12 months ended 31 December
2019: $63.2 million)
2.4 Intangible exploration and evaluation assets
6 months 6 months 12 months
ended ended ended
30 Jun 2020 30 Jun 2019 31 Dec 2019
Note $'000 $'000 $'000
At start of period 75,874 131,526 131,526
Additions 24,080 788 6,619
Other movements - (806) -
Impairment (12,109) - (66,468)
Changes to decommissioning
estimates 2.5 774 29 4,197
--------------------------- ---- ----------- ----------- -----------
At end of period 88,619 131,537 75,874
--------------------------- ---- ----------- ----------- -----------
Intangible exploration and evaluation assets comprise 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, at 30 June 2020, comprises the Lincoln,
Warwick and Halifax licences. The directors have fully considered
and reviewed the potential value of licence interests, including
carried forward exploration and evaluation expenditure. In doing
so, they have considered the Groups' tenure of its licence
interests, its plan for further exploration and evaluation
activities in relation to these and the likely opportunities for
realising the value of those licences, either by farm-out or by
development of the assets. After taking into account the specific
amounts impaired below, they consider the carrying amount to be
appropriate.
Amounts impaired in the period were $12.1 million, comprising
the Group's share of standby costs for the Paul B Loyd Jr rig,
which was not used for any drilling campaigns following the OGA
granting an extension to the licence commitments on the Lincoln
field in light of the COVID-19 pandemic. See the Interim Chief
Executive Officer's review and Financial Review above for further
details.
Exploration expense written off in the period was $0.4 million,
relating to changes in decommissioning estimates for the Whirlwind
well (which was fully written-off in December 2019).
In August 2020, the P2294 licence that holds the Warwick assets
was extended into its second term, and now expires in August 2023.
Although the initial term of the P2308 licence that holds the
Halifax assets is due to expire in November 2020, the directors
expect this licence to be renewed into its second term, having met
the required work programmes for the licence within its initial
term.
On 12 December 2019, the Group executed a deed of variation with
the Oil and Gas Authority (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, all relating to Whirlwind. The carrying value of
intangible exploration and evaluation assets relating to Strathmore
was previously fully impaired in 2017.
2.5 Decommissioning provisions
6 months 6 months 12 months
ended ended ended
30 Jun 2020 30 Jun 2019 31 Dec 2019
$'000 $'000 $'000
At start of period 55,673 37,657 37,657
Net new provisions and changes
in estimates 397 6,540 17,706
Utilised in period (2,100) - (12)
Unwinding of discount 117 204 323
At end of period 54,087 44,401 55,674
--------------------------------- ----------- ----------- -----------
Of which:
Current 12,650 - 12,484
Non-current 41,437 44,401 43,190
--------------------------------- ----------- ----------- -----------
54,087 44,401 55,674
------------------------------- ----------- ----------- -----------
The provision for decommissioning relates to the costs required
to decommission the suspended wells previously drilled on the
Lincoln and Lancaster exploration assets, the costs required to
decommission the Lancaster EPS installations and the costs required
to clean, remove and restore the Aoka Mizu FPSO at the end of the
charter term.
The decommissioning costs are expected to be incurred during
2021 (for the 205/26b-14 Lincoln well) and towards the end of 2025
(for the Lancaster EPS, Aoka Mizu FPSO and Lancaster exploration
well).
Changes in estimates in the period have arisen from a decrease
in the assumed discount rate, changes in foreign exchange rates,
and changes to the expected costs and timing of decommissioning the
205/26b-14 Lincoln well following the OGA granting an extension of
the suspension consent from June 2020 to June 2021.
Of the total net new provisions and changes in estimates, $0.8m
was recorded as additions to intangible exploration and evaluation
assets, $1.8m as a reduction to oil and gas assets, $1.0m
recognised as receivables due from the Group's joint operation
partner and $0.4m charged to exploration expenditure written
off.
The utilisation of provisions during the period related to the
plugging and abandonment of the Halifax and Whirlwind wells.
2.6 Joint operation
In September 2018 the Group entered into a joint operation with
Spirit to share costs and risks associated with the Greater Warwick
Area (GWA) in exchange for granting Spirit a 50% interest in the
Group's Lincoln (P1368 South) and Warwick (P2294) licences. The
phased work programme includes a planned tie-back of a GWA well to
the Aoka Mizu FPSO, together with host modifications to the vessel
and a gas export tie-in to the West of Shetland Pipeline System
('WOSPS'). This work was initially to be split across Phase 1
(Hurricane fully carried up to a gross cost of $180.6 million) and
Phase 2 (Hurricane 50% carried up to a gross cost of $187.5
million). As Phase 2 has not yet commenced, costs incurred from
inception above $180.6 million have been shared equally between the
joint operation partners.
With effect from 6 March 2020, a new cost allocation framework
was implemented whereby the joint operation will build-out the
equipment and materials required to tie-back a single well from the
GWA to the Aoka Mizu FPSO on a 50:50 basis. On completion, these
items will be held in storage until the joint operation sanctions
the tie-back of a well to the Aoka Mizu FPSO, with the required
regulatory consents to do so.
Hurricane can elect to continue to build-out long-lead items
related to the tie-in of the Aoka Mizu FPSO to WOSPS on a sole
basis. While Hurricane has no current plans to proceed with the
WOSPS installation, in the event that a decision is taken in future
to proceed, subject to the required approvals and consents,
Hurricane would bear 100% of the associated costs, and would
reimburse Spirit for related gas export past costs up to 31 January
2020 (excluding carry) of approximately $18.0 million (only where
installation occurs prior to the partners approval of Phase 2).
If at any time Phase 2 is approved and a GWA tie-back to the
Aoka Mizu FPSO proceeds, Hurricane will benefit from the original
terms of the 2018 farm-in through retrospective application of the
carry in the proportions originally agreed.
The Group currently acts as operator of the joint operation and
will continue to do so until full field development workstreams
commence.
Amounts due from and to the joint operation partner are shown in
notes 4.2 and 4.3 respectively.
Further details on the activities and progress of the joint
operation are described in the Interim Chief Executive Officer's
review above.
2.7 Commitments
30 Jun 2020 30 Jun 2019 31 Dec 2019
$'000 $'000 $'000
Contractual commitments for acquisition/construction
of oil and gas assets 11,847 1,873 4,299
Contractual commitments for acquisition/construction
of intangible exploration and
evaluation assets 4,624 - 17,127
Minimum undiscounted value of
leases not yet commenced - -- 20,358
----------------------------------------------------- ----------- ----------- -----------
Section 3 Income Statement
3.1 Earnings per share
6 months 6 months 12 months
ended ended ended
30 Jun 2020 30 Jun 2019 31 Dec 2019
$'000 $'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) (307,740) (21,246) 58,675
Add back impact of:
Convertible Bond - interest expense
not capitalised n/a n/a 16,417
Convertible Bond - depreciation
of interest capitalised in the year n/a n/a 738
Convertible Bond - fair value gain n/a n/a (34,691)
-------------------------------------- ------------- ------------- -------------
(Loss)/profit attributable to holders
of Ordinary Shares in the Company
used in calculating diluted earnings
per share (307,740) (21,246) 41,139
-------------------------------------- ------------- ------------- -------------
Number Number Number
Weighted average number of Ordinary
Shares used in calculating basic
earnings per share 1,989,515,103 1,965,389,894 1,978,513,120
Potential dilutive effect of:
Convertible Bond n/a n/a 442,307,692
-------------------------------------- ------------- ------------- -------------
Weighted average number of Ordinary
Shares and potential Ordinary Shares
used in calculating diluted earnings
per share 1,989,515,103 1,965,389,894 2,420,820,812
-------------------------------------- ------------- ------------- -------------
Cents
Basic (loss)/earnings per share (15.47) (1.08) 2.97
Diluted (loss)/earnings per share (15.47) (1.08) 1.70
-------------------------------------- ------------- ------------- -------------
The potential effect of the conversion feature included within
the Convertible Bond, and the effect of outstanding share awards
and options, was antidilutive for the 6 months ended 30 June 2020
and 30 June 2019 as the Group incurred a loss.
For the 12 months ended 2019 the impact of share awards was
antidilutive 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 as the adjusted exercise
prices were in excess of the average market price of Ordinary
Shares during the relevant periods.
3.2 Finance income and costs
6 months 6 months 12 months
ended ended ended
30 Jun 2020 30 Jun 2019 31 Dec 2019
Note $'000 $'000 $'000
Interest income on cash, cash
equivalents and liquid investments 843 619 1,453
Net foreign exchange gains - - 288
----------------------------------------- ---- ----------- ----------- -----------
Finance income 843 619 1,741
----------------------------------------- ---- ----------- ----------- -----------
Convertible Bond interest expense 5.1 (13,118) (12,511) (25,490)
Interest on lease liabilities 5.2 (3,846) (1,037) (4,972)
Unrealised fair value losses
on oil price derivatives 4.4 (878) - -
Other interest expense and
bank charges (121) (935) (1,495)
Net foreign exchange losses (650) (201) -
Unwinding of discount on decommissioning
provisions 2.5 (117) (204) (323)
----------------------------------------- ---- ----------- ----------- -----------
Finance costs incurred (18,730) (14,888) (32,280)
Interest capitalised - 9,074 9,074
----------------------------------------- ---- ----------- ----------- -----------
Finance costs (18,730) (5,814) (23,206)
----------------------------------------- ---- ----------- ----------- -----------
Total net finance costs (17,887) (5,195) (21,465)
----------------------------------------- ---- ----------- ----------- -----------
Section 4 Cash, working capital and financial instruments
4.1 Cash and cash equivalents
31 December
30 June 2020 30 June 2019 2019
$'000 $'000 $'000
Unrestricted cash and cash equivalents
(current) 123,170 81,399 156,591
Restricted cash and cash equivalents
(current) 20,053 15,374 11,778
---------------------------------------- ------------ ------------ -----------
Current cash and cash equivalents 143,223 96,773 168,369
Restricted cash and cash equivalents
(non-current) 2,881 2,967 3,065
---------------------------------------- ------------ ------------ -----------
Total cash and cash equivalents 146,104 99,740 171,434
---------------------------------------- ------------ ------------ -----------
Of which:
Unrestricted 123,170 81,399 156,591
Restricted 22,934 18,341 14,843
---------------------------------------- ------------ ------------ -----------
146,104 99,740 171,434
--------------------------------------- ------------ ------------ -----------
Included within restricted cash and cash equivalents is $20.1
million (30 June 2019: $nil; 31 December 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 an
amount to ensure it could meet its liability to pay an early
termination fee to the lessor.
At the end of 2018, as agreed with the OGA, GBP16.8 million was
held in trust to cover the post-tax cost of decommissioning the
Lancaster EPS and was accounted for as a non-current restricted
liquid investment and recognised within non-current assets. In
February 2019, the Group replaced this cash security held in trust
with a decommissioning bond of the same value. Under the terms of
the agreement with the bond provider, the original funds were able
to be released back to the Group in tranches once specific
production milestones were met. At 30 June 2019, the funds not yet
released were included within current restricted cash and cash
equivalents. The required production milestones were all achieved
by September 2019, and thus the full GBP16.8 million ($21.7
million) was released back to unrestricted cash by the end of 2019.
Under the terms of the bond, the bond provider can recall all or
part of bond at any time if they believe the Company's financial
position has deteriorated. Should this occur then the amounts may
be recalled, placed back into trust and reclassified as restricted
cash.
All the non-current restricted cash and cash equivalents
balances are held in escrow for future costs associated with the
Group's decommissioning obligations.
The carrying amounts of cash and cash equivalents and liquid
investments are considered to be materially equivalent to their
fair values.
4.2 Trade and other receivables
30 Jun 2020 30 Jun 2019 31 Dec 2019
$'000 $'000 $'000
Receivables due from joint
operation partner 17,759 51,509 47,519
Trade receivables 17,414 269 723
Prepayments 1,256 712 1,066
Other receivables 289 2,654 1,127
------------------------------ ----------- ----------- -----------
Trade and other receivables 36,718 55,144 50,435
------------------------------ ----------- ----------- -----------
The carrying amounts of trade and other receivables are
considered to be materially equivalent to their fair values and are
unsecured. Joint operation receivables represent expenses incurred
by the Group as operator of the joint operation which will be
recovered from the Group's joint operation partner. Amounts billed
to the joint operation partner accrue interest at LIBOR and are
generally due for settlement within ten days.
4.3 Trade and other payables
30 Jun 2020 30 Jun 2019 31 Dec 2019
$'000 $'000 $'000
Amounts due to joint operation
partner 1,120 - 5,371
Trade payables 9,500 27,799 647
Other payables 616 2,237 654
Accruals 43,716 57,368 65,697
--------------------------------- ----------- ----------- -----------
Trade and other payables 54,952 87,404 72,369
--------------------------------- ----------- ----------- -----------
The carrying amounts of trade and other payables are considered
to be materially equivalent to their fair values and are unsecured.
Trade and other payables are non-interest bearing and generally
payable within 30 days.
Trade and other payables and accruals include the Group's share
of joint operation payables, including amounts that the Group
settles on behalf of joint operation partners. Accruals includes
expenditure relating to joint operations incurred by the Group as
operator which have yet to be billed to joint operation partners.
Amounts due to the joint operation partner represent cash calls the
Group has made as operator in advance of balances relating to the
joint operation falling due.
4.4 Derivative financial instruments
In June 2020, the Group hedged a portion of its forecast
production for the second half of 2020 via the purchase of put
options at a total cost of $3.4 million. The options would result
in upside to the Group if the average Dated Brent price over the
option term is below the strike price.
The options are classified as Level 2 financial instruments
within the IFRS fair value hierarchy and have not been classified
as hedging instruments in a hedge relationship under IFRS 9.
Fair value
at
Put option commodity Term Notional Strike price 30 June
quantity 2020
bbl $/bbl $'000
1 July 2020 - 31 December
Dated Brent 2020 900,000 34.55 1,270
1 July 2020 - 31 December
Dated Brent 2020 900,000 35.50 1,272
--------- ----------
1,800,000 2,542
--------- ----------
The fair value loss of $0.9 million in the period has been
recognised within finance costs.
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 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, where applicable, 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's carrying value is split between a debt
component (the host contract) measured at amortised cost (with an
effective interest rate of 13.5%) and an embedded derivative
component measured at fair value.
The amounts recognised in the Financial Statements relating to
the Convertible Bond, being all 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 (8,625) - (8,625)
Fair value loss - 23,466 23,466
Interest charged 12,511 - 12,511
------------------------------- -------------- -------------------- --------
Carrying value at 30 June
2019 202,250 94,473 296,723
Cash interest paid (8,625) - (8,625)
Fair value gain - (58,157) (58,157)
Interest charged 12,979 - 12,979
Carrying value at 31 December
2019 206,604 36,316 242,920
Cash interest paid (8,625) - (8,625)
Fair value gain - (33,956) (33,956)
Interest charged 13,118 - 13,118
------------------------------- -------------- -------------------- --------
At 30 June 2020 211,097 2,360 213,457
------------------------------- -------------- -------------------- --------
Fair value at 30 June
2019 243,151 94,473 337,624
------------------------------- -------------- -------------------- --------
Fair value at 31 December
2019 235,852 36,316 272,168
------------------------------- -------------- -------------------- --------
Fair value at 30 June
2020 115,000 2,360 117,360
------------------------------- -------------- -------------------- --------
The Convertible Bond contains covenants relating to the
restrictions on incurrence of certain indebtedness. These covenants
were complied with for the current and prior periods. Further
details on the Convertible Bond and its covenants are disclosed in
note 5.1 to the Group's 2019 Annual Report and Financial
Statements.
The embedded derivative component of the Convertible Bond has
been assessed to be a Level 2 financial liability, as the valuation
has been calculated using the Black-Scholes option pricing model
using direct and indirect observable inputs. The key inputs used
are share price volatility (calculated as the volatility of one
Hurricane Ordinary Share over two years period to the measurement
date) and the price of one Ordinary Share at 30 June 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 bonds were considered. The likelihood of each was considered to
be nil for the purposes of the valuation.
The fair value calculation at 30 June 2020 used a share price
volatility assumption of 88.3 % (31 December 2019: n/a; 30 June
2019: 27.5%) and the price of one Hurricane Energy plc Ordinary
Share as at the balance sheet date of GBP0.058 (31 December 2019:
GBPn/a; 30 June 2019: GBP0.52). The sensitivity of a reasonably
possible increase or decrease of those inputs to the Group's profit
before tax for the period ended 30 June 2020 is summarised below,
assuming all other variables were held constant:
Gain/(loss)
$'000
------------------------------------ ------------
Share price volatility assumption:
20% points increase (2,818)
20% points decrease 1,752
Share price at balance sheet date:
GBP0.05 increase (6,997)
GBP0.05 decrease 2,352
------------------------------------ ------------
The valuation as at 31 December 2019 was derived by deducting
the estimated fair value of the debt component (using an equivalent
bond yield 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
6 months 6 months 12 months
ended ended ended
30 Jun 2020 30 Jun 2019 31 Dec 2019
$'000 $'000 $'000
At start of period 99,186 3,323 3,323
New leases - 96,361 96,361
Cash payments of principal
and interest (4,836) (701) (5,556)
Interest charged 3,846 1,037 4,972
Foreign exchange movements (172) 5 86
At end of period 98,024 100,025 99,186
----------------------------- ----------- ----------- -----------
Of which:
Current 9,463 9,482 9,501
Non-current 88,561 90,543 89,685
----------------------------- ----------- ----------- -----------
98,024 100,025 99,186
--------------------------- ----------- ----------- -----------
The Group's main lease is the bareboat charter of the Aoka Mizu
FPSO for which the Group makes fixed payments (which are included
within the lease liability measurement) and variable payments
(which are based on a percentage of the quantity and price of crude
oil sold, and recognised as an expense in the period in which the
related sales are made - see note 2.2).
5.3 Maturity analysis of financial liabilities
The maturity analysis of contractual undiscounted cash flows for
non-derivative financial liabilities is as follows:
Less than More than
6 months 6-12 months 1-2 years 2-5 years 5 years Total
$'000 $'000 $'000 $'000 $'000 $'000
Trade payables
and accruals 54,952 - - - - 54,952
Convertible Bond
interest 8,625 8,625 17,250 4,313 - 38,813
Lease liabilities 4,803 4,778 27,654 83,322 1,446 122,003
------------------ --------- ----------- --------- --------- --------- -------
At 30 June 2020 68,380 13,403 44,904 87,635 1,446 215,768
------------------ --------- ----------- --------- --------- --------- -------
Less than More than
6 months 6-12 months 1-2 years 2-5 years 5 years Total
$'000 $'000 $'000 $'000 $'000 $'000
Trade payables
and accruals 87,404 - (-) (-) - 87,404
Convertible Bond
interest 8,625 8,625 17,250 21,563 - 56,063
Lease liabilities 4,859 4,832 9,594 83,323 29,180 131,788
------------------ --------- ----------- --------- --------- --------- -------
At 30 June 2019 100,888 13,457 26,844 104,886 29,180 275,255
------------------ --------- ----------- --------- --------- --------- -------
Less than More than
6 months 6-12 months 1-2 years 2-5 years 5 years Total
$'000 $'000 $'000 $'000 $'000 $'000
Trade payables
and accruals 72,370 - - - - 72,370
Convertible Bond
interest 8,625 8,625 17,250 12,938 - 47,438
Lease liabilities 4,843 4,818 18,583 83,469 15,336 127,049
------------------ --------- ----------- --------- --------- --------- -------
At 31 December
2019 85,838 13,443 35,833 96,407 15,336 246,857
------------------ --------- ----------- --------- --------- --------- -------
Not included within the tables above is the Convertible Bond
principal of $230 million which, unless previously converted into
Ordinary Shares, redeemed or cancelled, is due to be redeemed on 24
July 2022 (see note 5.1).
At 30 June 2020, $17.8 million (31 December 2019: $42.5 million)
was due from the Group's joint operation partner to settle trade
payables and accruals relating to the joint operation (see note
4.3).
5.4 Share capital
Ordinary $'000
Shares
----------------------------------- ------------- -----
At 1 January 2019 1,959,551,637 2,843
Shares issued under warrants and
rights (at GBP0.20 per share) 29,860,834 39
Shares issued under employee share
schemes 815,582 1
-------------------------------------- ------------- -----
At 30 June 2019 and 31 December
2019 1,990,228,053 2,883
-------------------------------------- ------------- -----
Shares issued under employee share
schemes 1,643,503 2
-------------------------------------- ------------- -----
At 30 June 2020 1,991,871,556 2,885
-------------------------------------- ------------- -----
The Company has one class of Ordinary Share, which has a par
value of GBP0.001.
In May 2019, Crystal Amber exercised warrants allowing it to
subscribe for 23,333,333 Ordinary Shares at GBP0.20 per share.
Kerogen Capital subsequently exercised a related right to subscribe
for 6,527,501 Ordinary Shares at GBP0.20 per share. The gross
proceeds received from these warrants and rights was $7,782,000. No
transaction costs were incurred by the Group relating to the issue
of these shares. Following the full exercise of these warrants and
rights, there are no outstanding warrants or rights relating to the
Company's Ordinary Shares.
Section 6 Tax
6.1 Tax charge/credit for the period
6 months 6 months 12 months
ended ended ended
30 Jun 2020 30 Jun 2019 31 Dec 2019
$'000 $'000 $'000
UK corporation tax
Current tax - prior years - 6,235 6,259
----------------------------------------- ----------- ----------- -----------
Total current tax - 6,235 6,259
----------------------------------------- ----------- ----------- -----------
Deferred tax - current year (49,262) - 90,226
Effect of changes in tax rates - - (35,998)
Total deferred tax (49,262) - 54,228
----------------------------------------- ----------- ----------- -----------
Tax (charge)/credit per Income Statement (49,262) 6,235 60,487
----------------------------------------- ----------- ----------- -----------
Loss on ordinary activities before
tax (258,478) (27,481) (1,812)
----------------------------------------- ----------- ----------- -----------
Loss on ordinary activities multiplied
by standard rate of corporation tax
in the UK applicable to oil and gas
companies of 40% 103,391 10,992 725
Effects of:
R&D tax credit - 6,235 6,259
Expenses not deductible for tax
purposes (2,432) (948) (1,724)
Income not chargeable for tax purposes 6,285 - 4,211
Items taxed at rates other than
the standard rate of 40% (6,946) - (278,873)
Ring fence expenditure supplement - - 22,057
Recognition of deferred tax not
previously recognised - - 307,832
Derecognition of losses and losses
not recognised (149,560) (10,044) -
----------------------------------------- ----------- ----------- -----------
Total tax (charge)/credit for the
period (49,262) 6,235 60,487
----------------------------------------- ----------- ----------- -----------
The tax charge for the period of $49.3 million wholly relates to
the derecognition of most of the deferred tax asset previously
recognised at 31 December 2019, following a downwards revision to
estimated future taxable profits. Estimates of future taxable
profits were made using the Group's corporate cash flow model,
using assumptions consistent with that used in testing the
Lancaster oil and gas assets for impairment (as outlined in note
1.4.1). The results of the review concluded that there would be
sufficient forecast taxable future profits to recognise a deferred
tax asset of $5.0 million (30 June 2019: $nil; 31 December 2019:
$54.3 million), resulting in a deferred tax charge of $49.3 million
for the period.
In 2018 the Group made a claim under the SME Research &
Development tax relief scheme in respect of the 2016 and 2017
financial years and 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.
6.2 Deferred tax
6 months ended 6 months ended 12 months
ended
30 Jun 2020 30 Jun 2019 31 Dec 2019
$'000 $'000 $'000
Accelerated capital allowances (95,482) 216,049 (168,626)
Other timing differences - (1) 448
Tax losses carried forward 100,530 216,048 222,489
------------------------------- -------------- -------------- -----------
Deferred tax asset 5,048 - 54,311
------------------------------- -------------- -------------- -----------
Tax losses of $241.2 million (30 June 2019: $540.1 million; 31
December 2019: $487.9 million) have been offset against deferred
tax liabilities primarily related to fixed assets. Based on future
forecasts of interest expense that is not allowable against profits
subject to the supplementary charge a deferred tax asset of $5.0
million has been recognised in relation to supplementary charge
losses that will be used to cover this amount. A potential deferred
tax asset of $53.9 million has not been recognised, as it has been
concluded that it is not appropriate to recognise any of this
potential deferred tax asset until the Technical Review has been
concluded and there is further certainty over forecast production
profiles. A further $38.7 million relates to pre-trading
expenditure losses not recognised, and includes potential claims
for ring fence expenditure supplement ('RFES'). The recognised and
unrecognised potential deferred tax assets relate to different
types of tax loss, each being calculated at a different rate, the
highest being that applicable to UK ring-fence profits of 30%.
6.3 Factors which may affect future tax charges
The quantum of the deferred tax asset recognised, and
corresponding deferred tax charge or credit, is highly dependent on
management's estimates of future cash flows and taxable income.
Changes to estimates of future taxable profits will occur in future
periods due to movements in forecast oil prices, finalisation of
estimated reserves and resources, and the sanction or otherwise of
capital projects.
The Group has ring-fenced trading losses of $562.3 million at 30
June 2020 and supplementary charge losses and allowances of $820.9
million which have no expiry date and would be available for offset
against future trading profits. A potential RFES claim could also
be made for the current accounting period which would result in
additional trading losses of $56.2 million based on the position at
30 June 2020.
In addition to the above, the Group has pre-trading expenditure
of $118.4 million which is carried forward at 30 June 2020, and tax
relief will be available when FDP approval is obtained on the
remaining licences (this expenditure could also be uplifted by RFES
to $145.7 million).
Section 7 Other disclosures
7.1 Related party transactions
Related party transactions during the period comprise
remuneration and fees paid to directors, who are considered the
Group's key management personnel.
In May 2019, Kerogen Investments No. 18 Limited, a company
controlled by Kerogen Capital (which is a related party of the
Company due to the size of its shareholding and the provision of
key management personnel services to the Company), executed a
subscription right for 6,527,501 Ordinary Shares in the Company at
GBP0.20 per share.
7.2 Subsequent events
7.2.1 Preliminary conclusions of the Technical Review
The initial results and findings of the Technical Review are
included within the Interim Results Summary, Interim Chief
Executive Officer's Review, and Technical Review sections of this
announcement above.
7.2.2 P2294 licence extension
In August 2020, the P2294 licence (in which the Group has a 50%
interest) was extended into its second term. The licence now
expires in August 2023.
Appendix A: Glossary
2C contingent Best case contingent resources under the Society
resources of Petroleum Engineers' Petroleum Resources
Management System
2P reserves Proved plus probable reserves under the Society
of Petroleum Engineers' Petroleum Resources
Management System
------------------------------------------------------
AIM The AIM market of the London Stock Exchange
------------------------------------------------------
Aoka Mizu The Aoka Mizu FPSO
------------------------------------------------------
Bopd Barrels of oil per day
------------------------------------------------------
Company Hurricane Energy plc and/or its subsidiaries
------------------------------------------------------
CEO Chief Executive Officer
------------------------------------------------------
CFO Chief Financial Officer
------------------------------------------------------
Convertible Bond $230 million of 7.5% convertible bonds issued
by the Company in July 2017
------------------------------------------------------
COO Chief Operating Officer
------------------------------------------------------
CPR Competent Persons Report
------------------------------------------------------
EPS Early production system
------------------------------------------------------
ESP Electrical submersible pump
------------------------------------------------------
FDP Field development plan
------------------------------------------------------
FPSO Floating production storage and offloading
vessel
------------------------------------------------------
GLA Greater Lancaster Area, comprising the Lancaster
and Halifax fields located on UKCS licences
P.1368 Central and P.2308
------------------------------------------------------
the Group Hurricane Energy plc, together with its subsidiaries
------------------------------------------------------
GWA Greater Warwick Area, comprising the Lincoln
and Warwick fields located on UKCS licences
P.1368 South and P.2294
------------------------------------------------------
Hurricane Hurricane Energy plc and its subsidiaries
------------------------------------------------------
IFRS International Financial Reporting Standards
as adopted by the European Union
------------------------------------------------------
MMbbls Million barrels of oil
------------------------------------------------------
OGA Oil and Gas Authority
------------------------------------------------------
Onlap A geological phenomenon where successive wedge-shaped
younger rock strata extend progressively further
across an erosion surface cut in older rocks
------------------------------------------------------
Ordinary Shares Ordinary shares in the Company of GBP0.001
each
------------------------------------------------------
PP&E Property, Plant and Equipment
------------------------------------------------------
Spirit Spirit Energy Limited
------------------------------------------------------
Tier 1 contractors Hurricane's major direct contractors
------------------------------------------------------
UKCS United Kingdom Continental Shelf
------------------------------------------------------
UOP Unit of production
------------------------------------------------------
WOSPS West of Shetland Pipeline System
------------------------------------------------------
Appendix B: Non-IFRS measures
Management believe s that certain non-IFRS measures (also
referred to as 'alternative performance measures') are useful
metrics as they provide additional useful information on
performance and trends. These measures are used by management for
internal performance analysis and incentive compensation
arrangements for directors and employees. The non-IFRS measures
presented below are not defined in IFRS or other GAAPs and
therefore may not be comparable with similarly described or defined
measures reported by other companies. They are not intended to be a
substitute for, or superior to, IFRS measures.
Definitions and reconciliations to the nearest equivalent IFRS
measure are presented below.
Underlying profit before tax
Underlying profit before tax is defined as profit before tax
under IFRS, before fair value gains or losses on the Convertible
Bond embedded derivative, fair value gains or losses on derivatives
not designated as hedging instruments in a hedging relationship,
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 believe 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 outwith management's
control); and gains or losses arising from write-offs, impairments
and disposals of assets which do not reflect the Group core assets
and 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.
6 months 6 months 12 months
ended ended ended
Note 30 Jun 2020 30 Jun 2019 31 Dec 2019
$'000 $'000 $'000
Loss before tax (IFRS measure) (258,478) (27,481) (1,812)
Add back:
Fair value (gain)/loss on
Convertible Bond embedded
derivative 5.1 (33,956) 23,466 (34,691)
Fair value loss on unhedged
derivative financial instruments 4.4 878 - -
Impairment and write-off
of intangible exploration
and evaluation assets 2.4 12,537 - 66,468
Impairment of oil and gas
assets 2.3 238,853 - -
----------------------------------- ---- ----------- ----------- -----------
Underlying (loss)/profit before
tax (40,166) 4,015 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.
Depreciation and movements in crude oil inventory are deducted
as they are non-cash accounting adjustments to cost of sales. Fixed
lease payments 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
cost per barrel is defined as cash operating costs divided by
production volumes.
Management believe that cash production costs, and cash
production cost per barrel are useful measures as they remove
non-cash elements from cost of sales, assist with cashflow
forecasting and budgeting, and provide indicative breakeven amounts
for the sale of crude oil.
6 months 6 months 12 months
ended ended ended
Note 30 Jun 2020 30 Jun 2019 31 Dec 2019
$'000 $'000 $'000
Cost of sales (IFRS measure) 2.2 101,476 16,740 118,453
Less:
Depreciation of oil and gas
assets - owned 2.3 (48,348) (9,423) (54,406)
Depreciation of oil and gas
assets - leased 2.3 (7,258) (1,404) (8,210)
Movements in crude oil inventory 2.2 (2,113) 5,572 4,424
Add:
Fixed lease payments payable
for oil and gas assets 4,550 1,161 5,761
---------------------------------- ---- ----------- ----------- -----------
Cash production costs 48,307 12,646 66,022
---------------------------------- ---- ----------- ----------- -----------
Production volumes 2,658 kbbl 528 kbbl 3,030 kbbl
Cash production cost per barrel $18.2/bbl $24.0/bbl $21.8/bbl
Net free cash and net debt
Net free cash is defined as current unrestricted cash and cash
equivalents, plus current financial trade and other receivables,
current oil price derivatives, less current financial trade and
other payables.
Management believe 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 in July 2022 (unless previously converted, redeemed or
purchased and cancelled).
Management believe that net debt is a useful measure as it aids
stakeholders in understanding the current financial position of the
Company.
Note 30 Jun 2020 30 Jun 2019 31 Dec 2019
$'000 $'000 $'000
Cash and cash equivalents (IFRS
measure) 4.1 146,104 99,740 171,434
Add:
Trade and other receivables 4.2 36,718 55,144 50,435
Derivative financial instruments 4.4 2,542 - -
Less:
Restricted cash and cash equivalents 4.1 (22,934) (18,341) (14,843)
Prepayments 4.2 (1,256) (712) (1,066)
Trade and other payables 4.3 (54,952) (87,404) (72,369)
Net free cash 106,222 48,427 133,591
-------------------------------------- ---- ----------- ----------- -----------
Par value of Convertible Bond 5.1 (230,000) (230,000) (230,000)
-------------------------------------- ---- ----------- ----------- -----------
Net debt (123,778) (181,573) (96,409)
-------------------------------------- ---- ----------- ----------- -----------
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