TIDMPMO
RNS Number : 6386S
Premier Oil PLC
18 March 2021
Premier Oil plc
"Premier" or the "Company" or the "Group"
18 March 2021
Press Release
Corporate transaction highlights
-- Proposed merger with Chrysaor to create Harbour Energy plc, a
cash-generative London-listed oil and gas company of scale with a
strong balance sheet and significant international growth
opportunities
-- Forecast net debt of Combined Group on completion of US$2.9
billion (previously US$3.2 billion), reflecting higher commodity
prices and full take up of Harbour Energy shares by creditors
-- Completion of Chrysaor merger expected 31 March 2021, with
shares to be readmitted to trading on 1 April as Harbour Energy
plc
- Shareholder and creditor approvals received, regulatory
conditions satisfied and anti-trust clearances granted
- Court sanction hearing scheduled for 19 March 2021
Premier operational highlights
-- 2020 production averaged 61.4 kboepd (2019: 78.4 kboepd);
Premier's 2021 guidance of 61-66 kboepd reiterated (excludes
Chrysaor assets)
-- Tolmount: platform installed and first of the four
development wells successfully completed. First gas on track for Q2
2021, adding 20-25 kboepd (net) once at plateau later in 2021
-- Significant growth optionality retained
- Zama (Mexico): FEED completed, unitisation progressed; project sanction targeted end 2021
- Tuna (Indonesia): Fully funded appraisal of c. 100 mmboe (gross) field to start in Q2 2021
- Sea Lion (Falkland Islands) licence extension and farm down arrangements agreed
- Highly encouraging results from new 3D seismic data sets
across Indonesia and Mexico exploration acreage
Premier financial highlights and outlook
-- Operating cash flow of US$630 million (2019: US$1,080
million) with a net cash outflow of US$90 million; 2020 year-end
net debt of US$2,078 million (2019: US$1,990 million)
-- US$1,302 million loss after tax (2019: US$164 million profit
after tax) driven by one-off non-cash charges, including US$817
million relating to the partial derecognition of Premier's UK ring
fence tax losses and allowances which are expected to be
re-recognised on completion of the Chrysaor merger
-- 2020 operating costs (ex-lease costs) of US$12.2/boe and full
year total capex (including decommissioning spend) of US$315
million, reflecting full year savings and deferrals of over US$250
million
-- 2021 guidance of US$15/boe operating costs (ex-lease costs)
is unchanged. 2021 total capex guidance is expected to be
approximately US$300 million capex (previously US$275 million),
reflecting phasing of some costs from 2020 and increased Balmoral
Area decommissioning spend
-- Premier's total gross debt of c. US$2.7 billion, which
includes letters of credit and certain hedging liabilities, to be
repaid and cancelled on completion of the merger with Chrysaor
Chrysaor 2020 highlights
Chrysaor has published on its website today its full year
results for the year ending 31 December 2020 and has provided
Premier with the following highlights:
-- Production in 2020 of 173 kboepd (2019: 137 kboepd), in line
with guidance, and underpinned by a full year's contribution from
the assets acquired from ConocoPhillips and exceptionally high
uptime; 2021 production forecast of 140-155 kboepd unchanged
-- Free cash flow after capex, tax and interest of US$562
million, underpinned by increased production, a strong hedging
programme and capex deferrals
-- EBITDAX of US$1,784 million (2019: US$1,692 million). Loss
after tax of US$778 million (2019: US$218 million profit)
reflecting one off non-cash impairment charges of US$1,055 million
driven by weaker commodity prices and movements in foreign exchange
rates compared to the outlook before the pandemic
-- Chrysaor's operating costs (including net tariff costs)
averaged US$11.5/boe; 2021 guidance of less than US$15/boe
operating costs (including net tariff costs) unchanged
-- 2020 total capex (including exploration and decommissioning)
was US$718 million, approximately US$575 million lower than
forecast at the outset of the year; 2021 capex guidance of
US$750-850 million, including US$170 million for decommissioning
(pre-tax relief), unchanged
-- Significant hedging programme with 74% of 2021 oil volumes
and 85% of 2021 gas volumes hedged at an average price of US$58/boe
and 44 pence/therm, respectively
The above Chrysaor highlights are not subject to EY audit.
Enquiries
Premier Oil plc Tel: 020 7730 1116
Richard Rose, Interim Chief Executive, Finance Director
Elizabeth Brooks, Head of Investor Relations
Camarco Tel: 020 3757 4983
Billy Clegg
Georgia Edmonds
Notes to editors
Premier's quoted production numbers includes fuel gas whereas
Chrysaor's quoted production numbers reflect actual sales.
Chairman overview
2020 delivered some of the most challenging times for the
upstream oil and gas sector. The outbreak of the COVID-19 pandemic
and ensuing deep global economic slowdown, together with a
geopolitical oil price war, caused significant commodity price
weakness and volatility during the first half of the year.
Supported by extended record OPEC supply cuts and positive vaccine
related news, oil prices recovered into year-end and the global
demand and supply position is now more balanced although society's
concerns around energy transition and climate change continue to
weigh on the sector.
We are proud of the quick action that Premier took in response
to the pandemic to ensure the health and safety of our employees
and contractors, both offshore and onshore. We adapted working
practices and protocols to allow us to continue to operate our
business safely. This enabled us to deliver full-year production of
61.4 kboepd and, while that was lower than envisaged at the start
of the year, it is testament to the skill and dedication of our
teams that we maintained safe and responsible operations despite
the difficult operating environment.
The Company also responded quickly to minimise expenditure and
protect cash flows. Safety-critical maintenance and capital
investments in high-return projects which impacted near-term
production were prioritised while discretionary expenditure with
longer payback periods was deferred. This, together with the
continued underlying performance of Premier's assets, partially
mitigated the financial impact of low commodity prices on the
Group.
Alongside these actions Premier re-engaged with its creditors to
secure a long-term refinancing of the business. In September,
Premier was in the process of seeking creditor approval for the
refinancing of its debt facilities alongside the acquisition of
certain producing assets from BP when the Group was approached by
Chrysaor with a merger proposal. Given the market conditions at
that time, it was felt that an all share merger with Chrysaor had
greater execution certainty for stakeholders than the standalone
solution which was dependent upon a significant equity raise. As a
result, in October 2020 the Board unanimously recommended the
merger to shareholders who approved it at a General Meeting in
January 2021. The merger with Chrysaor remains on track to complete
at the end of March 2021, upon which Premier Oil plc will be
renamed Harbour Energy plc.
Harbour Energy will bring together two complementary businesses
to create the largest London-listed independent oil and gas
company, by production and reserves. It will have a cash-generative
diversified UK business with a significant operated position. In
addition, Harbour Energy will have a broad set of international
growth opportunities with the financial flexibility and capacity to
realise value from a top-tier development and exploration portfolio
as well as from a disciplined M&A strategy. Harbour Energy will
have a strong balance sheet from day one and is expected to
generate sufficient free cash flow to support shareholder returns,
including via a sustainable dividend in the near-term, subject to
market conditions.
Environmental, Social and Governance (ESG) issues remained a key
priority during 2020 and, for oil and gas companies in particular,
the carbon footprint of our industry is a key focus. Premier
recognises the need to respond to climate change and the critical
role of the energy industry in addressing these environmental
challenges. In March, Premier committed to developing all of its
operated projects on a carbon neutral basis. Harbour Energy will
have the scale and balance sheet to build on Premier's progress in
this area, and has committed to attaining the goal of Net Zero
across its operations by no later than 2035, well in advance of the
UK government goal of 2050.
I, along with my fellow Directors, recognise the challenging
circumstances and the personal impact on our employees that has
resulted from the COVID-19 pandemic and would like to take this
opportunity to thank them for their continued dedication, hard work
and support. I would also like to note the significant
contributions made by Tony Durrant and Robin Allan, both of whom
left Premier in 2020. As we look forward to the start of a new and
exciting chapter in Premier's long history, I firmly believe that
Harbour Energy has all of the ingredients, including scale, a
strong balance sheet and an experienced management team, to allow
the Group to prosper whilst playing its part in the energy
transition and delivering value for all of its stakeholders.
CEO Review
During 2020, Premier continued to safeguard its people,
completed and installed the Tolmount facilities offshore, and
preserved the optionality of its future growth projects whilst
maintaining production across its asset base. In addition, Premier
successfully negotiated a merger with Chrysaor, securing both
long-term value for stakeholders and a stronger balance sheet on
completion of the transaction.
Production and development operations
Production averaged 61.4 kboepd during 2020, a reduction on 2019
driven by lower uptime from the Catcher Area, the Group's largest
producing asset, and the acceleration of cessation of production
from some of Premier's more mature, high-cost UK fields. Increased
delivery capacity at year-end was supported by the successful
execution of operated infill wells on Catcher and Solan in the UK
and four well intervention campaigns in South East Asia.
UK production was 40.6 kboepd. This was underpinned by output
from Premier's operated Catcher Area. Despite lower uptime during
the year, the Catcher fields exited the year at plateau production
rates of 60 kbopd (gross, Premier 50 per cent), three years after
first oil. This is significantly ahead of the 18 month plateau at
50 kbopd envisaged at project sanction. Premier's operated South
East Asian assets delivered another robust performance in 2020,
benefitting from sustained high uptime and a continued low
operating cost base.
The Tolmount gas development is on track for first gas in the
second quarter of 2021. The Tolmount field will add 20-25 kboepd
(net, Premier 50 per cent) of production once at plateau rates,
contributing to a forecast Group 2021 production exit rate in
excess of 80 kboepd. In addition, Premier has made good progress
advancing Tolmount East, with a final investment decision targeted
during 2021. Once on-stream, Tolmount East will help maintain and
extend plateau production from the Tolmount Area.
Growth projects
Premier has an attractive portfolio of pre-development projects
which offer the potential for material future growth. During 2020
Premier sought to minimise and defer expenditure across its
operated projects to preserve cash while at the same time
continuing to optimise its level of participation in these
projects. In the Falkland Islands, Premier continued to progress
its operated 250 mmbbls Sea Lion Phase 1 project, albeit at a
reduced pace given the macro environment, while offshore Indonesia,
the Group successfully farmed down its Tuna PSC to Zarubezhneft who
will carry Premier on a two well appraisal programme in 2021.
In Mexico, the Block 7 (Premier 25 per cent interest) partners
and Pemex continued to progress the giant Zama field towards a
targeted late 2021 project sanction. 2020 saw completion of FEED on
the chosen development concept and significant progress in the
negotiations regarding the unitisation of the Zama field, which are
expected to conclude during the first half of 2021.
While 2020 saw Premier's exploration and appraisal drilling
campaigns deferred, the Group was highly encouraged by the seismic
data it received across its Indonesian, Mexican and UK licences.
Premier is particularly excited about its first exploration well on
its Andaman Sea acreage which is scheduled to be drilled in the
first half of 2022 and which is targeting a multi-TCF gas play with
access to commercial markets.
Harbour Energy will have the ability to fund and realise value
from Premier's top-tier development and exploration portfolio.
These projects will compete for capital with existing projects
within Chrysaor's portfolio as well as new business development
opportunities.
Reserves and resources
As at 31 December 2020, the Group's proven and probable (2P)
reserves, on a working interest basis, were 151 mmboe (2019: 175
mmboe) and total 2P and 2C resources were 845 mmboe (2019: 847
mmboe).
2P reserves 2P reserves and 2C
(mmboe) resources (mmboe)
1 January 2020 175 847
------------ -------------------
Production (23) (23)
------------ -------------------
Revisions, divestments (1) 21
------------ -------------------
31 December 2020 151 845
------------ -------------------
The reduction in 2P reserves is driven by the impact of 2020
production. Upward revisions in the Group's 2P reserves largely
related to the Catcher Area, due to better reservoir performance
and gas management strategy. This was offset by negative revisions
in Solan (UK) and Natuna Sea Block A (Indonesia) and earlier
cessation of production from a number of more mature UK fields.
The Group's 2C resources stood at 845 mmboe at year end. This
reflects a revision in 2C resources of 48 mmboe due to Premier's
working interest in the Tuna PSC increasing to 100 per cent prior
to completion of the farm out to Zarubezhneft post period end. This
was partially offset by the removal of 2C resources associated with
a number of UK fields which ceased production in 2020.
Finance and proposed merger with Chrysaor
At the outset of the year, Premier expected to generate material
free cash flow in 2020, based on its budgeted commodity price
assumptions. While Premier was quick to respond to the collapse in
oil prices, securing some US$250 million of cost savings and
deferrals across opex and capex, the Group reported a cash outflow
for the year of US$90 million. This resulted in an increased
year-end net debt position of US$2,078 million (2019: US$1,989
million).
In October, Premier announced the proposed merger with Chrysaor,
upon completion of which, Chrysaor and its shareholders will repay
and cancel all of Premier's existing gross debt and cross currency
hedging liabilities. Net debt of the Combined Group on completion
is expected to be approximately US$2,900 million.
Formal shareholder and creditor approval and Mexico and Vietnam
anti-trust clearances were received post year-end. The UK and
Falkland Islands regulatory conditions to the merger were also
satisfied in the first quarter of 2021 and the merger remains on
track to complete by the end of March 2021.
Environmental, Social and Governance (ESG)
A company's success is not only determined by its financial
performance, but also by its health, safety and environmental
performance. It is the Group's highest priority to continue to
operate all of its assets in a safe and responsible manner, to
ensure the health and safety of its workforce and to minimise the
potential risk to the environment. We have set ourselves ambitious
targets to become a carbon neutral enterprise through being Low
Carbon by Design and Carbon Neutral by Commitment.
In 2020, Premier recorded no serious injuries or significant
spills and a Total Recordable Injury Rate (TRIR) of 0.68 per
million man hours worked. While any injury is one too many, this
marks the lowest TRIR recorded by Premier in over 10 years. In
addition, Premier's global operated production platforms across the
North Sea, Indonesia and Vietnam achieved two years without a lost
time injury.
During 2020, Premier's GHG intensity rose slightly to 21.1
kgCO(2) e/boe as a result of year-on-year reduction in production.
However overall CO(2) e gross emissions across the Group's operated
assets reduced by some 12 per cent to 820 thousand tonnes,
supported by the Group's focus on continuous improvement in its
emissions performance and its proactive decision to abandon some of
its older fields.
Outlook
As we enter 2021 with improving commodity prices, Premier's
focus is on maintaining its safe production performance and
competitive cost base whilst delivering first gas from its operated
Tolmount project. We look forward to completing the Zama
unitisation discussions with Pemex and executing the fully-carried
two-well appraisal programme of our Tuna field in Indonesia.
We are also excited about completing the merger with Chrysaor.
Harbour Energy will have a low cost base and a robust reserve and
resource base. The Combined Group will be well positioned to
generate material free cash flow, even at low commodity prices, and
to invest for growth on a global stage.
UK
UK production averaged 40.6 kboepd, a decrease on the prior
corresponding period due to lower uptime at Catcher and the
acceleration of cessation of production from several of the Group's
more mature, higher cost fields. Looking ahead, Tolmount at plateau
rates will result in Premier's UK tax advantaged production
increasing to over 60 kboepd at the end of 2021.
Catcher Area
Production from Premier's operated Catcher Area averaged 26.1
kboepd (net, Premier 50 per cent) (2019: 33.6 kboepd) during 2020
with the fields continuing to produce at plateau oil rates
supported by strong reservoir performance.
The reduction on 2019 was driven by certain one-off equipment
failures (gas pre-heater and HVAC switchboard) which resulted in
short-term production outages and constrained oil rates for a few
weeks in the fourth quarter while a build-up of calcium naphthenate
was removed from the produced water plant. The reservoir continues
to outperform with the Group recognising a further reserves upgrade
at year end.
Through 2020 Premier reinjected produced gas into the reservoir
via the existing production wells to evaluate the opportunity for
improved oil recovery. Initial trials were positive and a second
phase of reinjection continued into 2021 to further define the
opportunity. In February 2021 Premier, as operator on behalf of the
joint venture partners, initiated the process with the regulator
for approval of various reservoir management schemes, including gas
reinjection, to increase total oil recovery from the fields. On the
expectation that such approvals will be granted, Premier recognised
a reserves increase associated with these projects in the current
period.
The Varadero infill well (VP1) was successfully drilled and
tied-in to production in September. The development of two Catcher
Area satellites, Catcher North and Laverda, were deferred as part
of the measures taken to minimise 2020 capex with development
drilling now expected to commence in early 2022, with first oil
scheduled for later that year. These wells add incremental
production as the Catcher Area comes off plateau through 2021.
The Group continues to work up additional opportunities within
and around the Catcher Area to maximise economic recovery. The 4D
seismic survey to be acquired in 2021 will help the understanding
of the reservoir recovery mechanisms including optimisation of
water flood, gas recovery and high grading of future infill and
near field drilling targets.
Other UK producing assets
Production from Premier's operated Solan field averaged 2.0
kboepd (2019: 3.5 kboepd) (Premier 100 per cent interest). The
Solan P3 well was brought on-stream in September, on schedule and
within budget, and produced at peak rates of over 10 kbopd in
November with the electric submersible pump online. Production from
the Solan field was shut in following the failure of the emergency
generator in December. Production was subsequently restored to
sustained rates of approximately 7 kbopd at the end of the year.
Post period end, commissioning of the fuel gas system was
successfully completed, reducing the asset's carbon footprint and
operating costs.
The non-operated Elgin-Franklin Area, which is the UK's largest
producing field group, averaged 6.8 kboepd (2019: 6 kboepd) (net,
Premier 5.2 per cent interest), significantly ahead of budget. This
was due to higher uptime and an active well programme, including
the FID well which was successfully brought on-stream in October,
three months earlier than scheduled. Production was also supported
by an acid wash campaign conducted in August with further
stimulation and intervention campaigns planned for 2021.
Ravenspurn North averaged 1.1 kboepd (2019: 1.2 kboepd) (net,
Premier 28.8 per cent interest), reflecting high uptime, a shorter
annual shutdown and good availability at the Dimlington terminal.
This was partially offset by the five well acid stimulation
campaign, originally planned for the first quarter of 2020, being
deferred to the fourth quarter.
As previously announced, Premier, together with its joint
venture partners, decided to cease production from certain mature,
high cost UK fields. This included the Balmoral Area and Huntington
where field life has already been extended significantly beyond
what was anticipated when Premier acquired operatorship of the
fields in 2009 and 2016 respectively.
At Huntington, which ceased production in April, the first phase
of the decommissioning programme was completed with the sailaway of
the FPSO and recovery of the riser systems during 2020, with the
FPSO mooring system to be recovered in 2021. The second phase,
which will entail recovery of the subsea equipment, is scheduled
for 2022. Final production from the operated Balmoral Area, which
achieved two years without a lost time injury in September,
occurred in November 2020 with sailaway of the FPV scheduled for
the second quarter of 2021. Production also ceased from Premier's
non-operated Scoter and Merganser fields in December 2020 while the
Kyle field, in which Premier has a 40 per cent interest, ceased
production in August 2020.
The Greater Tolmount Area
Tolmount, Premier's next UK growth project, is on schedule for
first gas during the second quarter of 2021. Good progress was made
across the four key project elements (platform, pipelines, terminal
modifications and wells) during 2020, despite the challenging
operational environment.
In March 2020, the HGS Tolmount platform was two weeks from
sailaway when Rosetti's Ravenna yard was shut down by the Italian
government in response to the emerging pandemic. As a result, a new
installation window was negotiated with the installation
contractor, Heerema, and the platform was successfully installed in
October 2020. A positive consequence of the five month delay was an
unusually high level of completion at sailaway. Hook-up and
commissioning is being undertaken in parallel with development
drilling, which commenced in the fourth quarter of 2020.
Saipem were successful in managing the impact of COVID-19 with
the pipeline lay barge mobilised from Rotterdam as scheduled. The
pipelines have been installed, tested, trenched and buried. The
tie- in at the terminal end of the pipeline has been made while the
offshore tie-in scope will be completed in spring 2021.
At the Easington terminal, the piping scope needed for free flow
of Tolmount gas was completed in 2020 and the remaining scope to
first gas is on track. Compression is not needed for Tolmount until
late 2022 at the earliest, but is scheduled to complete in October
2021.
Valaris 123, the jack up rig contracted to drill the Tolmount
wells, was mobilised during the fourth quarter of 2020. Batch
drilling of the top holes was completed in January 2021. The first
development well, Tolmount NW, reached total depth in February
encountering gas bearing reservoir as prognosed. The second
development well is drilling ahead with two wells expected to be
on-stream at first gas. Once at plateau rates, anticipated later in
2021, the field will add 20-25 kboepd (net) to Premier's
production.
Premier continues to progress Tolmount East towards a final
investment decision, expected to be taken in the second quarter of
2021, with first gas targeted for 2023. FEED on the proposed
Tolmount East development, initially comprising a single well
subsea tie back to the Tolmount platform, was completed in 2020.
All the key supply contracts, including for the provision of
subsea, umbilicals, risers, flowlines (SURF), subsea controls and
wellheads, have been finalised in preparation for their execution
as the project approaches sanction decision. Once on-stream
Tolmount East (and potentially the near field Mongour discovery
which could also be developed as a subsea tieback to the Tolmount
infrastructure) will help extend plateau production from the
Tolmount area.
Beyond Tolmount East, there is significant prospectivity in the
Greater Tolmount Area. The final processed data from the 3D seismic
acquired across the Greater Tolmount Area in 2019 was received in
the summer. This is being used to mature the Tolmount Far East
prospect and to further assess prospectivity to the east and west
of the Tolmount field. This includes a number of leads and
prospects identified on the two licences adjacent to the Tolmount
Field Development Area which Premier was awarded in the UK's 32(nd)
Round in September 2020. In the success case, these leads and
prospects could be developed via Tolmount infrastructure.
VIETNAM
Premier's operated Chim Sáo field delivered a robust production
performance in 2020. Together with low operating costs, this
resulted in the asset continuing to generate free cash flow for the
Group.
Production from the Premier-operated Block 12W, which contains
the Chim Sáo and Dua fields, averaged 8.6 kboepd (2019: 11.4
kboepd) (net, Premier-operated 53.1 per cent interest) and was in
line with expectations. The reduction on the prior year reflects
natural decline from the existing wells partially offset by active
reservoir management and ongoing well intervention activities.
2020 saw four well intervention campaigns aimed at maximising
the ultimate recovery from the Chim Sáo field. This included
improved utilisation of gas lift across the Chim Sáo well stock and
the perforation of new zones within existing wells. Further well
intervention work is planned for 2021 to help slow natural decline
and optimise offtake from the Chim Sáo field. Preparations are also
underway for a two well infill programme scheduled for 2022.
Premier is currently seeking regulatory approvals for the programme
ahead of going out to tender for a rig.
Post period end, Chim S á o surpassed the milestone of four
years without a Lost Time Injury and also completed its 250(th)
tanker offtake, with over 74 mmbbls (gross) of oil sold since first
oil (compared to sanctioned reserves of 44 mmbbls (gross).
Chim Sáo cargoes were placed in the market at competitive
prices, with an average premium to Brent of more than US$3.5/bbl
realised for cargoes lifted during 2020. Field operating costs were
US$10/boe (2019: US$9/boe), significantly below budget with opex
savings largely offsetting production decline.
INDONESIA
Premier's operated Natuna Sea Block A generated material
positive net cash flows for the Group, underpinned by a strong
production performance and low operating costs. Elsewhere in
Indonesia, Premier completed the farm down of its interest in the
Tuna PSC post period end and preparations are underway for the
Group's first exploration well on its highly prospective Andaman
Sea acreage.
Production and development.
Production from the Premier-operated Natuna Sea Block A averaged
12.2 kboepd (2019: 11.5 kboepd) (net, Premier 28.7 per cent
interest), ahead of budget and higher than 2019. This was driven by
Natuna Sea Block A capturing a higher market share of its principal
gas sales agreement (GSA1) and strong Singapore demand for gas sold
under the Group's second gas sales contract (GSA2). In addition,
asset reliability and deliverability was excellent throughout the
year, despite the slowdown of certain offshore activities due to
the outbreak of COVID-19, and supported a year-on-year reduction in
GHG emissions from the Group's Indonesian operations.
Singapore demand for Indonesian gas sold under GSA1 averaged 276
BBtud (2019: 285 BBtud), slightly below take or pay levels and
driven by low offtake during the third quarter when the price of
GSA1 gas was significantly above that of spot LNG. Premier's Anoa,
Pelikan, Bison and Gajah Puteri fields, which are dedicated to
GSA1, delivered 152 BBtud (gross) (2019: 147 BBtud) during the year
and accounted for 56 per cent (2019: 52 per cent) of GSA1
deliveries. This was materially above Natuna Sea Block A's
contractual share of 52.5 per cent. Production from the Gajah Baru,
Naga and Iguana gas fields, which supply gas into Singapore under
GSA2 averaged 64 BBtud (2019: 55 BBtud), slightly above take or pay
levels.
Premier's operated 2021 jack-up rig campaign, which will include
an Anoa well workover and an Anoa infill well, is on track to start
in mid-2021. This programme, together with several low cost
additional perforation activities planned for 2021, will help
maximise gas delivery from the Natuna Sea Block A fields.
Revenues from Premier's Indonesian operations were partially
protected from the impact of the collapse in commodity prices with
a significant proportion of the Group's 2020 Indonesian gas
entitlement production hedged at c.US$9/mmscf, significantly above
realised contract prices during the year.
Exploration and appraisal
In May 2020, Premier agreed a farm down agreement with
Zarubezhneft for a 50 per cent interest in the Group's Tuna field,
which is estimated to contain c. 100 mmboe and is located in the
Natuna Sea adjacent to the Indonesian and Vietnamese maritime
border. The farm down agreement was completed post period end in
January 2021 following receipt of Indonesian government approval.
Under the farm down agreement, Zarubezhneft will carry Premier for
its share of a two well campaign to appraise the Tuna field,
scheduled to commence in the second quarter of 2021. Premier
remains operator of the Tuna PSC, with the Company and Zarubezhneft
each having a 50 per cent interest in the licence.
In addition, Premier and Zarubezhneft have secured Indonesian
government approval for a one year extension to the exploration
period of the Tuna PSC to allow for appraisal drilling to take
place and the subsequent submission of a Plan of Development to the
Indonesian government by March 2022.
Elsewhere in Indonesia, the final data from the 2019 3D seismic
acquisition programme across Premier's Andaman Sea licences were
received during the year and confirmed the highly prospective
nature of this acreage. In light of the results from the 3D data,
reprocessing of some of the legacy 2D seismic data on Premier's
operated Andaman II licence was undertaken and has yielded positive
results with additional amplitude supported leads identified. These
will now be the target for a future 3D seismic acquisition
programme.
Premier plans to drill its first well in the Andaman Sea on its
operated Andaman II licence in the first half of 2022. Premier's
Andaman Sea position has the potential to deliver multi-TCF of gas
and adds a potentially material gas play to the Group's
portfolio.
FALKLAND ISLANDS
The weak oil price environment resulted in Premier taking the
decision to reduce activities on its Sea Lion Phase 1 project in
the first quarter of the year. Sea Lion remains a material
opportunity for the Group and a smaller core team has continued to
progress a number of regulatory and commercial work streams over
the course of the year.
Premier's 2020 priorities for its Sea Lion Phase 1 project, as
envisaged at the start of the year, included securing senior debt
financing for the project, completing the farm down to Navitas
Petroleum and submitting a Field Development Plan for the project
to the Falkland Islands Government by the end of the year.
Technical definition of the Sea Lion Phase 1 project, which will
develop 250 mmbbls of the 530 mmbbls Sea Lion gross resource, was
completed in the first quarter of 2020 and all of the key service
and supply contracts were in the process of being finalised. Public
consultation on the Environmental Impact Statement had also been
completed having been updated to reflect further project
optimisation. However, the collapse in commodity prices and the
ensuing need to defer discretionary capex, resulted in Premier
reducing activity on its operated Sea Lion Phase 1 project in
April.
Over the remainder of 2020, a reduced team continued to progress
a number of regulatory and commercial work streams. This included
developing Sea Lion's net zero emissions plan to ensure the project
would be carbon neutral and finalising the terms for Navitas to
farm in for a 30 per cent interest in the Sea Lion licences. Under
the terms of the farm out agreement, Navitas will share the
pre-first oil funding and bring additional sources of senior debt
financing to the project. In addition, the previously differing
interests between Premier and Rockhopper across the various Sea
Lion licences will be harmonised with Premier, Rockhopper and
Navitas having a 40 per cent, 30 per cent and 30 per cent interest,
respectively, in the Sea Lion licences.
The proposed farm out of the Sea Lion licences to Navitas is
subject to the Falkland Islands Government's and, pursuant to the
Merger Agreement, Chrysaor's approval. As a result, in December,
Premier, Rockhopper and Navitas agreed to extend the exclusivity
period for the farm out to enable the merger with Chrysaor to
complete and the management of Harbour Energy to make a decision on
the farm out.
Post period end, the Falklands Islands Government agreed an
extension to each of Premier's licences in the North Falklands
Basin, including the Sea Lion Discovery Area. The licences, which
had been due to expire on 1 May 2021, have been extended until
November 2022.
MEXICO
In Mexico, the Block 7 (Premier 25 per cent interest) partners
and Pemex continued to progress the giant Zama field towards
project sanction, targeted for late 2021. 2020 activity focused on
completing FEED, drafting the field development plan and advancing
unitisation ahead of the deadlines dictated by the Block 7 PSC and
the hydrocarbon laws of Mexico.
During 2020, the sub-surface teams continued with detailed
analysis of the samples and data obtained by the 2018 and 2019
appraisal drilling campaign, confirming the excellent quality and
properties of the Zama reservoir rocks and crude oil. Premier
believes that this, together with the very high resource density
and shallow water setting, will underpin a recovery factor of in
excess of 50 per cent from the field. Premier gross recoverable
resource estimate for Zama remains unchanged at over 800 mmboe.
It is anticipated that Zama will be developed using two drilling
and processing platforms tied back to a floating storage and
offloading vessel with the key elements of the development scheme
already agreed with Pemex. FEED for the platform support structures
(jackets) and topsides processing facilities was completed
successfully by McDermott Engineering. An invitation to tender for
detailed engineering, leading to procurement, and construction of
the jackets and topsides will be issued in 2021. The facilities are
low carbon by design with GHG intensity estimated at around 16
KgCO(2) e/bbl life of field.
Positive progress was also made on the unitisation of the Zama
field between the Block 7 partners and Pemex, particularly during
the second half of the year. The Mexican Regulators agreed that the
Zama reservoir is shared and extends across the boundary between
Block 7 and the neighbouring concession operated by Pemex. SENER
issued the instruction to unitise Zama in July and an Independent
Expert is now in the process of examining the Zama geological and
geophysical data ahead of making a determination of the initial
tract participation by the end of April 2021. A short extension to
the deadline for submission of the unitisation agreement to SENER
was granted in December to allow for the expert process and
negotiations to conclude.
Beyond Zama, Premier retains exposure to exploration upside in
Mexico through its other offshore licence interests, each of which
has the potential to deliver material future value for Premier. A
3D seismic survey across Block 30 (Premier 30 per cent interest)
was completed in July 2019. The final processed data was received
in the second quarter of 2020 and has been interpreted in order to
delineate the full extent of the Wahoo prospect, which will be
evaluated by the first well drilled on Block 30, targeted for the
second half of 2022. Additional prospectivity on the block is being
evaluated.
Elsewhere in Mexico, on Premier's 100 per cent operated Burgos
Blocks 11 and 13, reprocessing of the existing 3D seismic was
completed and interpretation is underway. Prospects in the deeper
Mesozoic carbonate play similar to the Arenque field have been
identified on the reprocessed data and are now the focus of the
evaluation as these could constitute a material play on block. The
shallower Oligo-Miocene clastic play remains but is now viewed as
higher risk.
EXPLORATION ACTIVITIES
During the year, the COVID-19 pandemic resulted in strict
budgetary constraints as a result of which, a number of planned
exploration activities were deferred to minimise near-term
expenditure. The Group's focus remains on under-explored but proven
hydrocarbon provinces that have the potential to develop into new
business units over the medium term.
Alaska
In March, Premier participated in the Charlie-1 well in Area A
(Premier 60 per cent interest) on the North Slope of Alaska. The
well was drilled on budget and successfully extended the Brookian
play south, recovering hydrocarbons to surface from conventional
pay; however the reservoir fluid was gas-condensate which is more
challenging to commercialise in this area than the light oil the
well was targeting. As a result, the well was plugged and abandoned
without further testing and Premier exited the licence.
Brazil
In Brazil, much of the first quarter was spent preparing for
Premier's first exploration well on its operated Block 717 (Premier
50 per cent interest) in the offshore Ceará basin. Premier had
contracted the Valaris DS-9 drillship to drill a well targeting the
stacked Berimbau/Maraca prospect and the well was due to spud on
1st July. Berimbau is a higher risk, high value prospect with a
Pmean to P10 gross unrisked resource estimate of 230-450 mmbbls.
Maraca is a lower risk prospect and is estimated to contain 85-165
mmbbls (Pmean-P10) of gross unrisked resource. However, as a result
of the COVID-19 pandemic the decision was taken to defer the well
and the Valaris contract was terminated. The JV have secured a
further nine month extension to the current term in response to the
COVID-19 pandemic and its impact. The well is now expected to be
drilled in Q1 2022.
FINANCIAL REVIEW
Business performance
Production averaged 61.4 kboepd in 2020 (2019: 78.4 kboepd),
which, coupled with lower commodity prices, resulted in total
revenue from all operations of US$949 million compared with
US$1,597 million in 2019.
EBITDAX for the period from continuing operations was US$620
million, a decrease of US$610 million compared to the prior period
EBITDAX of US$1,230 million. The reduced EBITDAX is due primarily
to lower realised commodity prices and production, partially offset
by higher realised hedging gains of US$149 million recognised in
the period. Underlying operating cost per barrel remained broadly
stable in spite of lower production due to tight cost control.
Business performance (continuing operations) 2020 2019
US$ million US$ million
Operating (loss)/profit (343.8) 455.0
Add: DD&A 671.3 757.9
Add: Exploration and new venture costs 293.4 21.3
Less: Profit on disposal of non-current
assets (1.1) (4.2)
EBITDAX as reported 619.8 1,230.0
Net debt has increased to US$2,078.4 million from US$1,989.8
million at the end of 2019.
Income statement
Production and commodity prices
Group production on a working interest basis averaged 61.4
kboepd compared to 78.4 kboepd in 2019. Production was lower than
in 2019 due to lower production from the Catcher field following
unplanned outages in the year and the cessation of production from
certain mature UK fields. Average entitlement production for the
period was 57.5 kboepd (2019: 73.9 kboepd).
Premier realised an average oil price for the year of
US$42.1/bbl (2019: US$66.3/bbl). Including the effect of oil swaps
which settled during 2020, the realised oil price was US$49.4/bbl
(2019: US$68.1/bbl). Premier continued to benefit from positive
differentials for its crude oil sales relative to the underlying
Brent oil price.
In the UK, average natural gas prices achieved were 34
pence/therm (2019: 42 pence/therm). Gas prices in Singapore, linked
to high sulphur fuel oil ('HSFO') pricing and in turn, therefore,
linked to crude oil pricing, averaged US$6.6/mscf (2019:
US$10.2/mscf). Including the effect of HSFO swaps which settled
during 2020, the realised HSFO price was US$8.3/mscf (2019:
US$10.2/mscf).
Realised prices - post hedging 2020 2019
Oil price (US$/bbl) 49.4 68.1
---- ----
UK natural gas (pence/therm) 34 42
---- ----
Singapore HSFO (US$/mscf) 8.3 10.2
---- ----
Total revenue from all operations decreased to US$949.4 million
(2019: US$1,596.5 million).
Cost of operations
Cost of operations comprise operating costs, changes in lifting
positions, inventory movement and royalties. Cost of operations for
the Group was US$324.7 million for 2020, compared to US$342.8
million for 2019 due to a decrease in operating costs partially
offset by stock overlift/underlift movements resulting from the
timing of hydrocarbon sales.
2020 2019
US$ million US$ million
Operating costs
============= =============
Continuing operations 273.8 322.6
Discontinuing operations (Pakistan) - 2.4
------------------------------------- ------------- -------------
Operating costs 273.8 325.0
============= =============
Operating cost per barrel (US$ per
barrel) 12.2 11.4
------------------------------------- ------------- -------------
The decrease in absolute operating costs reflects savings
achieved from strict management of discretionary spend, deferral of
certain work scopes and lower costs arising from the cessation of
production on certain UK fields. Operating costs per barrel,
excluding lease costs, increased to US$12/boe (2019: US$11/boe)
reflecting lower year-on-year production rather than any increase
in underlying operating costs.
Lease expenses in 2020 were US$155.6 million, giving a lease
cost per barrel of US$6.9/boe (2019: US$6.9/boe), which is
consistent year-on-year.
2020 2019
US$ million US$ million
Amortisation and depreciation
---------------------------------- ------------- -------------
Total DD&A 524.5 742.9
---------------------------------- ------------- -------------
DD&A per barrel (US$ per barrel) 23.3 26.4
---------------------------------- ------------- -------------
Total depreciation has decreased year-on-year to US$524.5
million due to lower production rates and the cessation of
production on certain mature fields. The depreciation charge
includes US$52.7 million related to an increase in the Group's
decommissioning provisions on assets which are carried at nil book
value. This is due to a reduction in the rate used to discount
provisions to 3.0 per cent (2019: 3.6 per cent) following the
reduction in US treasury rates observed in 2020 and not by any
material change in the underlying decommissioning cost
estimates.
In addition to the amortisation and depreciation charge for the
period, the Group recognised an impairment charge of US$143.8
million. US$140.3 million of the current period impairment charge
relates to Solan and was driven by a reduction in management's
long-term oil price assumption to US$60/bbl real (2019: US$70/bbl
real) together with the reduction in reserves associated with
future investment decisions.
Exploration expenditure and new ventures
Exploration expense and new venture costs amounted to US$293.4
million (2019: US$21.3 million). This includes exploration
expenditure of US$194.1 million written off for costs previously
capitalised for exploration prospects in the North Falklands basin,
which will not be developed as part of the Sea Lion Phase 1
project. In addition, the drilling of the Charlie-1 well in Area A
in Alaska encountered non-commercial gas condensate for which
US$27.1 million of costs have been expensed in the period. New
venture costs also include costs associated with the corporate
actions that were undertaken during the period including the
previously proposed acquisition of BP's interests in the Andrew
Area and the Shearwater field and the proposed merger with Chrysaor
Holdings Limited.
After recognition of these expenditures, the exploration and
evaluation assets remaining on the balance sheet at 31 December
2020 amount to US$785.3 million, principally for the Sea Lion
asset, our share of the Zama prospect and Block 30 in Mexico and
the Tuna PSC in Indonesia.
General and administrative expenses
Net G&A costs of US$8.4 million (2019: US$9.0 million) were
comparable with the prior year.
Finance gains and charges
Net finance gains and charges of US$261.5 million have reduced
compared to the prior year (US$352.5 million). This is due to lower
interest charges following a fall in LIBOR rates during the year
and a fair value gain realised in respect of the Group's
outstanding equity warrants. Included within finance charges are
costs of US$32.0 million associated with refinancing activities
during the period. Cash interest expense in the period was US$230.4
million (2019: US$251.9 million).
Taxation
The Group's total tax charge for 2020 from continuing operations
is US$696.9 million (2019: credit of US$52.5 million) which
comprises a current tax charge for the period of US$33.1 million
and a non-cash deferred tax charge for the period of US$663.8
million.
The total tax credit represents an effective tax rate charge of
negative 115.1 per cent (2019: credit of 51.2 per cent). The
effective tax rate is predominantly driven by the derecognition of
UK ring fence tax losses and allowances due to a reduction in
management's oil and gas price assumptions and the exclusion of
future taxable profits associated with the previously proposed BP
acquisitions when assessing recoverability of deferred tax assets
('DTA'). Despite the merger being expected to complete in March
2021, future taxable profits associated with Chrysaor's assets are
not reflected in the DTA recoverability assessment at year-end as
the relevant accounting standard does not permit the accounting
acquiree to take credit for future taxable profits associated with
a proposed business combination.
Due to the fall in oil and gas prices and the presence of
impairment indicators, the Group re-ran its corporate model to
assess whether it is appropriate to continue to recognise the
Group's deferred tax losses and allowances at 31 December 2020. The
results of the corporate model concluded that it was no longer
appropriate to recognise an amount of US$817.2 million in respect
of ring fence tax losses, decommissioning asset and investment
allowances. Premier retains access to these tax losses in the event
forecast taxable profits were to increase in the future and expects
to recognise these ring fence tax losses and investment allowances
in full upon completion of the proposed merger with Chrysaor, when
revising the corporate model to include the cash flows of the
enlarged Group.
The Group has a net deferred tax asset of US$763.4 million at 31
December 2020 (2019: US$1,426.2 million).
Loss after tax
Loss after tax is US$1,302.2 million (2019: profit of US$164.3
million) resulting in a basic loss per share of 146.7 cents from
continuing and discontinued operations (2019: earning of 19.9
cents). The loss after tax in the year is driven by the lower
production volumes and realised prices, significant charges in
relation to exploration and new venture expenditure ( US$293.4
million), the partial derecognition of the Group's deferred tax
asset (US$827.1 million) and the impairment of PP&E assets (
US$94.6 million , post-tax).
Cash flows
Cash flow from operating activities was US$630.1 million (2019:
US$1,080.0 million) after accounting for net tax receipts of US$2.0
million (2019: payments of US$61.2 million) and before the movement
in joint venture cash balances in the period of US$19.5 million.
The decrease is driven by reduced production and realised commodity
prices in the period.
Capital expenditure in 2020 totalled US$266.6 million (2019:
US$241.4 million).
Capital expenditure 2020 2019
US$ million US$ million
Fields/development projects 178.4 101.7
------------ ------------
Exploration and evaluation 85.6 136.9
------------ ------------
Other 2.6 2.8
------------ ------------
Total 266.6 241.4
------------ ------------
The principal development expenditure was in respect of the UK
where work continued on the Tolmount development and the Solan P3
and Catcher VP1 wells were both drilled and brought on-stream.
Development drilling at Catcher North and Laverda, originally
scheduled for 2020, was deferred as part of measures taken to
manage the Group's capital expenditure.
The largest parts of the E&E capital expenditure in the
period were the Charlie-1 appraisal well in Alaska which was
plugged and abandoned after encountering non-commercial gas
condensate, and ongoing pre-development expenditure on the Sea Lion
Phase 1 project in the Falkland Islands. In addition, cash
expenditure for decommissioning activity in the period was US$48.9
million (2019: US$35.3 million) and a further US$5.4 million of
cash placed into long-term abandonment accounts for future
decommissioning (2019: US$9.9 million).
Total development and E&E expenditure relating to Premier's
existing assets for 2021 is estimated at US$180 million principally
related to development drilling on Tolmount and Catcher, and
exploration and appraisal activities in Mexico and Indonesia.
Premier share of costs of the two well appraisal programme on the
Tuna discoveries in Indonesia are carried by Zabruzhneft up to an
agreed cap. Decommissioning spend is estimated at US$120 million
reflecting the cessation of production at various UK fields during
2020.
Discontinued operations, disposals and assets held for sale
The Group completed the sale of its Pakistan business to the
Al-Haj Group in March 2019 for a total consideration of US$65.6
million. The results of the Pakistan Business Unit in the prior
period are presented as a discontinued operation.
Balance sheet position
Net debt
Net debt at 31 December 2020 amounted to US$2,078.4 million (31
December 2019: US$1,989.8 million), with cash resources of US$108.3
million (31 December 2019: US$198.1 million). The maturity of all
of Premier's facilities is May 2021. During the year, Premier made
debt repayments of US$52.3 million partly offset by drawings under
its RCF facility of US$35.0 million. The Group cancelled US$129.5
million of its RCF debt facility during the period.
Premier retains cash at 31 December 2020 of US$72.0 million and
undrawn facilities of US$219.3 million, giving liquidity of
US$291.3 million (31 December 2019: US$549.2 million) when
excluding cash of US$36.3 million held on behalf of joint venture
partners or as security for letters of credit.
During the period the Group issued 82.2 million shares to one of
Premier's creditors, ARCM, resulting in equity proceeds of US$27.0
million.
Provisions
The Group's decommissioning provision increased to US$1,372.1
million at 31 December 2020, up from US$1,303.4 million at the end
of 2019. The increase is driven by a reduction in the discount rate
used to determine the net present value of the decommissioning
provision, following the reduction in US treasury rates observed in
2020 and not by any material change in the underlying
decommissioning costs estimates. The increase has been partly
offset by decommissioning activity undertaken during the period
following the cessation of production from certain mature UK
fields.
Non-IFRS measures
The Group uses certain measures of performance that are not
specifically defined under IFRS or other generally accepted
accounting principles. The non-IFRS measures used within this
Financial Review are EBITDAX, Operating cost per barrel, DD&A
per barrel, Net debt and Liquidity and are defined in the
glossary.
Financial risk management
Commodity prices
Premier continued to take advantage of hedging to protect free
cash flows. The Group's current hedge position is as follows:
Oil
Swaps/forwards 2021 1H 2021 2H
--------
Volume (mmbbls) 1.4 0.3
Average price (US$/bbl) 53 61
------------------------- -------- --------
UK gas
Swaps/forwards/options 2021 1H 2021 2H 2022 2023
--------
Volume (million therms) 57 68 80 -
Average price (p/therm)
(1) 45 40 42(1) -
------------------------- -------- -------- ------ -----
(1) Average price is a mixture of swap and option floor pricing
and excludes impact of deferred option premiums.
At 31 December 2020, the fair value of open oil and gas
instruments was a net asset of US$5.2 million (31 December 2019:
asset of US$29.2 million), which is expected to be released to the
income statement during 2021 and 2022 as the related barrels are
lifted or therms delivered
During 2020, expiration of forward oil and gas swaps resulted in
a net credit of US$149.5 million (2019: credit of US$45.6 million)
which has been included in sales revenue for the year.
Foreign exchange
Premier's functional and reporting currency is US dollars.
Exchange rate exposures relate only to local currency receipts, and
expenditures within individual business units. Local currency needs
are acquired on a short-term basis. At the year-end, the Group
recorded a mark-to-market loss of US$6.6 million on its outstanding
foreign exchange contracts (2019: gain of US$6.2 million). The
Group currently has GBP150.0 million of retail bonds, EUR63.0
million long-term senior loan notes and a GBP100.0 million term
loan in issuance which have been hedged under cross currency swaps
in US dollars at average fixed rates of US$1.64:GBP and
US$1.37:EUR. The fair value of the cross currency swap liability at
31 December 2020 is US$88.7 million (2019: US$123.6 million).
Interest rates
The Group has various financing instruments including senior
loan notes, UK retail bonds, term loans and revolving credit
facilities. On average, the effective interest rate on drawn funds
for the period, recognised in the income statement, was 7.4 per
cent.
Insurance
The Group undertakes a significant insurance programme to reduce
the potential impact of physical risks associated with its
exploration, development and production activities. Business
interruption cover is purchased for a proportion of the cash flow
from producing fields for a maximum period of 18 months. During
2020, there were no insurance claims and nil cash proceeds were
received in relation to settled insurance claims (2019: US$2.3
million).
Proposed Merger with Chrysaor Holdings Ltd
On 6 October 2020, the Group publicly announced the proposed
merger of Premier Oil plc ("Premier") and Chrysaor Holdings Limited
("Chrysaor") and the reorganisation of Premier's existing finance
arrangements.
The merger of Premier and Chrysaor Holdings Limited will create
Harbour Energy plc ('Harbour'), the largest independent oil and gas
company listed on the London Stock Exchange with combined
production of over 200 kboepd and will bring together two
complementary businesses to create a combined group with a strong
balance sheet and significant international growth
opportunities.
The Board of Directors of the Enlarged Group will comprise 11
Directors including six independent non--executive Directors. All
appointments have been agreed and announced, including the
appointments of Blair Thomas as Chairman and Linda Cook as CEO.
Upon completion of the transaction, Premier's existing creditors
will receive a cash payment of US$1.23 billion in satisfaction of
part of Premier's existing debt and cross--currency swaps and
Premier will issue new shares to the existing creditors to satisfy
the balance of the Premier Group's existing debt and
cross--currency swaps. In addition, existing creditors will receive
(i) new shares in Harbour and/or (ii) a cash alternative which is
capped at a maximum of US$175 million.
Under the terms of the transaction Premier's creditors were able
to elect to subscribe in cash at a pre-agreed price for those new
shares in the enlarged group which would have been issued to other
senior creditors if they had not elected the Cash-Out Option (the
'Top-Up Election'). Based on the elections made by senior
creditors, it is anticipated that the cash alternative of US$175
million will be retained by the enlarged group as the take-up of
the cash alternative option is expected to be less than US$175
million and the number of shares subscribed for under the Top-Up
Election exceeded the number of shares which are expected to be
available under the Top-Up Election.
As a result the merger is expected to result in Premier's
stakeholders owning up to 23 per cent of the Enlarged Group and
existing Chrysaor shareholders owning at least 77 per cent.
Premier's stakeholders include its existing shareholders which are
expected to own 5 per cent of the Enlarged Group.
Significant progress has been made towards obtaining the
necessary approvals for the transaction. Premier shareholder
approval was obtained at a General Meeting on 12 January 2021 and
Premier's creditors voted in favour of the restructuring plans on
22 February 2021. The restructuring plans remain subject to
approval by the Scottish Court of Session with the sanction hearing
currently scheduled to commence on 19 March 2021. All regulatory
conditions relating to the merger have now been satisfied and all
of the requisite anti-trust approvals have been received.
The Enlarged Group will have significant scale and
diversification, through the combination of material operated and
non--operated cash generative production hubs in the UK North Sea.
Premier's financial position will be transformed, delivering an
Enlarged Group with a strong and sustainable financing structure.
The merger will also realise substantial cost and tax synergies,
accelerating the use of Premier's existing circa US$4.1 billion of
UK tax losses and unlocking significant value for shareholders.
Going concern
The Group monitors its capital position and its liquidity risk
regularly throughout the year to ensure that it has access to
sufficient funds to meet forecast cash requirements. Cash forecasts
are regularly produced based on, inter alia, the Group's latest
life of field production and expenditure forecasts, management's
best estimate of future commodity prices (based on recent forward
curves, adjusted for the Group's hedging programme) and the Group's
borrowing facilities. Sensitivities are run to reflect different
scenarios including, but not limited to, changes in oil and gas
production rates, possible reductions in commodity prices and
delays or cost overruns on major development projects. This is done
to identify risks to liquidity and covenant compliance and enable
management to formulate appropriate and timely mitigation
strategies in order to manage the risk of funds shortfalls or
covenant breaches and to ensure the Group's ability to continue as
a going concern.
The proposed merger of Premier and Chrysaor and the
reorganisation of Premier's existing finance arrangements ("Debt
Restructuring") (together, "the Corporate Actions") are expected to
complete on 31st March 2021.
The Corporate Actions include the:
-- Merger of Premier and Chrysaor (together, "the Enlarged
Group") through a reverse takeover ("the Merger");
-- The issue of approximately 17.59 billion new ordinary shares
in Premier, approximately 14.25 billion of which will be issued to
Chrysaor's shareholders in exchange for the acquisition by Premier
of 100 per cent of the issued share capital of Chrysaor; and
-- Cancellation, repayment and release of Premier's US$2.7
billion of total gross debt and certain hedging liabilities, which
currently mature on 31 May 2021, for a cash payment of US$1.23
billion, together with new ordinary shares in Premier and, if
creditors had so elected, a share of a further cash payment capped
at approximately US$175 million.
The cash payments to creditors are expected to be funded through
a combination of existing cash balances and Chrysaor's borrowing
facilities.
Base case assessment
Management's going concern assessment considered the ability of
the Group to continue as a going concern from the date of approval
of the 2020 Annual Report and Accounts ('ARA') through to 31 March
2022 ('the going concern period'). The Group's base case going
concern assessment assumes: completion of the Corporate Actions on
31 March 2021; an oil price of US$51/bbl and US$55/bbl in 2021 and
2022, respectively; and production in line with approved asset
plans. Under the terms of the Corporate Actions, following
settlement of Premier's existing debt, the ongoing capital
requirements of the Enlarged Group will be financed by Chrysaor's
existing financing arrangements, comprising its US$4.5 billion
Reserve Base Lending ('RBL') facility and US$400 million junior
debt facility.
The RBL facility has a final maturity of November 2027 and
contains certain financial covenants relating to the ratio of
consolidated total net debt to consolidated EBITDAX on a historic
and forward-looking basis, which will be tested semi-annually. The
amount available under the facility will be re-determined annually
based on a valuation of the Group's borrowing base assets when
applying certain forward-looking assumptions, as defined in the
borrowing agreement. The junior debt facility is repayable in
instalments between June 2022 and June 2026 and is not subject to
any financial covenants.
Under management's base case, the Enlarged Group is forecasted
to have sufficient financial headroom throughout the going concern
period.
Sensitivity analysis
Whilst assuming completion of the Corporate Actions on 31(st)
March 2021, management has run downside scenarios on the cash flows
of the Enlarged Group, where oil and gas prices are reduced by a
flat US$10/bbl and where total production of the Enlarged Group is
forecast to reduce by 10 per cent throughout the going concern
period. In the downside scenarios applied to the base case
forecast, individually and in combination, the Enlarged Group is
forecasted to have sufficient financial headroom throughout the
going concern period.
Should the Corporate Actions fail to complete
The proposed Corporate Actions are subject to a number of
conditions that must be satisfied to proceed, including shareholder
approval, regulatory approval, approval of the Debt Restructuring
by creditors and Court sanction of the Debt Restructuring. As
highlighted in the section covering the proposed Merger,
shareholder approval of the Corporate Actions was received on 12
January 2021, all necessary regulatory approvals are now in place
and the requisite level of Premier's creditors voted in favour of
the Debt Restructuring at the creditor meeting on 22 February 2021.
A court hearing to sanction the Debt Restructuring is scheduled to
take place on 19 March 2021. Court sanction of the Debt
Restructuring represents the key outstanding milestone, shortly
after which it is expected that the Corporate Actions will
complete.
Should the Corporate Actions fail to complete, the maturity of
Premier's existing debt facilities may, at Premier's option, be
extended from 31 May 2021 to 31 March 2022 ("Interim Maturity
Extension"). Since July 2020, the financial covenant tests
associated with Premier's existing borrowing facilities have been
deferred, initially under the terms of an agreement with the
requisite majorities of the Group's creditors and, from 6 October
2020, under the terms of a support letter executed by the requisite
majority of creditors ("Support Letter"). Without these deferrals,
the Group would have breached the financial covenants contained in
its financing agreements in respect of the testing periods ended on
30 June 2020, 30 September 2020 and 31 December 2020. The financial
covenant deferrals in the Support Letter remain in place until 30
September 2021 (or such later dates as may be agreed by Premier and
a requisite threshold of creditors, provided that such date may not
be later that 1 December 2021) ("Long-Stop Date") or completion of
the Merger.
Should the financial covenant deferrals expire, the Group will
immediately be in breach of its existing financial covenants.
Therefore, in the event that the Corporate Actions do not complete,
the ability of the Group to continue trading will depend upon: (i)
a significant portion of its creditors providing further financial
covenant deferrals; and (ii) the Group agreeing either: (a) an
alternative plan for the implementation of the Corporate Actions
with its creditors and Chrysaor; or (b) an alternative plan to
address its existing debt facilities and certain hedging
liabilities with its creditors. Failure to obtain future covenant
deferrals and/or execute an alternative debt restructuring would
result in Premier's existing debt facilities and certain hedging
liabilities becoming payable in the going concern period and, in
such circumstances, the Group would not be able to repay these
amounts.
Conclusion
Based on all required shareholder and regulatory approval
processes being complete and the requisite level of Premier's
creditors having voted in favour of the Debt Restructuring, the
Directors expect to complete the Corporate Actions on 31 March
2021. Assuming the Corporate Actions complete, the Directors have a
reasonable expectation that the Company has adequate resources to
continue in operational existence throughout the going concern
period. In the unlikely event that the Corporate Actions do not
complete, management believe it is likely that the lenders will
provide the required support to allow the Company time to complete
an alternative restructuring of its existing debt facilities.
Therefore, the Directors continue to adopt the going concern basis
of accounting in preparing these consolidated financial statements
and the financial statements do not include the adjustments that
would result if the Group were unable to continue as a going
concern.
However, successful completion of the Corporate Actions is
subject to the Court sanctioning the Debt Restructuring and is
outside the Group's control. The uncertainties regarding (1)
management's ability to complete the Corporate Actions; and (2)
should the Corporate Actions fail to complete, management's ability
to complete an alternative restructuring of its existing debt
facilities and certain hedging liabilities and obtain covenant
deferrals or waivers in the intervening period to prevent its
existing debt falling due within the going concern period, create
material uncertainties that may cast significant doubt on the
Company's ability to continue as a going concern.
Business risks
Premier's business may be impacted by various risks leading to
failure to achieve strategic targets for growth, loss of financial
standing, cash flow and earnings, and reputation. Not all of these
risks are wholly within the Company's control and the Company may
be affected by risks which are not yet manifest or reasonably
foreseeable.
Effective risk management is critical to achieving our strategic
objectives and protecting our personnel, assets, the communities
where we operate and with whom we interact, and our reputation.
Premier therefore has a comprehensive approach to risk
management.
A critical part of the risk management process is to assess the
impact and likelihood of risks occurring so that appropriate
mitigation plans can be developed and implemented. Risk severity
matrices are developed across Premier's business to facilitate
assessment of risk. The specific risks identified by project and
asset teams, business units and corporate functions are
consolidated and amalgamated to provide an oversight of key risk
factors at each level, from operations through business unit
management to the Executive Committee and the Board.
For all the known risks facing the business, Premier attempts to
minimise the likelihood and mitigate the impact. According to the
nature of the risk, Premier may elect to take or tolerate risk,
treat risk with controls and mitigating actions, transfer risk to
third parties, or terminate risk by ceasing particular activities
or operations. Premier has a zero tolerance to financial fraud or
ethics non-compliance, and ensures that HSES risks are managed to
levels that are as low as reasonably practicable, whilst managing
exploration and development risks on a portfolio basis.
The Group has identified its principal risks for the next 12
months as being:
-- Commodity price volatility
-- Access to capital
-- Health, safety, environment and security
-- Production and development delivery and decommissioning execution
-- Merger completion and integration
-- Climate change
-- Joint venture partner alignment and supply chain delivery
-- Organisational capability
-- Exploration success and reserves addition
-- Host government: political and fiscal risks
Further information detailing the way in which these risks are
mitigated is provided on the Company's website www.premier-oil.com
.
Richard Rose
Finance Director
Consolidated Income Statement
For the year ended 31 December 2020
2020 2019
US$ million US$ million
---------------------------------------------
Continuing operations
Sales revenues 949.4 1,584.7
Other operating income/(costs) 3.5 (2.9)
Costs of operation (324.7) (342.8)
Depreciation, depletion, amortisation
and impairment (671.3) (757.9)
Exploration expenses and new ventures (293.4) (21.3)
Profit on disposal of non-current assets 1.1 4.2
General and administration costs (8.4) (9.0)
------------- -------------
Operating (loss)/profit (343.8) 455.0
Interest revenue, finance and other gains 84.8 31.4
Finance costs, other finance expenses
and losses (346.3) (383.9)
(Loss)/profit before tax from continuing
operations (605.3) 102.5
Tax (charge)/credit (696.9) 52.5
------------- -------------
(Loss)/profit for the year from continuing
operations (1,302.2) 155.0
------------- -------------
Discontinued operations
Profit for the year from discontinued
operations - 9.3
------------- -------------
(Loss)/profit after tax (1,302.2) 164.3
------------- -------------
(Loss)/earnings per share (cents):
From continuing operations
Basic (146.7) 18.8
Diluted (146.7) 17.2
------------- -------------
From continuing and discontinued operations
Basic (146.7) 19.9
Diluted (146.7) 18.2
------------- -------------
Consolidated Statement of Comprehensive Income
For the year ended 31 December 2020
2020 2019
US$ million US$ million
--------------------------------------------------- ------------- -------------
(Loss)/profit for the year (1,302.2) 164.3
--------------------------------------------------- ------------- -------------
Cash flow hedges on commodity swaps and
options:
Gains/(losses) arising during the year 112.6 (50.8)
Less: reclassification adjustments for
gains in the year (149.5) (45.6)
------------- -------------
(36.9) (96.4)
Cash flow hedges on foreign exchange
swaps:
Losses arising during the year (12.4) (13.4)
Add: reclassification adjustments for
losses in the year 19.8 10.3
------------- -------------
7.4 (3.1)
Tax relating to components of other comprehensive
income 1.9 25.0
Exchange differences on translation of
foreign operations (9.3) (3.8)
Gain on long-term employee benefit plans(1) 0.3 0.2
Other comprehensive expenses (36.6) (78.1)
Total comprehensive (loss)/income for
the year (1,338.8) 86.2
------------- -------------
(1) Not expected to be reclassified subsequently to income
statement.
All comprehensive (loss)/income is attributable to the equity
holders of the parent.
Consolidated Balance Sheet
As at 31 December 2020
2020 2019
US$ million US$ million
---------------------------------------
Non-current assets:
Intangible exploration and evaluation
assets 785.3 934.0
Property, plant and equipment 2,101.8 2,481.8
Goodwill 240.8 240.8
Long-term receivables 248.2 231.1
Deferred tax assets 869.7 1,556.1
------------- -------------
4,245.8 5,443.8
------------- -------------
Current assets:
Inventories 12.7 16.3
Trade and other receivables 279.1 378.9
Derivative financial instruments 14.1 55.3
Cash and cash equivalents 108.3 198.1
414.2 648.6
Total assets 4,660.0 6,092.4
------------- -------------
Current liabilities:
Trade and other payables (399.5) (356.2)
Lease liabilities (74.3) (149.7)
Short-term provisions (116.9) (76.8)
Derivative financial instruments (95.9) (98.8)
Short-term debt (2,181.0) -
Deferred income (15.7) (15.3)
(2,883.3) (696.8)
Net current liabilities (2,469.1) (48.2)
------------- -------------
Non-current liabilities:
Long-term debt - (2,169.8)
Deferred tax liabilities (106.3) (129.9)
Lease liabilities (525.3) (582.8)
Deferred income (22.8) (60.5)
Derivative financial instruments - (62.3)
Long-term provisions (1,285.2) (1,258.8)
------------- -------------
(1,939.6) (4,264.1)
------------- -------------
Total liabilities (4,822.9) (4,960.9)
------------- -------------
Net (liabilities)/assets (162.9) 1,131.5
------------- -------------
Equity and reserves:
Share capital 171.1 156.5
Share premium account 517.5 499.4
Other reserves (851.5) 475.6
------------- -------------
(162.9) 1,131.5
------------- -------------
Consolidated Statement of Changes in Equity
For the year ended 31 December 2020
Attributable to the equity
holders of the parent
-------------------------------------------- ------------
Share premium
Share capital account Other reserves Total
US$ million US$ million US$ million US$ million
------------------------------ ------------- ------------- -------------- ------------
At 1 January 2019 154.2 491.7 380.1 1,026.0
Issue of Ordinary Shares 2.3 7.7 0.9 10.9
Purchase of ESOP Trust shares - - (3.6) (3.6)
Provision for share-based
payments - - 12.0 12.0
Profit for the year - - 164.3 164.3
Other comprehensive expense - - (78.1) (78.1)
At 1 January 2020 156.5 499.4 475.6 1,131.5
Issue of Ordinary Shares 14.6 18.1 1.9 34.6
Purchase of ESOP Trust shares - - (1.5) (1.5)
Provision for share-based
payments - - 11.3 11.3
Loss for the year - - (1,302.2) (1,302.2)
Other comprehensive expense - - (36.6) (36.6)
At 31 December 2020 171.1 517.5 (851.5) (162.9)
Consolidated Cash Flow Statement
For the year ended 31 December 2020
2020 2019
US$ million US$ million
-----------------------------------------------------------------------
Net cash from operating activities 610.6 1,108.7
------------ ------------
Investing activities:
Capital expenditure (266.6) (241.4)
Decommissioning pre-funding (5.4) (9.9)
Decommissioning expenditure (48.9) (35.3)
Receipts from sublease income 26.7 20.2
Proceeds from disposal of oil and gas properties 2.7 4.2
Net cash used in investing activities (291.5) (262.2)
Financing activities:
Issuance of Ordinary Shares 30.2 4.7
Net (purchase)/release of ESOP Trust shares (0.4) 1.1
Warrant cash consideration - (13.8)
Proceeds from drawdown of bank loans 35.0 -
Repayment of bank loans (52.3) (399.7)
Lease liability payments (181.0) (224.7)
Interest paid (230.4) (251.9)
------------ ------------
Net cash from financing activities (398.9) (884.3)
------------ ------------
Currency translation differences relating to cash and cash equivalents (10.0) (8.7)
------------ ------------
Net decrease in cash and cash equivalents (89.8) (46.5)
------------ ------------
Cash and cash equivalents at the beginning of the year 198.1 244.6
------------ ------------
Cash and cash equivalents at the end of the year 108.3 198.1
------------ ------------
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 31 December 2020
1. General information
Premier Oil plc is a limited liability company incorporated in
Scotland and listed on the London Stock Exchange. The address of
the registered office is 4th Floor, Saltire Court, 20 Castle
Terrace, Edinburgh EH1 2EN, United Kingdom. This preliminary
announcement was authorised for issue in accordance with a
resolution of the Board of Directors on 17 March 2021.
The financial information for the year ended 31 December 2020
set out in this announcement does not constitute statutory accounts
within the meaning of Section 434 of the Companies Act 2006.
Statutory accounts for the year ended 31 December 2019 were
approved by the Board of Directors on 4 March 2020 and delivered to
the Registrar of Companies and those for 2020 will be delivered
following the Company's Annual General Meeting ('AGM'). The auditor
has reported on the 2020 accounts; their audit report was
unqualified, but did draw attention to the material uncertainties
that exist which may cast significant doubt on the Group's ability
to continue as a going concern. Further information relating to the
going concern assumption is provided in the Financial Review,
including details on the material uncertainties.
Basis of preparation
The financial information has been prepared in accordance with
international accounting standards in conformity with the
requirements of the Companies Act 2006 and International Financial
Reporting Standards adopted pursuant to Regulation (EC) No.
1606/2002 as it applies in the European Union ('IFRS'). However,
this announcement does not itself contain sufficient information to
comply with IFRS. The Company will publish full financial
statements that comply with IFRS at the end of March 2021 on the
Company's website.
The financial information has been prepared under the historical
cost convention except for the revaluation of financial instruments
and certain oil and gas properties at the transition date to IFRS.
These financial statements are presented in US dollars since that
is the currency in which the majority of the Group's transactions
are denominated.
The financial information has been prepared on the going concern
basis. Further information relating to the going concern assumption
is provided in the Financial Review, including details on the
material uncertainties in relation to (1) management's ability to
complete the Corporate Actions; and (2) should the Corporate
Actions fail to complete, management's ability to complete an
alternative restructuring of its existing debt facilities and
certain hedging liabilities and obtain covenant deferrals or
waivers in the intervening period to prevent its existing debt
falling due within the going concern period.
Accounting Policies
The accounting policies applied in this announcement are
consistent with those of the annual financial statements for the
year ended 31 December 2019, as described in those annual financial
statements. A number of amendments to existing standards and
interpretations were applicable from 1 January 2020. The adoption
of these amendments did not have a material impact on the Group's
financial statements for the year ended 31 December 2020.
2. Operating segments
The Group's operations are located and managed in five business
units; namely the Falkland Islands, Indonesia, Vietnam, the United
Kingdom, and the Rest of the World. The results for Pakistan, the
disposal of which completed in the prior year, are reported as a
discontinued operation in the prior year.
Some of the business units currently do not generate revenue or
have any material operating income.
The Group is only engaged in one business of upstream oil and
gas exploration and production.
2020 2019
US$ million US$ million
----------------------------------------------------
Revenue:
Indonesia 144.7 172.2
Vietnam 103.7 198.6
United Kingdom 701.0 1,213.9
Total Group sales revenue 949.4 1,584.7
Interest and other finance revenue 0.8 2.4
------------ ------------
Total Group revenue from continuing operations 950.2 1,587.1
------------ ------------
Group operating (loss)/profit:
Indonesia 59.8 90.9
Vietnam 19.4 96.2
United Kingdom (109.9) 291.7
Rest of the World(1) (235.4) (0.9)
Unallocated (2) (77.7) (22.9)
------------ ------------
Group operating (loss)/profit (343.8) 455.0
Interest revenue, finance and other gains 84.8 31.4
Finance costs, other finance expenses and losses (346.3) (383.9)
(Loss)/profit before tax from continuing operations (605.3) 102.5
Tax (696.9) 52.5
------------ ------------
(Loss)/profit after tax from continuing operations (1,302.2) 155.0
------------ ------------
Profit from discontinued operations - 9.3
------------ ------------
2020 2019
US$ million US$ million
-----------------------------------------
Balance sheet
Segment assets:
Falkland Islands 504.4 680.0
Indonesia 430.0 481.5
Vietnam 378.2 437.8
United Kingdom 3,040.8 4,060.3
Rest of the World 179.7 179.4
Unallocated(2) 126.9 253.4
Total assets 4,660.0 6,092.4
Liabilities:
Falkland Islands (5.6) (13.0)
Indonesia (206.7) (216.5)
Vietnam (281.2) (324.3)
United Kingdom (2,020.7) (2,041.7)
Rest of the World (31.8) (34.5)
Unallocated(2) (2,276.9) (2,330.9)
------------ ------------
Total liabilities (4,822.9) (4,960.9)
------------ ------------
Other information
Capital additions and acquisitions:
Falkland Islands 24.7 30.0
Indonesia 11.6 72.1
Pakistan - 1.3
Vietnam 2.4 5.0
United Kingdom 276.3 142.6
Rest of the World 58.5 61.2
------------ ------------
Total capital additions and acquisitions 373.5 312.2
------------ ------------
2020 2019
US$ million US$ million
----------------------------------------------------------
Depreciation, depletion, amortisation and impairment: (3)
Indonesia 50.1 44.5
Vietnam 44.1 60.0
United Kingdom 566.6 652.6
Rest of the World 10.5 0.8
------------ ------------
Total DD&A and impairment (continuing operations) 671.3 757.9
------------ ------------
(1) The Group operating loss relating to the Rest of the World
is primarily driven by the write-off to non-Sea Lion Falkland
Islands exploration and evaluation assets in the period.
(2) Unallocated expenditure, assets and liabilities include
amounts of a corporate nature and not specifically attributable to
a geographical segment. These items include corporate general and
administration costs, new venture and pre-licence exploration
costs, cash and cash equivalents, mark-to market valuations of
commodity contracts, warrants and other short and long-term
debt.
(3) Includes DD&A in respect of right-of-use assets.
Out of the total Group worldwide sales revenues of US$949.4
million (2019: US$1,584.7 million), revenues of US$701.0 million
(2019: US$1,213.9 million) arose from sales of oil and gas to
customers located in the UK. Included within the total revenues
were revenues of US$799.9 million (2019: US$1,539.1 million) from
contracts with customers. This was in addition to hedging gains of
US$149.5 million (2019: US$45.6 million).
Included in assets of the United Kingdom segment are non-current
assets (excluding deferred tax assets) of US$2,000.1 million (2019:
US$2,286.3 million). Included in depreciation, depletion,
amortisation and impairment is an impairment charge in relation to
the UK of US $143.8 million (2019: US$ 41.5 million net
charge).
Revenue from two customers (2019: three customers) each exceeded
10 per cent of the Group's consolidated revenue. Sales to one
customer in the UK amounted to US$128.8 million (2019: two
customers for US$318.8 million and US$187.3 million). Sales to one
customer in Indonesia totalled US$113.0 million (2019: one customer
amounting to US$160.4 million).
3. Costs of operation
2020 2019
US$ million US$ million
------------------------------------
Operating costs 273.8 322.6
Gas purchases 18.4 21.6
Stock overlift/(underlift) movement 28.0 (10.5)
Royalties 4.5 9.1
324.7 342.8
4. Tax
2020 2019
US$ million US$ million
------------------------------------------------------------
Current tax:
UK corporation tax on profits (22.6) (6.0)
Overseas tax 44.6 81.6
Adjustments in respect of prior years 11.1 (24.5)
------------ ------------
Total current tax 33.1 51.1
------------ ------------
Deferred tax:
UK corporation tax 687.3 (94.0)
Overseas tax (23.5) (9.6)
------------ ------------
Total deferred tax 663.8 (103.6)
------------ ------------
Tax charge/(credit) on (loss)/profit on ordinary activities 696.9 (52.5)
------------ ------------
The tax charge for the year can be reconciled to the
(loss)/profit per the consolidated income statement as follows:
2020 2019
US$ million US$ million
------------------------------------------------------------------------------------------
Group (loss)/profit on ordinary activities before tax (605.3) 102.5
------------ ------------
Group (loss)/profit on ordinary activities before tax at 32.8% weighted average rate
(2019:
46.0%) (198.5) 47.2
Tax effects of:
(Income)/expenses that are not (taxable)/deductible in determining taxable profit(1) 64.7 16.2
Financing costs disallowed for UK supplementary charge 20.3 19.4
Non-deductible field expenditure - 11.3
Tax and tax credits not related to (loss)/profit before tax (mainly ring fenced
expenditure
supplement) (12.1) (89.2)
Unrecognised tax losses(2) 827.1 10.0
Effect of change in foreign exchange 1.8 0.3
Adjustments in respect of prior years (9.1) (40.3)
Recognition that decommissioning provision will unwind at 50% 2.7 (8.0)
Recognition of deferred tax asset - (19.4)
Tax charge/(credit) for the year 696.9 (52.5)
Effective tax rate for the year (115.1%) (51.2%)
------------ ------------
(1) Includes the tax effect of the US$194 million exploration
write-off in respect of the Falkland Islands licences.
(2) Includes US$817 million of unrecognised deferred tax asset
in respect of ring fence tax losses, decommissioning asset and
allowances.
The UK deferred tax charge arises primarily due to the
derecognition of previously recognised UK ring fence tax losses and
allowances. It is no longer appropriate to recognise a deferred tax
asset of US$817.2 million of the Group's ring fence tax losses,
decommissioning asset and allowances at 31 December 2020 based on
expected future profitability. The future taxable profits represent
those solely relating to Premier's existing assets and do not
include those assets associated with the proposed merger. The
reduction from the prior year primarily relates to the exclusion of
taxable profits associated with previously proposed acquisitions
and the reduction in management's long-term price assumptions.
More detail on assumptions applied in assessing the
recoverability of deferred tax assets is provided in note 5.
The weighted average rate is calculated based on the tax rates
weighted according to the profit or loss before tax earned by the
Group in each jurisdiction. The change in the weighted average rate
year-on-year relates to the mix of profit and loss in each
jurisdiction.
The future effective tax rate for the Group is impacted by the
mix of jurisdictions in which the Group operates (with corporation
tax rates ranging from 19 per cent to 44 per cent), assumptions
around future oil prices and changes to tax rates and
legislation.
Post balance sheet event note
On 3 March 2021 it was announced in the UK budget that the UK
non-ring fence corporation tax rate will increase from 19 per cent
to 25 per cent with effect from 2023. The Group do not currently
recognise any deferred tax assets in respect of UK non-ring fence
tax losses and therefore this rate change did not impact the
disclosed results.
5. Deferred tax
2020 2019
US$ million US$ million
-------------------------
Deferred tax assets 869.7 1,556.1
Deferred tax liabilities (106.3) (129.9)
763.4 1,426.2
(Charged)
/credited to Credited to At 31 December
At 1 January 2020 Exchange movements income statement retained earnings 2020
US$ million US$ million US$ million US$ million US$ million
-------------------
UK deferred
corporation tax:
Fixed assets and
allowances (513.4) - 44.2 - (469.2)
Decommissioning 439.6 (0.4) (8.9) - 430.3
Tax losses and
allowances 1,536.6 (0.6) (688.2) - 847.8
Investment
allowance 82.5 - (46.7) - 35.8
Derivative
financial
instruments 10.8 - 12.4 1.9 25.1
----------------- ------------------ ------------------ ------------------ ------------------
Total UK deferred
corporation tax 1,556.1 (1.0) (687.2) 1.9 869.8
----------------- ------------------ ------------------ ------------------ ------------------
Overseas deferred
tax 1 (129.9) - 23.5 - (106.4)
----------------- ------------------ ------------------ ------------------ ------------------
Total 1,426.2 (1.0) (663.7) 1.9 763.4
----------------- ------------------ ------------------ ------------------ ------------------
(Charged)
/credited to Credited to At 31 December
At 1 January 2019 Exchange movements income statement retained earnings 2019
US$ million US$ million US$ million US$ million US$ million
-------------------
UK deferred
corporation tax:
Fixed assets and
allowances (609.2) 0.1 95.7 - (513.4)
Decommissioning 376.8 2.1 60.7 - 439.6
Tax losses and
allowances 1,602.5 0.8 (66.7) - 1,536.6
Investment
allowance 77.8 0.1 4.6 - 82.5
Derivative
financial
instruments (13.8) (0.1) (0.3) 25.0 10.8
----------------- ------------------ ------------------ ------------------ ------------------
Total UK deferred
corporation tax 1,434.1 3.0 94.0 25.0 1,556.1
----------------- ------------------ ------------------ ------------------ ------------------
Overseas deferred
tax 1 (139.5) - 9.6 - (129.9)
----------------- ------------------ ------------------ ------------------ ------------------
Total 1,294.6 3.0 103.6 25.0 1,426.2
----------------- ------------------ ------------------ ------------------ ------------------
1 The overseas deferred tax relates mainly to temporary
differences associated with fixed asset balances.
The Group's deferred tax assets at 31 December 2020 are
recognised to the extent that taxable profits are expected to arise
in the future against which the UK ring fence tax losses and
allowances can be utilised. In accordance with paragraph 37 of IAS
12 - 'Income Taxes', the Group reassessed its deferred tax assets
at 31 December 2020 with respect to UK ring fence tax losses and
allowances. The corporate model used to assess whether it is
appropriate to recognise the Group's deferred tax losses and
allowances was re-run, using an oil price assumption of US$51/bbl
in 2021, US$55/bbl in 2022 and US$60/bbl in 'real' terms thereafter
(2019: US$65/bbl in 2020 and 2021, US$70/bbl in 2022 and US$70/bbl
in 'real' terms thereafter) and gas price assumption of 37.5p/therm
in 2021, 42.5p/therm in 2022 and 42.5p/therm in 'real' terms
thereafter. These price assumptions are consistent with that used
when assessing the Group's underlying assets for impairment. As at
31 December 2019, approximately US$267 million of the recognised
deferred tax asset was supported by future taxable profits
associated with previously proposed acquisitions which have since
been terminated. As at 31 December 2020, the
future taxable profits in the corporate model represent those
relating to Premier's existing assets and do not include those
associated with the proposed merger. The proposed merger will
represent a reverse takeover by Chrysaor and, therefore, Premier
will represent the accounting acquiree. On the basis that Premier
will represent the accounting acquiree, and therefore does not have
control of the future taxable profits of the enlarged group as at
the balance sheet date, future taxable profits associated with the
merger were not included in the corporate model as at 31 December
2020. The results of the corporate model concluded that it is no
longer appropriate to recognise a deferred tax asset of US$817.2
million of the Group's UK ring fence tax losses, decommissioning
asset and allowances at 31 December 2020 based on expected future
profitability. The reduction from the prior year primarily relates
to the exclusion of taxable profits associated with previously
proposed acquisitions and the reduction in management's long-term
price assumptions.
In addition to the above, there are carried forward non-ring
fence UK tax losses of approximately US$425.3 million (2019:
US$376.4 million) and overseas tax losses of US$288.7 million
(2019: US$267.7 million) for which a deferred tax asset has not
been recognised.
None of the UK tax losses (ring fence and non-ring fence) have a
fixed expiry date for tax purposes.
No deferred tax has been provided on unremitted earnings of
overseas subsidiaries, following a change in UK tax legislation in
2009 which exempted foreign dividends from the scope of UK
corporation tax, where certain conditions are satisfied.
The recognition of the Group's UK deferred tax asset is
sensitive to commodity prices. A US$5/bbl reduction in the
long-term oil price would result in an additional deferred tax
asset derecognition charge of US$40 million. A 5p/therm reduction
in the long-term gas price would result in an additional deferred
tax asset derecognition charge of US$86 million.
6. (Loss)/earnings per share
The calculation of basic (loss)/earnings per share is based on
the (loss)/profit after tax and the weighted average number of
Ordinary Shares in issue during the year. Basic and diluted
earnings per share are calculated as follows:
2020 2019
US$ million US$ million
------------------------------------------------------------------------------------------ ------------ ------------
(Loss)/earnings
(Loss)/earnings for the purpose of diluted earnings per share on continuing operations (1,302.2) 155.0
Profit from discontinued operations - 9.3
------------------------------------------------------------------------------------------ ------------ ------------
(Loss)/earnings for the purpose of diluted earnings per share on continuing and
discontinued
operations (1,302.2) 164.3
------------ ------------
Number of shares (millions)
Weighted average number of Ordinary Shares for the purpose of basic earnings per share 887.7 826.2
Effects of dilutive potential Ordinary Shares:
Contingently issuable shares (2020: anti-dilutive) - 76.9
------------ ------------
Weighted average number of Ordinary Shares for the purpose of diluted earnings per share 887.7 903.1
------------ ------------
(Loss)/earnings per share from continuing operations (cents)
Basic (146.7) 18.8
Diluted (146.7) 17.2
------------ ------------
Earnings per share from discontinued operations (cents)
Basic - 1.1
Diluted - 1.0
------------ ------------
As at 31 December 2020, there are 57.8 million potentially
dilutive contingently issuable shares related to unexercised equity
warrants and share options, the inclusion of which gives rise to an
anti-dilutive loss per share.
7. Intangible exploration and evaluation ('E&E') assets
Total
Oil and Gas Properties US$ million
Cost:
At 1 January 2019 812.6
Exchange movements 1.3
Additions during the year 129.3
Transfer to PP&E (1.9)
Exploration expense (1) (7.3)
------------
At 31 December 2019 934.0
Exchange movements (12.5)
Additions during the year 85.5
Exploration expense (1) (221.7)
------------
At 31 December 2020 785.3
------------
(1) Expensed in the income statement together with new venture
expenditure of US$69.3 million (2019: US$14.0 million) and US$2.4
million of E&E expenditure that was charged directly to the
income statement, resulting in a total exploration expense and new
venture costs of US$293.4 million. In the current period, new
venture expenditure includes costs incurred in respect to Corporate
Actions, including previously proposed acquisitions and the
proposed merger with Chrysaor.
The amounts for intangible E&E assets represent costs
incurred on active exploration projects. These amounts are written
off to the income statement as exploration expense unless
commercial reserves are established or the determination process is
not completed and there are no indications of impairment.
The outcome of ongoing exploration, and therefore whether the
carrying value of E&E assets will ultimately be recovered, is
inherently uncertain. To the extent that we have an active licence
to continue to explore for resources and have an intention to
continue exploration activity, the exploration cost associated with
the licence will remain capitalised as an E&E asset on the
balance sheet. Once exploration activity has completed and we have
no further intention to explore the licence for resources, costs
capitalised up to that point will be expensed and no further costs
associated with the licence will be capitalised.
During the year, exploration expenditure of US$194.1 million has
been written off for costs previously capitalised for exploration
prospects in the North Falklands basin which will not be developed
as part of the Sea Lion Phase 1 project. In addition, the drilling
of the Charlie-1 well in Area A in Alaska encountered
non-commercial gas condensate for which US$27.1 million of costs
have been expensed in the year. The balance carried forward is
predominantly in relation to the Sea Lion (Falkland Islands) and
Tuna (Indonesia) projects, as well as our share of expenditure on
the Zama prospect in Mexico.
Based on the continuation of commercial and technical evaluation
activities and in the absence of data to suggest that the carrying
value of capitalised expenditure incurred to date could not be
recovered in full, capitalised E&E costs in respect to Sea Lion
(Falkland Islands) continue to be carried on the balance sheet.
During 2020, terms of a farm-out, which remains subject to
approval, were agreed with Navitas Petroleum LP and planning for
the development of Sea Lion continued to be progressed, albeit at a
reduced level given the macro environment. A joint venture approved
work programme and budget is in place for 2021 and an extension of
the Sea Lion licence to November 2022 has been agreed by the
Falkland Islands Government. Should the proposed merger with
Chrysaor complete, it is anticipated that the enlarged group will
have significant financial resources to support a future
development decision. However, this will remain subject to the
completion of technical and commercial evaluation activities by the
Board of the enlarged group. Because the proposed merger will
represent a reverse takeover by Chrysaor, on completion Sea Lion
will be measured at fair value, which could differ to its current
carrying value. Should the merger not complete, Premier would have
to identify alternative finance options for Sea Lion. In those
circumstances, the lack of a clear financing solution for the
project would be considered as an indicator of impairment.
8. Property, plant and equipment
Right-of-use assets Other fixed
Oil and gas properties US$ million assets Total
US$ million US$ million US$ million
=============================================
Cost:
At 1 January 2019 7,807.6 803.3 57.3 8,668.2
Exchange movements (1.7) (0.6) 1.1 (1.2)
Re-measurement of lease liabilities - 8.3 - 8.3
Additions and changes in decommissioning
estimates 180.1 - 2.8 182.9
Transferred from E&E 1.9 - - 1.9
Disposals (1.3) - - (1.3)
====================== =================== ============ ============
At 31 December 2019 7,986.6 811.0 61.2 8,858.8
====================== =================== ============ ============
Exchange movements (0.7) 1.0 0.7 1.0
Re-measurement of lease liabilities - 2.5 - 2.5
Additions and changes in decommissioning
estimates 285.3 - 2.7 288.0
At 31 December 2020 8,271.2 814.5 64.6 9,150.3
Amortisation, depreciation and impairment:
At 1 January 2019 5,568.2 - 51.1 5,619.3
Exchange movements (1.1) - 0.9 (0.2)
Charge for the year 489.4 223.0 4.0 716.4
Net impairment credit 41.5 - - 41.5
At 31 December 2019 6,098.0 223.0 56.0 6,377.0
Exchange movements (0.8) 0.3 0.7 0.2
Charge for the year 399.6 124.9 3.0 527.5
Impairment charge 143.8 - - 143.8
At 31 December 2020 6,640.6 348.2 59.7 7,048.5
Net book value:
At 31 December 2019 1,888.6 588.0 5.2 2,481.8
====================== =================== ============ ============
At 31 December 2020 1,630.6 466.3 4.9 2,101.8
====================== =================== ============ ============
Finance costs that have been capitalised within oil and gas
properties during the year total US$3.5 million (2019: US$4.3
million), at a weighted average interest rate of 7.4 per cent
(2019: 8.2 per cent).
Amortisation and depreciation of oil and gas properties is
calculated on a unit-of-production basis, using the ratio of oil
and gas production in the period to the estimated quantities of
proved and probable reserves on an entitlement basis at the end of
the period plus production in the period, on a field-by-field
basis. Proved and probable reserve estimates are based on a number
of underlying assumptions including oil and gas prices, future
costs, oil and gas in place and reservoir performance, which are
inherently uncertain. Management uses established industry
techniques to generate its estimates and regularly references its
estimates against those of joint venture partners or external
consultants. However, the amount of reserves that will ultimately
be recovered from any field cannot be known with certainty until
the end of the field's life.
The current period charge includes US$52.7 million relating to
the net effect of changes in decommissioning provisions on assets
previously depreciated to nil net book value as a result of a
change in decommissioning discount rates.
Impairment charge
In the period, Group-wide indicators of impairment, being a
reduction in management's long-term oil and gas price assumptions
and decommissioning discount rate, were identified. The impairment
charge in the current year primarily relates to Solan (UK) as a
result of a reduction in management's long-term oil price
assumption and a decrease in reserves associated with future
investments decisions. The impairment charge of US$143.8 million
(pre-tax) (2019: net impairment charge of US$41.5 million) was
calculated by comparing the future discounted pre-tax cash flows
expected to be derived from production of commercial reserves (the
value-in-use) against the carrying value of the cash-generating
unit. When testing producing assets for impairment, future cash
flows were estimated using the following oil price assumption:
US$51/bbl in 2021, US$55/bbl in 2022 and US$60/bbl in 'real' terms
thereafter (2019: US$65/bbl in 2020 and 2021, US$70/bbl in 2022
followed by a long-term price of US$70/bbl (real) thereafter) and
were discounted using a pre-tax discount rate of 9 per cent for the
UK assets (2019: 9 per cent) and 12.5 per cent for the non-UK
assets (2019: 12.5 per cent). Assumptions involved in impairment
measurement include estimates of commercial reserves and production
volumes, future oil and gas prices, discount rates and the level
and timing of expenditures, all of which are inherently
uncertain.
Sensitivity
A US$5/bbl reduction in the long-term oil price (to US$55/bbl
(real)) would increase the impairment charge by US$72.1 million, of
which US$67.1 million would be in respect of goodwill associated
with the Catcher cash-generating unit. A 1 per cent increase in the
discount rates used when determining the value-in-use for each oil
and gas property would increase the impairment charge by US$12.3
million of which US$10.9 million would be in respect to goodwill
associated with the Catcher cash-generating unit.
Goodwill
Goodwill of US$240.8 million has been specifically assigned to
the Catcher field in the UK, which is considered the
cash-generating unit for the purposes of any impairment testing of
this goodwill. The Group tests goodwill annually for impairment, or
more frequently if there are indications that goodwill might be
impaired. The recoverable amounts are determined from value-in-use
calculations with the same key assumptions as noted above for the
impairment calculations. The discount rate used is 9 per cent
(2019: 9 per cent). The value-in-use forecast takes into
consideration cash flows which are expected to arise during the
life of the Catcher field as a whole, currently expected to be
around 2028. This period exceeds five years but is believed to be
appropriate as it is underpinned by estimates of commercial
reserves provided by our in-house reservoir engineers using
industry standard reservoir estimation techniques. The headroom
between the recoverable amount and the carrying amount of the
Catcher cash-generating unit, including the goodwill, is US$15.2
million (2019: US$203.8 million).
The key assumptions applied in the measurement of the
value-in-use of the Catcher asset are discount rate, oil prices and
forecasted recoverable reserves. A change in any of these key
assumptions would cause the asset's carrying amount to exceed its
recoverable amount as disclosed above.
Right-of-use assets
There were no new leases entered into during the period. The
re-measurement above represents the net impact of re-measurements
of the Catcher FPSO lease which were driven by changes in assumed
Cessation of Production ('COP') dates during the year based on
field performance and the extension of the Chim S á o lease by two
years to 2030 to reflect revised COP date.
In addition to the above the Group has a net investment in
sublease of US$57.1 million (2019: US$75.7 million), of which
US$53.1 million is classified as a long-term receivable and US$4.0
million as trade and other receivables. The net investment in
sublease represents our joint operations partners' share of lease
liabilities on lease arrangements for which Premier has entered
into in its role as operator as sole signatory on behalf of the
joint operation and the asset is controlled by the joint
operation.
Income of US$4.2 million, which predominantly represents
unwinding of the net investment in sublease, has been recognised as
finance income in the year.
9. Leases
2020 2019
US$ million US$ million
At 1 January 732.5 899.6
Re-measurement 6.9 8.3
Finance costs 45.7 50.0
Lease payments (186.3) (224.7)
Exchange differences 0.8 (0.7)
===================== ============ ============
At 31 December 599.6 732.5
============ ============
Classified as:
Short-term 74.3 149.7
Non-current 525.3 582.8
------------ ------------
Expenses related to both short-term and low value lease
arrangements are considered to be immaterial for reporting
purposes. During the period variable lease costs of US$6.6 million
(2019: US$23.3 million) were expensed. Lease liabilities have been
classified as either short-term or non-current in the balance sheet
according to whether they are expected to be settled within 12
months of the balance sheet date.
The significant portion of the Group's lease liabilities
represent lease arrangements for FPSO vessels on the Catcher and
Chim Sáo assets. The lease liabilities, and associated
right-of-use-assets have been calculated by reference to
in-substance fixed lease payments in the underlying agreements
incurred throughout the non-cancellable period of the lease along
with periods covered by options to extend the lease where the Group
is reasonably certain that such options will be exercised. When
assessing whether extension options were likely to be exercised,
assumptions are consistent with those applied when testing for
impairment.
There were no new leases entered into during the period. The
re-measurement above represents the net impact of re-measurements
of the Catcher FPSO lease which were driven by changes in assumed
Cessation of Production ('COP') dates during the year based on
field performance and the extension of the Chim Sáo lease by two
years to 2030 to reflect the revised COP date.
Under the modified retrospective transition method, lease
payments were discounted at 1 January 2019 using an incremental
borrowing rate representing the rate of interest that Premier would
have to pay to borrow over a similar term, and with a similar
security, the funds necessary to obtain an asset of a similar value
to the right-of-use asset in a similar economic environment. The
incremental borrowing rate applied to each lease was determined by
taking into account the risk-free rate, adjusted for factors such
as the credit rating linked to the life of the underlying lease
agreement. The weighted average incremental borrowing rate applied
by Premier upon transition was 7.2 per cent. Incremental borrowing
rates applied to individual leases ranged between 7.2 per cent and
9.2 per cent.
10. Notes to the cash flow statement
2020 2019
US$ million US$ million
---------------------------------------------------------
(Loss)/profit before tax for the year (605.3) 102.5
Adjustments for:
Depreciation, depletion, amortisation and impairment 671.3 757.9
Other operating (income)/costs (3.5) 2.9
Exploration expense 227.1 7.3
Provision for share-based payments 6.3 7.1
Interest revenue and finance gains (84.8) (31.4)
Finance costs and other finance expenses 346.3 383.9
Profit on disposal of non-current assets (1.1) (4.2)
Operating cash flows before movements in working capital 556.3 1,226.0
Decrease/(increase) in inventories 3.6 (3.8)
Decrease/(increase) in receivables 54.3 (74.9)
Increase/(decrease) in payables 12.7 (19.5)
------------ ------------
Cash generated by operations 626.9 1,127.8
Income taxes received 2.0 (61.2)
Interest income received 1.2 6.2
------------ ------------
Net cash from continuing operating activities 630.1 1,072.8
------------ ------------
Net cash from discontinued operating activities - 7.2
------------ ------------
Net cash from operating activities 630.1 1,080.0
------------ ------------
Movement in JV cash (19.5) 28.7
------------ ------------
Total net cash from operating activities 610.6 1,108.7
------------ ------------
Analysis of changes in net debt:
2020 2019
US$ million US$ million
a) Reconciliation of net cash flow to movement in net debt:
Movement in cash and cash equivalents (89.8) (46.5)
Proceeds from drawdown of bank loans (35.0) -
Repayment of bank loans 52.3 399.7
Non-cash movements on debt and case balances (primarily foreign exchange) (16.1) (12.3)
(Increase)/reduction in net debt in the year (88.6) 340.9
Opening net debt (1,989.8) (2,330.7)
------------ ------------
Closing net debt (2,078.4) (1,989.8)
------------ ------------
b) Analysis of net debt:
Cash and cash equivalents 108.3 198.1
Borrowings (2,186.7) (2,187.9)
------------ ------------
Total net debt (2,078.4) (1,989.8)
------------ ------------
The carrying amounts of the borrowings on the balance sheet are
stated net of the unamortised portion of the refinancing fees of
US$5.7 million (2019: US$18.1 million).
11. Subsequent Events
Proposed Merger with Chrysaor Holdings Limited
Subsequent to year-end, the proposed merger with Chrysaor
Holdings Ltd has been progressed as planned with completion
expected to occur 31 March 2021.
During January 2021 a convening hearing was held in connection
with the restructuring plans required to implement the merger. At
the hearing the court granted Premier's request to start the
restructuring plans process and the Group convened creditor
meetings for February 2021. At these meetings the restructuring
plans to implement the merger were approved by the requisite
proportion of lenders. The restructuring plans remain subject to
approval by the Scottish Court of Session with the sanction hearing
scheduled to commence on 19 March 2021.
All elections were received from senior lenders in respect of
the take-up of a partial cash alternative capped at US$175 million
(the 'Cash-Out Option'). As a result of the elections, the take-up
of the Cash-Out Options is expected to be less than US$175 million
and will be satisfied through funds received from senior creditors
able to elect to subscribe for new shares, in cash at a pre-agreed
price, which would have been issued to other creditors if they had
not elected the Cash-Out Option. Therefore, the enlarged group
expects to retain the US$175 million of cash that it may otherwise
have needed to use to fund the Cash-Out Option.
The satisfaction of all regulatory conditions and the receipt of
anti-trust approval was progressed with all necessary conditions
met and approvals granted by 22 February 2021.
12. External audit
This preliminary announcement is consistent with the audited
financial statements of the Group for the year-ended 31 December
2020.
13. Publication of financial statements
It is anticipated that the full Annual Report and Financial
Statements will be published on the Company's website at the end of
March 2021 ( www.premier-oil.com ).
14. Annual General Meeting
It is anticipated that the Annual General Meeting will be held
on Wednesday 23 June 2021.
Glossary
Non-IFRS measures
The Group uses certain measures of performance that are not
specifically defined under IFRS or other generally accepted
accounting principles. These non-IFRS measures are EBITDAX,
Operating cost per barrel, DD&A per barrel, Net Debt and
Liquidity and are defined below.
-- EBITDAX: Earnings before interest, tax, depreciation,
amortisation, impairment, exploration spend and other one off
items. In the current year it also excludes the gain on disposal
recognised in the income statement. This is a useful indicator of
underlying business performance.
-- Free cash flow: Positive cash flow generation from operating,
investing and financing activities excluding drawdowns from and
repayments of borrowing facilities and equity issuances.
-- Operating cost per barrel: Operating costs for the year
divided by working interest production. This is a useful indicator
of ongoing operating costs from the Group's producing assets.
-- DD&A per barrel: Amortisation and depreciation of oil and
gas properties and right-of-use assets for the year divided by
working interest production. This is a useful indicator of ongoing
rates of depreciation and amortisation of the Group's producing
assets.
-- Net Debt: The net of cash and cash equivalents and long-term
debt recognised on the balance sheet. This is an indicator of the
Group's indebtedness and capital structure.
-- Liquidity: The sum of cash and cash equivalents on the
balance sheet, and the undrawn amounts available to the Group on
our principal facilities, including letters of credit facilities,
less our JV partners' share of cash balances. This is a key measure
of the Group's financial flexibility and ability to fund day to day
operations.
Each of the above non-IFRS measures are presented within the
Financial Review with detail on how they are reconciled to the
statutory financial statements.
OIL AND GAS RESERVES
Working interest reserves at 31 December 2020
Working interest basis
Falkland
Islands Indonesia UK Vietnam Mexico Total
----------- --------------- ---------------- -------------- ----------- ------------------------------
Oil
Oil and
Oil Oil Oil Oil Oil and NGLs
and and and and and NGLs Gas and
NGLs Gas NGLs Gas NGLs Gas NGLs Gas NGLs Gas Gas
------ --- ------ ------- ------- ------- ------ ------ ------ --- ------- ------------ -------
mmbbls bcf mmbbls bcf mmbbls bcf mmbbls bcf mmbbls bcf mmbbls bcf mmboe
------ --- ------ ------- ------- ------- ------ ------ ------ --- ------- ------------ -------
Group proved plus probable reserves:
At 1 January
2020 - - 1.09 156.79 56.84 357.30 14.16 19.39 - - 72.09 533.48 174.73
------ --- ------ ------- ------- ------- ------ ------ ------ --- ------- ------------ -------
Revisions - - (0.30) (17.10) 3.92 (12.54) 1.55 3.88 - - 5.17 (25.76) (0.65)
------ --- ------ ------- ------- ------- ------ ------ ------ --- ------- ------------ -------
Discoveries
and extensions - - - - - - - - - - - - -
------ --- ------ ------- ------- ------- ------ ------ ------ --- ------- ------------ -------
Acquisitions
and divestments - - - - (0.08) (0.01) - - - - (0.08) (0.01) (0.08)
------ --- ------ ------- ------- ------- ------ ------ ------ --- ------- ------------ -------
Production - - (0.23) (22.12) (11.99) (15.42) (2.52) (3.15) - - (14.74) (40.69) (22.62)
------ --- ------ ------- ------- ------- ------ ------ ------ --- ------- ------------ -------
At 31 December
2020 - - 0.56 117.57 48.69 329.33 13.19 20.12 - - 62.44 467.02 151.38
------ --- ------ ------- ------- ------- ------ ------ ------ --- ------- ------------ -------
Total Group developed and undeveloped reserves
Proved on
production - - 0.41 72.31 22.74 45.45 7.52 10.85 - - 30.67 128.61 54.95
------ --- ------ ------- ------- ------- ------ ------ ------ --- ------- ------ -------------
Proved
approved/justified
for development - - 0.07 19.99 7.80 155.66 0.55 1.95 - - 8.42 177.60 42.40
------ --- ------ ------- ------- ------- ------ ------ ------ --- ------- ------ -------------
Probably
on production - - 0.01 9.96 12.44 16.81 4.52 5.26 - - 16.97 32.03 22.94
------ --- ------ ------- ------- ------- ------ ------ ------ --- ------- ------ -------------
Probably
approved/justified
for development - - 0.07 15.31 5.71 111.41 0.60 2.06 - - 6.38 128.78 31.09
------ --- ------ ------- ------- ------- ------ ------ ------ --- ------- ------ -------------
At 31 December
2020 - - 0.56 117.57 48.69 329.33 13.19 20.12 - - 62.44 467.02 151.38
------ --- ------ ------- ------- ------- ------ ------ ------ --- ------- ------ -------------
1 Revision of gas in Indonesia based on observed depletion
behaviour in Gajah Puteri field and observed water ingress on other
Natuna A gas fields.
2 Revisions in the UK relate to better reservoir performance
observed in the Catcher Area, offset by revisions in Solan; earlier
anticipated Cessation of Production ('CoP') on Ravenspurn North and
Johnston, and earlier actual CoP in the Balmoral Area, Huntington
and Kyle.
3 Vietnam revision reflects a slightly better decline based on
production behaviour with a later CoP than anticipated last
year.
4 Proved plus probable gas includes 38.8bcf of fuel gas.
5. The Zama field (Mexico), Tuna field (Indonesia), Sea Lion
(Falkland Islands) and Tolmount East (UK) remain categorised as
contingent resources and consequently have no booked reserves.
6 The divestment in the UK relates to the reduction in working
interest in Laverda from 54 per cent to 50 per cent.
Premier categorises petroleum resources in accordance with the
June 2018 SPE/WPC/AAPG/SPEE/SEG/SPWLA/EAGE Petroleum Resource
Management System ('SPE PRMS'). Proved and probable reserves are
based on operator, third-party reports and internal estimates and
are defined in accordance with the Statement of Recommended
Practice ('SORP') issued by the Oil Industry Accounting Committee
('OI-AC'), dated July 2001.
The Group provides for amortisation of costs relating to
evaluated properties based on direct interests on an entitlement
basis, which incorporates the terms of the PSCs in Indonesia and
Vietnam. On an entitlement basis, reserves were 143.5 mmboe as at
31 December 2020 (2019: 164.4 mmboe). This was calculated at
year-end 2020, using the following oil price assumption: US$51/bbl
in 2021, US$55/bbl in 2022 and US$60/bbl in real terms thereafter
(2019: US$65/bbl in 2020 and 2021, US$70/bbl in 2022 and US$70/bbl
in real terms thereafter).
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