TIDMPMO
RNS Number : 0604F
Premier Oil PLC
05 March 2020
Premier Oil plc
"Premier" or the "Company" or the "Group"
Full Year Results for the year ended 31 December 2019
5 March 2020
Press Release
Tony Durrant, Chief Executive Officer, commented:
"Premier made significant progress against its strategic targets
during 2019. Strong operational performance resulted in record free
cash flows and reducing debt levels. We took material steps to
commercialise our reserve and resource base and added to our
exploration acreage position. The proposed acquisitions will add
material cash-generative UK production. Premier is committed to
being a responsible operator and today announces that all operated
projects will be developed on a net zero emissions basis."
Operational highlights
-- Production of 78.4 kboepd, at upper end of guidance; 2020
guidance of 70-75 kboepd (before any contribution from the
announced UK acquisitions)
-- Catcher (UK) project payback reached; Catcher North and Laverda developments sanctioned
-- BIG-P (Indonesia) first gas delivered on schedule and below budget
-- Tolmount (UK) on track for first gas by year-end 2020, adding
20-25 kboepd (net, Premier 50 per cent); Tolmount East development
planning underway targeting 2020 2H sanction
-- Positive Zama (Mexico) appraisal campaign; unitisation and sales process underway
-- Heads of Terms signed for Sea Lion (Falkland Islands) and Tuna (Indonesia) farm downs
-- Accretive and strategic UK acquisitions, underwritten
financing and proposed extension of credit facilities announced;
court sanction hearing scheduled for 17-20 March 2020
-- New prospective acreage captured in Alaska and Indonesia;
high value near-term E&A wells planned with Charlie-1 (Alaska)
drilling ahead and Berimbau/Maraca (Brazil) to spud in Q3
Financial highlights
-- Increased profit after tax of US$164 million (2018: US$133 million)
-- Record free cash flow of US$327 million (2018: US$251
million); US$31/bbl cash margin (2018: US$26/bbl)
-- EBITDAX increased to US$1,230 million (2018: US$1,091
million, adjusted for the impact of IFRS16)
-- 2019 expenditure (opex of US$11/boe, total capex of US$273 million) below guidance
-- Net debt reduced to US$1.99 billion (2018: US$2.33 billion)
and covenant leverage ratio to 2.3x (2018: 3.1x)
-- Free cash flow generation forecast for 2020, driving continued debt reduction
Enquiries
Premier Oil plc
Tony Durrant, Chief Executive; Richard Rose, Finance Director
Tel: 020 7730 1111
Camarco
Billy Clegg, James Crothers Tel: 020 3757 4983
A presentation to analysts will be held at 9.30am today at
Premier Oil's offices at 23 Lower Belgrave Street, London SW1W 0NR
and will be webcast live on the Company's website at
www.premier-oil.com . A copy of this announcement is available for
download from our website at www.premier-oil.com .
CEO REVIEW
2019 was another year of strong operational and financial
delivery by Premier with significant progress made against the
Company's strategic objectives.
Commodity prices were slightly weaker during 2019 driven by
global trade tensions and ongoing concerns about the balance of
supply and demand. Despite this, the Group reported record free
cash flows and increased net profits.
Production
Group production averaged 78.4 kboepd (2018: 80.5 kboepd), at
the upper end of market guidance. This was driven by exceptionally
high uptime across the portfolio and outperformance from Premier's
operated flagship Catcher Area in the UK, which reached cash
payback in October.
Production by business 2019 2018
unit (kboepd)
Indonesia 11.5 13.2
----- -----
Pakistan(1) 1.3 5.3
----- -----
United Kingdom 54.2 46.8
----- -----
Vietnam 11.4 15.2
----- -----
Total 78.4 80.5
----- -----
(1) sold on 26 March 2019
Increased tax advantaged production from the UK offset lower
output from the Group's Asian assets. This change in production
mix, together with higher price realisations, continued tight cost
control and prudent management of capital investment, resulted in
increased cash margins year-on-year.
In South East Asia and the UK, Premier's two core producing
areas, the teams have continued to mature and execute incremental
investment opportunities to increase the reserves and field life of
the Group's assets. In December, Premier achieved first gas from
its operated Bison, Iguana and Gajah Puteri (BIG-P) fields
increasing deliverability from the Natuna Sea Block A PSC and
enabling the Group to meet increased Singapore demand for its
Indonesian gas. The safe and successful execution of BIG-P on
schedule and below budget builds on Premier's track record of
project delivery.
In the UK, a significant amount of activity is planned for 2020.
This includes the drilling of a third producer on the Solan field
West of Shetland, the development of two Catcher Area satellites in
the Central North Sea together with a Varadero infill well, and
infill drilling at Ravenspurn North in the Southern Gas Basin.
These investments have high returns and quick payback periods and
will help boost production in the second half of 2020 and early
2021.
Growth projects
The Premier-operated Tolmount development is on track for first
gas by the end of 2020 and underpins the Group's medium-term
production profile. As a conventional platform serving four wells
tied back to an established onshore terminal, Tolmount requires
modest capital expenditure and will have low production costs,
ensuring the project's robust economics. Premier has also partnered
with infrastructure group, Kellas Midstream, who will partially
fund and own the infrastructure element of the development.
The Group's positive view of the upside within the Greater
Tolmount Area was confirmed with the successful Tolmount East
appraisal well in October which, as well as extending plateau
production from the Tolmount Area, unlocks the potential
development of the Mongour discovery to the north. Further
potential exists at the nearby prospect, Tolmount Far East and to
the south and west of the Tolmount field.
Premier has continued to optimise its level of participation in
its future development projects. In the Falkland Islands, Premier
has signed a Heads of Terms with Navitas Petroleum to farm in for a
30 per cent interest in the Group's fully appraised 250 mmbbls
(gross) Sea Lion project. This marks a significant step forward for
the Sea Lion development with Navitas Petroleum sharing the
pre-first oil funding and bringing additional sources of senior
debt financing to the project. In Indonesia, Premier has signed a
Heads of Terms with Zarubezhneft to farm in for a 50 per cent
interest in its operated Tuna PSC. The new investor will carry
Premier for its share of a two-well appraisal campaign targeted to
commence in 2020.
Exploration within a disciplined capital framework remains a key
part of Premier's business model and 2019 saw the Group continue to
capture highly-prospective international acreage in proven basins.
Premier deepened its position in the emerging Andaman Sea gas play,
an area which has significant long-term potential, and also entered
the Alaska North Slope. Premier's first well in Alaska, which
spudded post period-end, is targeting an accumulation of over 1
billion barrels of oil-in-place (gross).
Free cash flow through the cycle remains a pre-requisite for the
Group and Premier will remain disciplined and selective in the
projects it progresses, realising value from part or full disposal
of development assets where appropriate. In August, Premier
initiated a sales process for its stake in the Zama field offshore
Mexico, following the successful appraisal of the field earlier in
the year. Premier expects those discussions to reach conclusion
later in 2020 once the unitisation process with the neighbouring
block is further advanced.
Reserves and resources
As at 31 December 2019, the Group's proven and probable (2P)
reserves, on a working interest basis, were 175 mmboe (2018: 194
mmboe) and total 2P and 2C resources were 847 mmboe (2018: 867
mmboe).
2P reserves (mmboe) 2P reserves and 2C
resources (mmboe)
1 January 2019 194 867
-------------------- -------------------
Production (28) (28)
-------------------- -------------------
Net additions, revisions,
discoveries 15 16
-------------------- -------------------
Disposals, relinquishments (5) (8)
-------------------- -------------------
31 December 2019 175(1) 847
-------------------- -------------------
(1) Due to rounding, total 2P reserves does not correspond to
the sum of the individual line items
The reduction in 2P reserves is driven by the impact of 2019
production and the sale of the Pakistan business, partially offset
by a 15 mmboe upward revision in the Group's 2P reserves,
principally related to the Catcher Area and Natuna Sea Block A.
Premier now anticipates a higher overall recovery from the Catcher
Area, following excellent reservoir performance and maturation of
production infill well targets. In Indonesia, strong performance
from the Gajah Baru Upper Arang reservoir and maturation of
incremental projects in the Anoa field resulted in increased Natuna
Sea Block A's 2P reserves. The Group's 2C resources were broadly
flat year-on-year.
Premier also seeks to increase its reserve and resource base
through acquisitions. Post period-end, the Group announced the
proposed acquisitions of the Andrew Area and Shearwater assets from
BP and an additional 25 per cent interest in its operated Tolmount
Area from Dana Petroleum. These acquisitions, once completed, will
materially increase the Group's UK reserves and resources. They are
materially value accretive and in line with the Group's stated
strategy of acquiring cash-generative assets in the UK North Sea,
where Premier has strong operating capability and considerable tax
assets. It is expected that the final consideration will be fully
funded from the proceeds of the new equity issuance.
Finance
During 2019, the Group generated US$327.4 million of positive
free cash flow which was directed towards debt reduction and
further strengthening the balance sheet. At year-end 2019, net debt
was US$1.99 billion bringing total debt reduction since October
2017 to over US$900 million, significantly ahead of the Group's
forecasts. This is primarily due to operational outperformance,
supplemented by non-core asset disposals.
The Group has also announced the proposed extension of the
maturities of its credit facilities to 2023. By the end of 2021,
the Group will have benefitted from more than 12 months of
production from Tolmount and the acquired UK assets will have been
fully integrated into the business. Premier believes that this,
together with its balance sheet benefitting from two further years
of debt reduction, will put the Company in a strong position to
refinance the business with a more conventional, and lower cost,
debt structure.
The Court Schemes of Arrangement (the Schemes) required to
implement the announced acquisitions, related funding arrangements
and extension of the Group's credit facilities commenced post
year-end. The requisite majority of Premier's creditors approved
the Schemes in February and the court sanction hearing is scheduled
to commence on 17 March 2020.
Environmental, Social and Governance (ESG)
A Company's success is not only measured in terms of financial
performance, but also in terms of environment and social
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 safety of its workforce and to minimise the potential
risk to the environment. In 2019, Premier recorded no serious
injuries, no spills and reduced its carbon footprint, achieving a
historic low Greenhouse Gas intensity at its operated assets.
Premier recognises the urgent need to respond to Climate Change
and the key role the energy industry needs to play in addressing
the environmental challenges faced by society today. As such,
Premier has committed to ensuring that all of its operated projects
will be developed on a carbon neutral basis in respect of Scope 1
and Scope 2 emissions. We can therefore commit, based on expected
future profiles, that Premier will be more than 65 per cent carbon
neutral by 2025 and 100 per cent by 2030.
Outlook
In the first quarter of 2020, oil prices have fallen
significantly due to fears over the spread of COVID-19 and the
impact this may have on global demand for oil. The current volatile
macro environment serves to highlight the importance of the
business being sustainably free cash flow positive and ensuring
that future growth can be funded through the commodity price cycle
without compromising the balance sheet. The Group's immediate
priority remains to reduce its debt levels and covenant leverage
ratio towards 1x, a process which will be accelerated by the
acquisition of the UK assets announced post period-end. At the same
time, Premier will continue to maintain its capital discipline
investing selectively in new international projects and exploration
to create material value for all of its stakeholders over the
longer term.
Board changes
As announced separately, Premier is pleased to announce that
Elisabeth Proust will join the Company's Board as an independent
Non-executive Director and member of the Health, Safety,
Environment and Security Committee and Nomination Committee with
effect from 1 April 2020.
Elisabeth has a strong technical and operational background and
joins the Board after a distinguished career within Total's
upstream business.
Robin Allan, Director, North Sea and Exploration, will be
leaving the Board at the close of the Group's Annual General
Meeting in May. Robin will continue to work for Premier on a
part-time consultancy basis, with a particular focus on ESG matters
and Premier's response to the Climate Change agenda.
BUSINESS UNIT REVIEW
UK
Premier achieved record production from its UK assets of 54.2
kboepd in 2019. This 16 per cent increase on the prior year was
driven by a full-year contribution from the Catcher Area at
increased rates. First gas from Premier's operated Tolmount
project, which is scheduled to come on-stream by year end 2020,
will help sustain the Group's UK production at over 50 kboepd,
before any contribution from the proposed UK acquisitions.
Catcher Area
Production from the Catcher Area exceeded expectations during
2019 averaging 33.6 kboepd (net, Premier 50 per cent operated
interest), underpinned by exceptionally high operating efficiency
and reservoir outperformance.
The Catcher Area FPSO continues to produce beyond sanctioned
plateau rates supported by excess well deliverability. This
resulted in the Group again increasing its Catcher Area recoverable
reserves. Premier is also working with the FPSO provider and its
joint venture partners to increase oil rates on a short term trial
basis. The Catcher Area achieved a low GHG intensity during 2019,
benefitting from the high plant uptime and the new build FPSO with
modern gas recovery and treatment systems.
Premier received formal approval of the development of the
Catcher North and Laverda fields in August. The requisite contracts
have been placed and fabrication of the flexibles and umbilicals is
underway. Catcher North and Laverda, together with the Varadero
infill well, which will also be drilled during 2020, will help
offset natural decline as the existing Catcher Area production
wells come off plateau. Development drilling is scheduled to start
in May 2020 with first oil scheduled for the first quarter of
2021.
The Group continues to work up additional well targets within
and around the Catcher Area to maximise economic recovery. Two
Burgman infill production wells are under evaluation for 2021 with
long lead items ordered and the rig contracting process underway.
The 4D seismic to be acquired during 2020 will further calibrate
Premier's existing reservoir models, help high grade future
opportunities and provide better imaging of the potential
oil-bearing reservoirs beyond the existing discoveries to evaluate
near-field tie-back opportunities.
Other UK producing assets
2019 production from the Elgin-Franklin Area, which is the UK's
largest producing field, averaged 6.0 kboepd (net, Premier 5.2 per
cent interest), ahead of expectations. Production was supported by
well intervention campaigns and infill drilling, including the F12
well, which was placed on-stream in December. Further infill
drilling is planned for 2020, including the F5 well, which is
expected to be drilled in the second quarter and tied into
production before year-end. In addition, post period-end the joint
venture partners approved a four-well stimulation campaign to take
place in 2020 to help improve production performance from the
existing wells.
Production from Premier's operated Solan field averaged 3.5
kboepd (Premier 100 per cent interest), slightly ahead of forecast
and driven by excellent plant operating efficiency. Preparations
continued throughout 2019 for the drilling of a new Solan
production well (P3) which will boost production from the central
part of the reservoir and extend field life. The well is expected
to spud in March 2020 with first oil anticipated in the third
quarter of 2020. Premier has reached agreement with Baker Hughes to
align payment with milestone dates, reducing Premier's cash outlay
prior to the completion of the well. On the successful completion
of the P3 well, excess gas will be used to replace diesel as a fuel
for power generation on the facility.
Active well management at the Premier-operated Huntington field
underpinned high uptime from the facility with production averaging
5.8 kboepd (Premier 100 per cent interest). Post period-end, water
cut in the highest producing well increased. This prompted Premier
to submit a draft decommissioning programme for the removal of the
leased Huntington FPSO from the field to the Secretary of State for
Business, Energy and Industrial Strategy in February 2020. Premier
expects that the last Huntington cargo will be lifted from the
field in April 2020. Since 2016, when Premier became operator, the
field has outperformed expectations, with proactive reservoir
management resulting in the deferral of cessation of production and
reserve upgrades over the last few years.
During 2019, Premier installed the Ocean Power Technologies
(OPT) PowerBuoy(R) (PB3) for trial on the Huntington field. The PB3
has demonstrated its ability to harness wave energy to power
site-monitoring systems designed for the protection of subsea
infrastructure following FPSO sailaway. Premier intends to work
with the Oil and Gas Technology Centre and OPT to further develop
the system for future use during the decommissioning phases of the
Group's assets.
Premier's operated Balmoral Area delivered 1.3 kboepd (net,
Premier 79.2 per cent interest) during the period. Production was
impacted by the failure of the Brenda multi-phase-pump, partially
offset by the restart of the B29 well in April.
In 2019, production from Ravenspurn North averaged 1.2 kboepd
(net, Premier 28.7 per cent interest). Uptime from the field
improved significantly following the summer shut down, averaging in
excess of 95 per cent. The Borr Prospector-5 jack up rig has been
contracted to drill two horizontal wells on Ravenspurn North,
commencing in March 2020. The wells will access gas in undrained
areas of the field with the aim of extending field life and
derisking further infill opportunities.
Production from the Kyle field, which is exported via the
Petrojarl Banff FPSO, averaged 1.4 kboepd (net, Premier 40 per cent
interest). The Kyle joint venture partners are working closely with
the Banff owners towards the safe and cost efficient
decommissioning of the Kyle facilities, with sailaway of the
Petrojarl Banff FPSO anticipated in the summer of 2020.
UK unit field operating costs were stable at US$13/boe (2018:
US$13/boe) while lease costs reduced to US$8/boe (2018: US$10/boe).
This reflects a full year of production at increased rates from the
Catcher FPSO offsetting natural decline on more mature, fixed cost
assets such as Huntington and Kyle.
The Greater Tolmount Area
The Premier-operated Tolmount development is on schedule for
first gas before year-end 2020 and is tracking below budget.
Construction and fit-out of the platform in Rosetti's yard
continued during 2019. Jacket roll up was achieved in December and
final welding and riser installation is nearing completion. The fit
out of all major topsides equipment packages has been substantially
completed and final piping, electrical installation and
pre-commissioning continues ahead of platform sailaway, which is
scheduled for late-April 2020.
Saipem continue to progress the offshore pipeline work scope on
behalf of the joint venture partners. The offshore pre-anchor route
survey was concluded in November and coating of the linepipe was
completed post period-end. Onshore, the shaft from cliff top to
beach level has been constructed and preparations are underway for
the beach crossing. Laying of the 20 inch gas export pipeline is
planned for the summer of 2020. The Easington terminal works are
also progressing and the installation of the pre-assembled units
commenced post period-end.
Preparations for the 2020 development drilling campaign are well
underway. All long lead items have been ordered and contracts
placed. The first of the four development wells is expected to spud
in the second quarter of 2020 after the jacket is installed. There
is also a plan to drill a fifth well at the end of the programme to
improve overall recovery from the field. Premier continues to
expect first gas before year-end, with Tolmount adding 20-25 kboepd
(net, Premier 50 per cent interest) to Group production once on
plateau.
In October 2019, Premier announced the success of the Tolmount
East well in an undrilled area four kilometres east of the Tolmount
gas field. Premier is undertaking FEED studies for both platform
and subsea concepts to develop the Tolmount East gas field via the
Tolmount infrastructure. Premier plans to select the optimal field
development concept during the second quarter of 2020. Final
product from the 3D seismic acquired across the Greater Tolmount
Area in 2019 is expected in April 2020 and will further-inform the
concept select decision. Project sanction of Tolmount East is
targeted for the second half of the year and will be brought
on-stream to ensure Tolmount infrastructure is kept at full
utilisation.
The success at Tolmount East unlocks the potential development
of the Mongour discovery to the north which is expected to be
developed with Tolmount East. Total resource at Tolmount East,
including Mongour, is 160-300 BCF (P50 to P10). These estimates
will be further refined as FEED progresses and the processing of
the 3D seismic data is completed and integrated into the
evaluation.
There is considerable upside within the Greater Tolmount Area.
The success at Tolmount East with the new 3D seismic survey reduces
the uncertainty of the Tolmount Far East prospect which Premier is
currently maturing ahead of drilling in 2022. Further potential
also exists to the south and west of the Tolmount field.
Proposed UK acquisitions
Post period-end, Premier announced the proposed acquisitions of
the Andrew Area and Shearwater assets from BP and an additional 25
per cent interest in its operated Tolmount Area from Dana
Petroleum.
The acquisitions provide Premier with material operated
interests in the Andrew Area and a non-operated interest in
Shearwater, a significant production and infrastructure hub in the
Central North Sea. Both the Andrew Area and the Shearwater field
add mid-life production with material upside potential through
production optimisation, incremental developments and field life
extension projects. The Tolmount acquisition enables Premier to
deepen its position in one of its core UK development assets which
has significant upside and, as outlined above, is on track for
first gas by the end of 2020.
Combined with existing assets, the proposed acquisitions add
cash-generative, rising production out to 2024 with pro forma 2019
UK production in excess of 75 kboepd and no decommissioning
security burden. All of the proposed acquisitions are expected to
have completed by the end of the third quarter of 2020.
INDONESIA
Premier's Indonesian Business Unit generated material positive
net cash flows, after ongoing capital expenditures on the BIG-P
development. Safe delivery of BIG-P first gas on schedule and below
budget is testament to the team's strong project execution skills
and supports the Company's long-term gas sales contracts into
Singapore.
Production and development
Production from the Premier-operated Natuna Sea Block A averaged
11.5 kboepd (net, Premier 28.7 per cent interest) (2018: 12.9
kboepd). The slight reduction on 2018 reflects weaker Singapore
demand during the second and third quarters of 2019 with Singapore
customers substituting cheaper spot LNG for Natuna Sea pipeline
gas.
Singapore demand for Premier's Indonesian gas strengthened into
year-end with production from Natuna Sea Block A averaging 16.1
kboepd (net to Premier) in December, as the price of Natuna Sea
Block A pipeline gas and spot LNG converged. This strong production
has continued into 2020 with Natuna Sea Block A production
averaging 15.6 kboepd (net to Premier) to the end of February with
Singapore demand significantly above take or pay levels.
Premier's Indonesian gas pricing is driven by HSFO prices. In
light of the impending implementation of IMO2020 legislation,
Premier hedged a significant proportion of its 2020 Indonesian gas
entitlement production at c.US$9/mmscf, significantly above current
spot prices.
Gross gas deliveries under GSA1 GSA2
GSA1 and GSA2 (BBtud)
2019 2018 2019 2018
----- ----- ----- -----
Anoa, Pelikan, Bison, Gajah
Puteri 147 153 - -
----- ----- ----- -----
Gajah Baru, Naga, Iguana - - 55 80
----- ----- ----- -----
Kakap - 4 - -
----- ----- ----- -----
Total 147 157 55 80
----- ----- ----- -----
Premier sold an average of 202 BBtud (gross) (2018: 233 BBtud)
from its Natuna Sea Block A fields to Singapore under its two Gas
Sales Agreements (GSA1 and GSA2) during 2019. Gross liquids
production from the Natuna Sea Block A averaged 1.4 kbopd in
2019.
Singapore demand for Indonesian gas under GSA1 averaged 285
BBtud (2018: 292 BBtud), slightly ahead of take or pay levels.
Premier's Natuna Sea Block A fields dedicated to GSA 1 - Anoa,
Pelikan, Bison and Gajah Puteri - delivered 147 BBtud (gross)
(2018: 153 BBtud), capturing 52 per cent (2018: 52 per cent) of
GSA1 deliveries, above Natuna Sea Block A's contractual share of 51
per cent.
Premier's Natuna Sea Block A fields dedicated to GSA2 - Gajah
Baru, Naga and Iguana - delivered 55 BBtud (2018: 80 BBtud), in
line with take or pay levels.
During 2019, Premier successfully executed a series of high
value investments aimed at boosting deliverability from Natuna Sea
Block A. Premier achieved first gas from its operated BIG-P project
in December, on schedule and significantly below budget. With
further production history, Premier expects BIG-P recoverable
reserves to increase to in excess of the 93 BCF (gross) estimated
at sanction. This is as a result of the successful three-well
drilling campaign in 2019 which encountered additional productive
sands. Natuna Sea Block A deliverability was also boosted by a
successful perforation of an Anoa West Lobe well in May and the
tie-in of a Gajah Baru infill well in December.
Further intervention activities are planned for 2020 to maximise
gas delivery from the Natuna Sea Block A fields and preparations
are underway for a 2021 rig campaign which will include Anoa well
workovers and side-tracks, infill drilling on the Pelikan field and
an appraisal well to test the northern flank of the producing Anoa
field.
Exploration and appraisal
During 2019, Premier continued to progress its operated Tuna
discoveries, which are estimated to contain 100 mmboe (gross) and
are located in the Natuna Sea close to the Indonesian and
Vietnamese maritime boundary.
In December, Premier signed a Heads of Terms with Zarubezhneft,
a Russian company with upstream interests primarily in Vietnam, to
farm in for a 50 per cent non-operated interest in the Tuna PSC. A
farm down agreement is expected to be signed by the end of the
first quarter of 2020. Under the farm down agreement, Zarubezhneft
will carry Premier for its share of a two-well appraisal campaign
which is planned for 2020. It is anticipated that, post completion
and receipt of government approval, Premier will retain
operatorship and a 50 per cent interest in the Tuna PSC.
In January 2020, Premier was awarded 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 2021.
Elsewhere in Indonesia, Premier expanded its acreage position in
the South Andaman Sea during 2019, farming in for a 20 per cent
interest in South Andaman and Andaman I PSCs. A 3D seismic
acquisition programme across parts of the Andaman Sea blocks was
completed during the first half of 2019. The fast track data was
received in September and confirmed the prospective nature of the
acreage with the fully-processed seismic data across all three
blocks to be delivered in the first quarter of 2020. Premier plans
to drill its first well in the Andaman Sea on its operated Andaman
II licence in the first half of 2021. 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 Indonesia
portfolio.
VIETNAM
Premier's operated Chim Sáo field delivered a robust production
performance in 2019. Together with continued low operating costs,
this resulted in the asset generating over US$80 million of free
cash flow. A two-well infill programme is being planned for 2021 to
help offset natural decline from the existing production wells with
regulatory approvals in progress.
Production from the Premier-operated Block 12W, which contains
the Chim Sáo and Dua fields, averaged 11.4 kboepd (net,
Premier-operated 53.1 per cent interest) (2018: 15.2 kboepd) and
was ahead of 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.
2019 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 2020 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 2021.
Premier is currently seeking regulatory approvals for the programme
ahead of going out for tender for a rig.
Chim Sáo cargoes were well bid, especially in the second half of
the year, with an average premium to Brent of more than US$4.70/bbl
realised for cargoes lifted during 2019. Demand for Chim Sáo crude
continued to strengthen post period-end with January to April 2020
loading cargoes sold at an average premium to Brent of
US$7.20/bbl.
Field operating costs were US$9/boe (2018: US$5/boe),
significantly below budget driven by production outperformance.
FALKLAND ISLANDS
The Premier-operated Sea Lion Phase 1 project has been
substantially derisked from a technical and cost perspective and,
post period-end, Navitas Petroleum agreed to farm in for a 30 per
cent interest in the project. The Group's focus is now on securing
senior debt support for the project.
The 530 mmbbls (gross) Sea Lion project, which will be developed
over two phases, represents a material opportunity for the
Group.
Sea Lion Phase 1 will develop 250 mmbbls (gross) using a
conventional FPSO and subsea well development scheme, similar to
Premier's operated Catcher development. FEED has been completed and
the development concept further optimised with the addition of a
drill centre to the south and the well count increased to 29 wells
(20 producers, eight water injectors and one gas injector). 12
wells will be drilled pre-first oil supporting ramp up to plateau
production rates of 85 kboepd (gross).
Premier continues to benefit from a collaborative relationship
with its Tier 1 supply chain companies. All of the key service and
supply contracts, including for the provision of the FPSO, drilling
rig, well services, flexible flowlines and risers, subsea
production systems and SURF installation, are being finalised in
preparation for their execution as the project approaches sanction
decision.
The Environmental Impact Statement was updated in 2019 to
reflect further project optimisation and was issued for public
consultation in the Falkland Islands, which concluded post
period-end. The Environmental Impact Statement will be submitted
along with the Field Development Plan (FDP) for government approval
as part of the project sanction process.
Premier has made a public commitment that all operated projects
will be developed on the basis that they will be net zero in
respect of Scope 1 and Scope 2 emissions. A number of engineering
features have been designed into the Sea Lion project using
best-available technology to minimise emissions at source. It is
anticipated that these will be supplemented by carbon offsets to
ensure net zero emissions from Sea Lion is achieved.
During 2019, Premier launched a farm down process to bring in an
additional equity partner into the Sea Lion project to optimise the
Group's level of participation in the development. In January 2020,
Premier and Rockhopper agreed a detailed Heads of Terms with
Navitas Petroleum to farm in for a 30 per cent interest in Sea
Lion. Finalisation of a farm out agreement is expected during the
first half of 2020 with completion subject to regulatory and lender
approval. Together with the vendor funding for the project by the
contractors and the senior debt financing component, this reduces
Premier's share of pre-first oil capex from c.US$500 million to
below US$300 million spread over the project investment period.
The critical path item to sanction remains securing senior debt
support for the project. In 2019, Premier completed a Preliminary
Information Memorandum supported by a comprehensive set of
independent expert reports on the project. These formed the basis
for the financing guarantee application process for the senior debt
component of the project financing. While engagement with senior
debt providers is constructive, feedback received highlights the
need for Premier to complete its announced corporate actions and
extension of its credit facilities to provide certainty over its
medium- to long-term funding position before financial guarantees
for the project can be provided.
EXPLORATION ACTIVITIES
During 2019, Premier's exploration teams continued to invest
selectively in its international exploration portfolio within
strict budgetary constraints. The Group's focus remains on
underexplored but proven provinces which have the potential to
develop into new business units over the medium term.
Alaska
2019 saw a new country entry for Premier, with the Group farming
in for a 60 per cent interest in the conventional Area A Icewine
project in the Alaska North Slope. Area A contains the Malguk-1
discovery drilled by BP in 1991. This well discovered but never
tested 251 feet of light oil pay in turbidite sands in the Torok
formation, within the emerging Brookian play where a number of
developments are currently underway. Premier estimates an
accumulation of more than 1 billion barrels (gross) of
oil-in-place. The Charlie-1 (Malguk-1 appraisal) well spudded post
period-end on 2 March and is currently drilling ahead. Premier
plans to flow test the well with the results expected in April. On
successful completion of the work programme, Premier will have the
option to assume operatorship and to opt-in to Icewine Area B or
C.
Brazil
In Brazil, much of 2019 was spent preparing for Premier's first
in-country exploration well on its operated Block 717 (Premier 50
per cent interest) in the offshore Ceará basin. Premier has
contracted the Valaris DS-9 drillship to drill a well targeting the
stacked Berimbau/Maraca prospect. Berimbau is the 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.
The well is expected to spud in the third quarter of 2020.
Elsewhere in the Ceará basin, on Block 661 (Premier 30 per cent
non-operated interest), the joint venture successfully obtained an
initial term licence extension through to November 2021.
Having fully evaluated the prospectivity on Block 665 (Premier
50 per cent operated interest), Premier and its joint venture
partner unanimously decided to relinquish the licence in April
2019.
Mexico
The Talos-operated Block 7 Zama appraisal campaign successfully
completed in July, on schedule and below budget, and comprised two
appraisal wells and a vertical side-track, which was flow tested. A
comprehensive set of data was acquired and demonstrated reservoir
properties at the upper end of expectation. This resulted in
Premier increasing its gross resource estimate of the Zama
structure to 670-810-970 mmboe (P90-P50-P10).
In June, the Block 7 joint venture partnership agreed the main
elements of a full field development plan to maximise overall
recovery from the Zama field. The Zama field will be developed
using two offshore processing, drilling and accommodation
platforms, together with a floating, storage and offloading vessel
and oil export by tankers. FEED is now underway with submission of
the FDP for government approval expected in the third quarter of
2020. FDP approval is subject to conclusion of the unitisation of
the field between Block 7 and the neighbouring block (Pemex 100 per
cent interest).
Unitisation discussions are progressing as per the Mexican
regulatory process, which is in line with international best
practice. If the Block 7 partners and Pemex cannot reach agreement,
then an independent expert will be appointed in the second quarter
of 2020 to determine the initial tract participation of the Zama
field as per the process detailed in the Government-approved
Pre-unitisation Agreement.
Following the successful appraisal of the Zama field, Premier
initiated a sales process for its interest in Block 7. Discussions
with interested parties are ongoing and are expected to conclude
once the unitisation process is further advanced.
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 acquisition across Block 30 (Premier 30 per cent
interest) was completed in July. The data is now being processed to
delineate the full extent of the Wahoo and Cabrilla prospects, as
well as to mature other prospectivity on the Block. Drilling is
targeted for 2021.
Premier's exploration plan for its 100 per cent operated Burgos
Blocks 11 and 13 were approved by CNH in July, triggering the start
of the four-year initial term for these licences. Reprocessing of
the existing 3D seismic across Premier's Burgos blocks is ongoing
and regional play fairway analysis has identified a deeper play in
the Cretaceous and Jurassic carbonates that provides additional
upside to that previously identified in the Oligocene-Miocene
clastic play.
FINANCIAL REVIEW
Business performance
Production averaged 78.4 kboepd in 2019 (2018: 80.5 kboepd),
which, coupled with improved crude differentials, higher post
hedged realisations and a higher oil vs gas mix, resulted in total
revenue from all operations of US$1,597 million compared with
US$1,438 million in 2018.
EBITDAX for the period from continuing operations was US$1,230
million, an increase of US$139 million compared to the prior period
EBITDAX of US$1,091 million, once lease expenses have been added
back following the implementation of IFRS 16. The increased
EBITDAX, on a like-for-like basis, is due primarily to improved
realised oil prices post hedging and a higher oil vs gas production
mix with underlying operating costs remaining broadly stable due to
tight cost control.
Business performance (continuing operations) 2019 2018
$ million $ million
Operating profit 455.0 531.0
Add: DD&A 757.9 358.4
Add: Exploration and new venture costs 21.3 35.2
(Less): (Profit) on disposal of assets (4.2) (42.3)
EBITDAX as reported 1,230.0 882.3
Add: lease expenses - 208.7
=========== ===========
EBITDAX adjusted for lease expenses 1,230.0 1,091.0
=========== ===========
In addition, we have reduced Net Debt to US$1,989.8 million,
following strong cash flow generation in the year.
Income statement
Production and commodity prices
Group production on a working interest basis averaged 78.4
kboepd compared to 80.5 kboepd in 2018. Production is at the upper
end of guidance previously given but is slightly lower than prior
year due to the disposal of the Pakistan business unit, which
completed in March 2019, and natural decline in other fields. This
was partially offset by high operational efficiency across the
asset portfolio and the increased contribution from Catcher.
Average entitlement production for the period was 73.9 kboepd
(2018: 73.8 kboepd).
Premier realised an average oil price for the year of
US$66.3/bbl (2018: US$67.9/bbl). Including the effect of oil swaps
which settled during 2019, the realised oil price was US$68.1/bbl
(2018: US$63.5/bbl). Premier benefitted from improving
differentials for its crude oil sales relative to the underlying
Brent oil price.
In the UK, average natural gas prices achieved were 42
pence/therm (2018: 57 pence/therm), which included 24.5 million
therms which were sold under fixed price master sales agreements.
Gas prices in Singapore, linked to high sulphur fuel oil ('HSFO')
pricing and in turn, therefore, linked to crude oil pricing,
averaged US$10.2/mscf (2018: US$11.2/mscf).
Realised prices 2019 2018
Oil price (US$/bbl) post hedging 68.1 63.5
---- ----
UK natural gas (pence/therm) 42 57
---- ----
Singapore HSFO (US$/mscf) 10.2 11.2
---- ----
Total revenue from all operations (including Pakistan) increased
to US$1,596.5 million (2018: US$1,438.3 million). From continuing
operations (excluding Pakistan), sales revenue increased to
US$1,584.7 million from US$1,397.5 million for the prior year.
Cost of operations
Cost of operations comprise operating costs, changes in lifting
positions, inventory movement and royalties. Cost of operations,
which now exclude lease expenses following the adoption of IFRS 16,
for the Group was US$342.8 million for 2019, compared to US$291.3
million for 2018, once lease costs of US$208.7 million are removed
from the prior period.
2019 2018
$ million $ million
Operating costs
=========== ===========
Continuing operations 322.6 487.5
Less: lease expenses - (208.7)
Discontinuing operations (Pakistan) 2.4 9.5
------------------------------------- ----------- -----------
Operating costs 325.0 288.3
=========== ===========
Operating cost per barrel (US$ per
barrel) 11.4 9.8
------------------------------------- ----------- -----------
Lease expenses in 2019 were US$196.4 million, giving a lease
cost per barrel of US$6.9, which is broadly consistent year on
year.
The increase in absolute operating costs reflects additional
payments made to reflect high uptime from the Catcher field.
Ongoing cost reduction initiatives, successful contract
renegotiations and strict management of discretionary spend
continue to deliver low and stable operating costs. Operating costs
per barrel, excluding lease costs, are expected to be c.$15/bbl in
2020 reflecting lower year on year production rather than any
increase in underlying operating costs.
2019 2018
$ million $ million
Amortisation and depreciation
---------------------------------- ----------- -----------
Total DD&A 742.9 386.5
---------------------------------- ----------- -----------
DD&A per barrel (US$ per barrel) 26.4 13.2
---------------------------------- ----------- -----------
Total depreciation has increased year-on-year due to DD&A
charges of US$223.0 million recognised on right-of-use-assets now
recorded on the balance sheet as property, plant and equipment
following the adoption of IFRS 16 on 1 January 2019. The DD&A
charge reflects the positive impact of the revised Catcher reserves
estimates. Included within the depreciation charge for the year are
charges of US$30.5 million related to an increase in the Group's UK
decommissioning provisions for assets which are carried at nil book
value. 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
2019 and not by any material change in the underlying
decommissioning cost estimates.
Exploration expenditure and new ventures
Exploration expense and new venture costs amounted to US$21.3
million (2018: US$35.2 million), primarily related to work
performed on potential new licences and acquisitions. After
recognition of these expenditures, the exploration and evaluation
assets remaining on the balance sheet at 31 December 2019 amount to
US$934.0 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 fell to US$9.0 million from US$14.0 million in
2018.
Finance gains and charges
Net finance gains and charges of US$352.5 million, have reduced
compared to the prior year (US$372.8 million). An increase in
finance costs due to lease liabilities recognised on adoption of
IFRS 16 has been broadly offset by a reduction in the unwinding of
the decommissioning provision due to the change in discount rate
and mark to market gains on open hedging instruments. Cash interest
expense in the period was US$251.9 million (2018: US$228.7
million), reflecting the timing of Revolving Credit Facility
("RCF") rollovers. Cash interest expense is expected to fall in
2020 on an underlying basis reflecting reduced net debt, excluding
the impact of any amendment fees relating to the proposed amendment
and extension of our existing facilities.
Taxation
The Group's total tax credit for 2019 from continuing operations
is US$52.5 million (2018: charge of US$53.1 million) which
comprises a current tax charge for the period of US$51.1 million
and a non-cash deferred tax credit for the period of US$103.6
million.
The total tax credit represents an effective tax rate credit of
51.2 per cent (2018: charge of 33.5 per cent). The effective tax
rate for the year is primarily impacted by ring fence expenditure
supplement claims in the UK during the year (US$88.1 million
credit). For the Group's principal UK North Sea operating
subsidiary, 2019 represented the final ring fence expenditure
supplement claim. After adjusting for this, the underlying Group
tax charge for the period is US$35.6 million and an effective tax
rate of 34.7 per cent. The Group has a net deferred tax asset of
US$1,426.2 million at 31 December 2019 (2018: US$1,294.6
million).
Profit after tax
Profit after tax is US$164.3 million (2018: US$133.4 million)
resulting in a basic earnings per share of 19.9 cents from
continuing and discontinued operations (2018: 17.3 cents). The
profit after tax in the year is driven principally by the increased
sales revenue and the Group's tax loss position in the UK,
partially offset by the increase in lease related costs in the
income statement following implementation of IFRS 16 on 1 January
2019.
Cash flows
Cash flow from operating activities was US$1,080.0 million
(2018: US$777.2 million) after accounting for tax payments of
US$61.2 million (2018: US$128.8 million) and before the movement in
joint venture cash balances in the period of US$28.7 million . The
increase is driven by increased production and revenue in the
period and due to US$204.5 million of lease cash costs (net) in
2019 recorded as financing and not operating cash flows.
Capital expenditure in 2019 totalled US$241.4 million (2018:
US$279.8 million).
Capital expenditure 2019 2018
$ million $ million
Fields/development projects 101.7 234.3
----------- -----------
Exploration and evaluation 136.9 43.6
----------- -----------
Other 2.8 1.9
----------- -----------
Total 241.4 279.8
----------- -----------
The development expenditure mainly relates to the BIG-P
development in Indonesia and the Tolmount project in the UK. The
largest part of the E&E capital expenditure in the period was
the appraisal drilling for the Zama project in Mexico. In addition,
cash expenditure for decommissioning activity in the period was
US$35.3 million (2018: US$72.7 million). Further to this, US$9.9
million of cash was funded into long-term abandonment accounts for
future decommissioning activities (2018: US$17.8 million).
Total development and E&E expenditure in 2020 is estimated
at US$410 million principally related to development drilling on
Tolmount, Catcher and Solan and exploration and appraisal
activities in Alaska, Brazil, Mexico and Indonesia. Decommissioning
spend is estimated at US$60 million reflecting the recent decision
to cease production at Huntington, although the impact on full year
cash flow generation is offset by the assumption that Huntington
would have generated negative operating cash flow in 2H 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. In total Premier received the full
consideration of US$65.6 million for the sale including deposits
and completion payments paid by the buyer and net cash flows
collected by Premier since the economic date of the transaction.
The Pakistan Business Unit results for the current and prior
periods are presented as a discontinued operation.
Balance sheet position
Net debt
Net debt at 31 December 2019 amounted to US$1,989.8 million (31
December 2018: US$2,330.7 million), with cash resources of US$198.1
million (31 December 2018: US$244.6 million). The maturity of all
of Premier's facilities is May 2021. During the year, Premier made
debt repayments of US$399.7 million. Further, the Group cancelled
US$333.8 million of its RCF debt facility.
Premier retains significant cash at 31 December 2019 of US$151.0
million and undrawn facilities of US$398.2 million, giving
liquidity of US$549.2 million (31 December 2018: US$569.6 million)
when excluding cash of US$47.1 million held on behalf of joint
venture partners or as security for letters of credit.
Subsequent to the year-end, in January 2020, a further US$129.5
million of the Group's RCF debt facility was cancelled by Premier,
which will result in reduced commitment fee costs for the Group in
2020.
Provisions
The Group's decommissioning provision increased to US$1,303.4
million at 31 December 2019, up from US$1,214.5 million at the end
of 2018. 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
2019 and not by any material change in the underlying
decommissioning costs estimates.
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 used within this
Financial Review are EBITDAX, Cash Margin, Free Cash Flow,
Operating cost per barrel, DD&A per barrel, Net Debt and
Liquidity and are defined in the glossary.
Impact on key financial metrics on adoption of IFRS 16
Leases
A new IFRS standard on leases came into effect on 1 January
2019. The impact on key financial metrics for the period is shown
below.
$ million Impact of IFRS
16
Balance Sheet at 31 December 2019 (1)
Fixed assets 588.0
Net investment in sub-lease 75.7
Lease liabilities (732.5)
===============
Income Statement for 2019 (2)
Costs of Production 196.4 Decrease
DD&A 223.0 Increase
Net finance costs 44.7 Increase
Net impact on profit after tax 71.3 Decrease
===============
Cash flow for 2019 (3)
Operating cash flow 204.5 Increase
Net lease payments (within financing 204.5 Increase
and investing)
Free cash flow Nil
===============
1. Balance Sheet
Following the adoption of IFRS 16, US$588.0 million of
right-of-use assets, US$75.7 million of net investment in sublease
and US$732.5 million of lease liabilities have been included in the
Group balance sheet as at 31 December 2019. All of these were
previously classified as operating leases as the Group did not have
any finance leases under IAS 17. Lease liabilities are now
presented separately on the Group balance sheet as both current and
non-current liabilities, do not form part of finance debt and are
not included in net debt under the terms of the Group's financing
facilities.
2. Income Statement
Charges to the income statement due to the adoption of IFRS 16
have increased by US$71.3 million. This represents an increase in
depreciation and finance costs recognised on right-of-use assets
and lease liabilities, which are partially offset by the absence of
operating lease expenses within costs of production. EBITDAX, as
previously defined, has increased, due to the absence of operating
lease expenses within costs of production. For the purposes of
covenant calculations, lease expenses continue to be included
within costs of production.
3. Cash flow
In prior years, operating lease payments were presented as
operating cash flows. Lease payments are now classified as
financing cash flows which has caused operating cash flows to
increase. There were US$204.5 million of lease payments (net)
included within financing and investing cash flows for 2019, that
would previously have been reported within operating cash flows
before the adoption of IFRS 16.
Financial risk management
Commodity prices
Premier continued to take advantage of the improved oil price
environment observed at times in 2019 to increase its hedging
position to protect free cash flows and covenant compliance.
(1)
The Group's current hedge position is as follows:
Oil
Swaps / forwards 2020 1H 2020 2H
--------
Volume (mmbbls) 3.4 1.3
Average price (US$/bbl) 64 63
------------------------- -------- --------
UK gas
Swaps / forwards / options 2020 1H 2020 2H 2021 2022
--------
Volume (million therms) 35 28 89 64
Average price (p/therm) 55 52 42 (1) 42 (1)
---------------------------- -------- -------- ------- -------
(1) 2021 average price is a mixture of swap and option floor
pricing whilst 2022 is average option floor pricing only. Excludes
impact of deferred option premiums
Indonesia gas
Swaps / forwards 2020 1H 2020 2H
--------
Volume (HSFO k te) 126 126
Average price (US$/te) 382 340
------------------------ -------- --------
At 31 December 2019, the fair value of the open oil and gas
instruments above was an asset of US$29.2 million (31 December
2018: asset of US$119.3 million), which is expected to be released
to the income statement during 2020 and 2021 as the related barrels
are lifted or therms delivered.
During 2019, expiration of forward oil swaps resulted in a net
credit of US$35.9 million (2018: charge of US$71.2 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 gain of US$6.2 million on its outstanding
foreign exchange contracts (2018: loss of US$17.2 million). The
Group currently has GBP150.0 million 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 2019
is US$123.6 million, which is split between current and long term
liabilities (2018: liability of US$125.6 million).
Interest rates
The Group has various financing instruments including senior
loan notes, UK retail bonds, term loans and revolving credit
facilities. Currently, approximately 73 per cent of total
borrowings is fixed or capped using interest rate options. On
average, the effective interest on drawn funds for the period,
recognised in the income statement, was 8.2 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
2019, US$2.3 million of cash proceeds were received (net to
Premier) in relation to settled insurance claims (2018: US$1.4
million).
Going concern
The Group monitors its funding position and its liquidity risk
throughout the year to ensure 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.
Management's base case forecast assumed an oil price of
US$65/bbl in 2020 and 2021, respectively and production in line
with prevailing rates. In January 2020, the Group publicly
announced the agreement it had reached to undertake the following
corporate actions (together the "Corporate Actions"):
-- an amend and extend ("A&E") of all of the Group's
financing facilities, including extension of maturity from May 2021
to November 2023;
-- the proposed acquisition of a 25 per cent working interest in
Tolmount from Dana and interests in Andrew and Shearwater from BP
(together the "Acquisitions" or the "Acquired Assets");
-- entering into of a US$300 million bridge facility to partly
finance the Acquisitions (the "Bridge Facility"). Based on current
forecasts we do not expect to utilise the Bridge Facility; and,
-- raising equity from shareholders via a combination of a
placing and a rights issue (the "Equity Raise"), which is fully
underwritten.
The above actions are expected to be approved via a court scheme
of arrangement in March 2020. Assuming approval is obtained, the
Group will request that shareholders approve the Equity Raise and
Acquisitions in Q2 2020. In February 2020, more than 75 per cent of
the Group's creditors voted to support the Group's scheme of
arrangement. Accordingly, management expect the above Corporate
Actions to be approved and completed in Q3 2020. The expected
completion of Corporate Actions is reflected in the base case
forecast. However, as sanction of the scheme of arrangement is
subject to court approval, and particularly given the scheme is
currently being opposed by one creditor, approval is not yet
certain.
At 31 December 2019, the Group continued to have significant
headroom on its financing facilities and cash on hand. The Group
has run downside scenarios, where oil and gas prices are reduced by
a flat US$10/bbl throughout the going concern period and where
total Group production is forecast to reduce by 10 per cent. In the
downside scenarios applied to the base case forecast, individually
and in combination, there would be no forecast covenant breach
during the 12 month going concern assessment period.
In addition, the Group has run downside scenarios where the
Corporate Actions do not complete either because of a rejection of
the Scheme by the court or due to rejection by shareholders. In the
event that the Corporate Actions do not complete, and applying the
base case assumptions to Premier's existing assets, the forecasts
show that the Group will have sufficient financial headroom for the
12 months from the date of approval of the 2019 Annual Report and
Accounts, even if the Corporate Actions do not complete. However,
if the Corporate Actions do not complete and downside price and or
production scenarios materialise, in the absence of any mitigating
actions, a breach of one or more of the financial covenants during
the 12 month going concern assessment period would arise and the
Group's financing facilities would be classified as current
liabilities in subsequent reporting periods. This potential breach
could be mitigated by asset disposals, such as the Group's interest
in the Zama prospect, as well as further hedging activity or
deferral of expenditure.
Currently, due to fears over the spread of COVID-19 and the
impact this may have on global demand for oil, oil prices have
fallen to levels not seen since early 2016 and below the sensitised
case above. If oil prices were to remain at these levels, and the
Corporate Actions described above did not complete, the Directors
believe that the mitigating actions identified above would prevent
a breach from occurring.
Based on management's expectation that the completion of the
Corporate Actions is probable, and considering the downside
scenarios run, including the Corporate Actions not completing, the
Directors have a reasonable expectation that the Company has
adequate resources to continue in operational existence for the
foreseeable future. Therefore, the Directors continue to adopt the
going concern basis of accounting in preparing these consolidated
financial statements.
In the remote scenario whereby the Corporate Actions do not
complete, there is a sustained fall in the oil price, and
management is unable to deliver any mitigating actions, in the
event of a forecast covenant breach, management has an expectation
that either a covenant waiver or forbearance from the required
number of lenders would be received, which would avoid an
acceleration of repayment of the Group's financing facilities
during the going concern period.
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
-- Financial discipline and governance
-- Production and development delivery and decommissioning execution
-- Joint venture partner alignment and supply chain delivery
-- Climate change
-- Organisational capability
-- Exploration success and reserves addition
-- Health, safety, environment and security
-- 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 2019
2019 2018
US$ million US$ million
------------------------------------------------
Continuing operations
Sales revenues 1,584.7 1,397.5
Other operating costs (2.9) (1.2)
Costs of operation (342.8) (500.0)
Depreciation, depletion, amortisation
and impairment (757.9) (358.4)
Exploration expenses and new ventures (21.3) (35.2)
Profit on disposal of non-current assets 4.2 42.3
General and administration costs (9.0) (14.0)
------------- -------------
Operating profit 455.0 531.0
Interest revenue, finance and other gains 31.4 27.8
Finance costs, other finance expenses
and losses (383.9) (400.6)
Profit before tax from continuing operations 102.5 158.2
Tax credit/(charge) 52.5 (53.1)
------------- -------------
Profit for the year from continuing operations 155.0 105.1
------------- -------------
Discontinued operations
Profit for the year from discontinued
operations 9.3 28.3
------------- -------------
Profit after tax 164.3 133.4
------------- -------------
Earnings per share (cents):
From continuing operations
Basic 18.8 13.6
Diluted 17.2 12.2
------------- -------------
From continuing and discontinued operations
Basic 19.9 17.3
Diluted 18.2 15.5
------------- -------------
Consolidated Statement of Comprehensive Income
For the year ended 31 December 2019
2019 2018
US$ million US$ million
--------------------------------------------------- ------------- -------------
Profit for the year 164.3 133.4
--------------------------------------------------- ------------- -------------
Cash flow hedges on commodity swaps:
(Losses)/gains arising during the year (50.8) 85.7
Add: reclassification adjustments for
(gains)/losses in the year (45.6) 71.2
------------- -------------
(96.4) 156.9
Cash flow hedges on interest rate and
foreign exchange swaps:
(Losses)/gains arising during the year (13.4) 21.5
Less: reclassification adjustments for
losses/(gains) in the
year 10.3 (11.4)
------------- -------------
(3.1) 10.1
Tax relating to components of other comprehensive
income 25.0 (33.8)
Exchange differences on translation of
foreign operations (3.8) 7.4
Gain on long-term employee benefit plans* 0.2 -
Other comprehensive (expenses)/income (78.1) 140.6
Total comprehensive income for the year 86.2 274.0
------------- -------------
* Not expected to be reclassified subsequently to income
statement.
All comprehensive income is attributable to the equity holders
of the parent.
Consolidated Balance Sheet
As at 31 December 2019
2019 2018
US$ million US$ million
---------------------------------------
Non-current assets:
Intangible exploration and evaluation
assets 934.0 812.6
Property, plant and equipment 2,481.8 2,245.6
Goodwill 240.8 240.8
Long-term receivables 231.1 159.8
Deferred tax assets 1,556.1 1,434.1
------------- -------------
5,443.8 4,892.9
------------- -------------
Current assets:
Inventories 16.3 12.5
Trade and other receivables 378.9 282.3
Derivative financial instruments 55.3 127.4
Cash and cash equivalents 198.1 244.6
Assets held for sale - 55.2
------------- -------------
648.6 722.0
------------- -------------
Total assets 6,092.4 5,614.9
------------- -------------
Current liabilities:
Trade and other payables (356.2) (375.6)
Lease liabilities (149.7) -
Short-term provisions (76.8) (46.0)
Derivative financial instruments (98.8) (41.4)
Deferred income (15.3) (11.0)
Liabilities directly associated with
assets held for sale - (21.9)
------------- -------------
(696.8) (495.9)
------------- -------------
Net current (liabilities)/assets (48.2) 226.1
------------- -------------
Non-current liabilities:
Long-term debt (2,169.8) (2,552.0)
Deferred tax liabilities (129.9) (139.5)
Lease liabilities (582.8) -
Deferred income (60.5) (76.0)
Derivative financial instruments (62.3) (129.4)
Long-term provisions (1,258.8) (1,196.1)
------------- -------------
(4,264.1) (4,093.0)
------------- -------------
Total liabilities (4,960.9) (4,588.9)
------------- -------------
Net assets 1,131.5 1,026.0
------------- -------------
Equity and reserves:
Share capital 156.5 154.2
Share premium account 499.4 491.7
Other reserves 475.6 380.1
------------- -------------
1,131.5 1,026.0
------------- -------------
Consolidated Statement of Changes in Equity
For the year ended 31 December 2019
Share premium
Share capital account Other reserves Total
US$ million US$ million US$ million US$ million
------------------------------
At 1 January 2018 109.0 284.5 141.4 534.9
Issue of Ordinary Shares 45.2 207.2 7.7 260.1
Purchase of ESOP Trust shares - - (1.5) (1.5)
Provision for share-based
payments - - 14.6 14.6
Conversion of convertible
bonds - - (56.1) (56.1)
Profit for the year - - 133.4 133.4
Other comprehensive income - - 140.6 140.6
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 31 December 2019 156.5 499.4 475.6 1,131.5
Consolidated Cash Flow Statement
For the year ended 31 December 2019
2019 2018
US$ million US$ million
-----------------------------------------------------------------------
Net cash from operating activities 1,108.7 722.8
------------ ------------
Investing activities:
Capital expenditure (241.4) (279.8)
Decommissioning pre-funding (9.9) (17.8)
Decommissioning expenditure (35.3) (72.7)
Receipts from sub-lease income 20.2 -
Proceeds from disposal of oil and gas properties 4.2 73.4
Net cash used in investing activities (262.2) (296.9)
Financing activities:
Issuance of Ordinary Shares 4.7 13.8
Net release/(purchase) of ESOP Trust shares 1.1 (1.5)
Warrant cash consideration (13.8) -
Proceeds from drawdown of long-term bank loans - 105.0
Repayment of long-term bank loans (399.7) (415.3)
Lease liability payments (224.7) -
Interest paid (251.9) (228.7)
------------ ------------
Net cash from financing activities (884.3) (526.7)
------------ ------------
Currency translation differences relating to cash and cash equivalents (8.7) (20.0)
------------ ------------
Net decrease in cash and cash equivalents (46.5) (120.8)
------------ ------------
Cash and cash equivalents at the beginning of the year 244.6 365.4
------------ ------------
Cash and cash equivalents at the end of the year 198.1 244.6
------------ ------------
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 31 December 2019
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 4 March 2020.
The financial information for the year ended 31 December 2019
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 2018 were
approved by the Board of Directors on 6 March 2019 and delivered to
the Registrar of Companies and those for 2019 will be delivered
following the Company's Annual General Meeting ('AGM'). The auditor
has reported on the 2019 accounts and their audit report was
unqualified.
Basis of preparation
The financial information has been prepared in accordance with
the recognition and measurement criteria of International Financial
Reporting Standards ('IFRS') adopted for use in the European Union.
However, this announcement does not itself contain sufficient
information to comply with IFRS. The Company will publish full
financial statements that comply with IFRS in April 2020.
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.
Accounting Policies
The accounting policies applied in these condensed financial
statements are consistent with those of the annual financial
statements for the year ended 31 December 2018, as described in
those annual financial statements, except for the adoption of IFRS
16 Leases.
IFRS 16 'Leases'
Premier adopted IFRS 16 Leases ('IFRS 16') with effect from 1
January 2019. IFRS 16 was issued in January 2016 to replace IAS 17
Leases. Further information is included in Premier's 2018 Annual
Report and Financial Statements - Accounting Policies
IFRS 16 sets out the principles for the recognition,
measurement, presentation and disclosure of leases and requires
lessees to account for all leases, with limited exceptions, under a
single on-balance sheet model similar to the accounting for finance
leases under IAS 17. Under IFRS 16, at the commencement date of a
lease, a lessee is required to recognise a liability to make lease
payments ('lease liability') and an asset representing the right to
use the underlying asset during the lease term ('right-of-use
asset'). Lease liabilities are measured at the present value of
future lease payments over the reasonably certain lease term.
Variable lease payments that do not depend on an index or a rate
are not included in the lease liability. Such payments are expensed
as incurred throughout the lease term.
In applying IFRS 16 for the first time the Group has applied the
short-term lease practical expedient by not recognising lease
liabilities in respect to lease arrangements with a remaining lease
term of less than 12 months as at 1 January 2019. The Group adopted
the modified retrospective approach to adoption on 1 January 2019,
measuring right-of-use assets at an amount based on their
respective lease liability on adoption, with the cumulative effect
of adopting the standard recognised at the date of initial
application without restatement of comparative information.
Lessees are required to separately recognise the interest
expense associated with the unwinding of the lease liability and
the depreciation expense on the right-of-use asset. These costs
replace amounts previously recognised as operating expenditure in
respect of operating leases in accordance with IAS 17. Principal
payments related to leases are now presented as financing cash
flows in the cash flow statement. The replacement of operating
lease, expenditure with the recognition of interest expense and
depreciation in respect to lease liabilities and right-of-use
assets, respectively, will result in an increase in Group EBITDAX.
The adoption of IFRS 16 will not impact the calculation of the
Group's financial debt covenants.
A matter finalised since the release of Premier's 2018 Annual
Report and Financial Statements is the determination of the
appropriate accounting for a lease arrangement entered into by a
lead operator as a sole signatory for the lease of equipment that
will be used in a joint operation. The IFRS Interpretations
Committee ('IFRIC') issued an agenda decision in respect to this
matter in March 2019. Where all partners of a joint operation are
considered to share the primary responsibility for lease payments
under a lease contract, the Group recognises its share of the
respective right-of-use asset and lease liability. This situation
is most common where the parties of a joint operation co-sign the
lease contract. The Group recognises a gross lease liability for
leases entered into on behalf of a joint operation where it has
primary responsibility for making the lease payments.
In such instances, if the arrangement between the Group and the
joint operation represents a finance sublease, the Group recognises
a net investment in sublease for amounts recoverable from
non-operators whilst derecognising the respective portion of the
gross right-of-use asset. The gross lease liability is retained on
the balance sheet. The net investment in sublease is classified as
either trade and other receivables or long-term receivables on the
balance sheet according to whether or not the amounts will be
recovered within 12 months of the balance sheet date.
The assessment as to whether a sublease exists predominantly
depends on whether the operator or the joint operation directs the
use of the respective right-of-use asset. Where the arrangement
between the operator and joint operation does not represent a
sublease or the sublease represents an operating sublease, the
Group retains the gross lease liability and right-of-use asset on
the balance sheet.
The following table provides a reconciliation of the Group's
operating lease commitments as at 31 December 2018 to the total
lease liability recognised on adoption of IFRS 16. The Group did
not recognise any finance leases under IAS 17.
Total
US$ million
----------------------------------------------------
Operating lease commitments at 31 December 2018 1,002.0
Contracts not in scope of IFRS 16(1) (85.6)
Effects of discounting(2) (189.9)
Short-term leases (3.1)
Impact of leases in joint operations(3) 99.0
Lease extension options(4) 77.6
Other (0.4)
Lease liabilities recognised on adoption of IFRS 16 899.6
(1) Contracts that were considered to be leases under IAS 17
which do not meet the definition of a lease under IFRS 16,
principally because the supplier is considered to have substantive
substitution rights over the associated assets.
(2) The previously disclosed lease commitments were
undiscounted, whilst the IFRS 16 obligations have been discounted
based on Premier's incremental borrowing rate.
(3) This represents the gross up of the lease obligations to
represent 100 per cent of the liability where the Group has entered
into a lease agreement on behalf of the joint operation and its
partners and has primary responsibility for lease payments.
(4) Previously, lease commitments only included non-cancellable
periods in the lease agreements. Under IFRS 16, the lease term
includes periods covered by options to extend the lease where the
Group is reasonably certain that such options will be
exercised.
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 are
reported as a discontinued operation.
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.
2019 2018
US$ million US$ million
-----------------------------------------------
Revenue:
Indonesia 172.2 192.8
Vietnam 198.6 272.4
United Kingdom 1,213.9 931.5
Rest of the World - 0.8
Total Group sales revenue 1,584.7 1,397.5
Interest and other finance revenue 2.4 7.6
------------ ------------
Total Group revenue from continuing operations 1,587.1 1,405.1
------------ ------------
Group operating profit:
Indonesia 90.9 111.8
Vietnam 96.2 142.2
United Kingdom 291.7 326.2
Rest of the World (0.9) (29.6)
Unallocated (1) (22.9) (19.6)
------------ ------------
Group operating profit 455.0 531.0
Interest revenue, finance and other gains 31.4 27.8
Finance costs and other finance expenses (383.9) (400.6)
Profit before tax from continuing operations 102.5 158.2
Tax 52.5 (53.1)
------------ ------------
Profit after tax from continuing operations 155.0 105.1
------------ ------------
Profit from discontinued operations 9.3 28.3
------------ ------------
2. Operating segments (continued)
2019 2018
US$ million US$ million
----------------------------------------------------------
Balance sheet
Segment assets:
Falkland Islands 680.0 648.1
Indonesia 481.5 417.7
Vietnam 437.8 312.0
United Kingdom 4,060.3 3,706.1
Rest of the World 179.4 103.8
Assets held for sale - 55.2
Unallocated(1) 253.4 372.0
Total assets 6,092.4 5,614.9
Liabilities:
Falkland Islands (13.0) (12.8)
Indonesia (216.5) (174.0)
Vietnam (324.3) (174.1)
United Kingdom (2,041.7) (1,431.9)
Rest of the World (34.5) (51.4)
Liabilities directly associated with assets held for sale - (21.9)
Unallocated(1) (2,330.9) (2,722.8)
------------ ------------
Total liabilities (4,960.9) (4,588.9)
------------ ------------
Other information
Capital additions and acquisitions:
Falkland Islands 30.0 15.1
Indonesia(2) 72.1 24.5
Pakistan 1.3 4.1
Vietnam(2) 5.0 (0.1)
United Kingdom(2) 142.6 (50.3)
Rest of the World(2) 61.2 37.2
------------ ------------
Total capital additions and acquisitions 312.2 30.5
------------ ------------
2. Operating segments (continued)
2019 2018
US$ million US$ million
----------------------------------------------------------
Depreciation, depletion, amortisation and impairment: (3)
Indonesia 44.5 46.6
Vietnam 60.0 55.6
United Kingdom 652.6 254.8
Rest of the World 0.8 1.4
------------ ------------
Total DD&A and impairment (continuing operations) 757.9 358.4
------------ ------------
(1) 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 costs, cash and cash equivalents,
mark-to market valuations of commodity contracts and interest rate
swaps and options, warrants and other long-term debt.
(2) Includes revisions to decommissioning estimates in the
year.
(3) Includes DD&A in respect of right-of-use assets.
Out of the total Group worldwide sales revenues of US$1,584.7
million (2018: US$1,397.5 million), revenues of US$1,213.9 million
(2018: US$931.5 million) arose from sales of oil and gas to
customers located in the UK. Included within the total revenues
were revenues of US$1,539.1 million (2018: US$1,468.7 million) from
contracts with customers. This was in addition to hedging gains of
US$45.6 million (2018: US$71.2 million loss).
Included in assets arising from the United Kingdom segment are
non-current assets (excluding deferred tax assets) of US$2,286.3
million (2018: US$2,090.5 million). Included in depreciation,
depletion, amortisation and impairment is a net impairment charge
in relation to the UK of US $41.5 million (2018: US$35.2 million
net credit).
Revenue from three customers (2018: three customers) each
exceeded 10 per cent of the Group's consolidated revenue. Sales to
two customers in the UK amounted to US$318.8 million and US$187.3
million (2018: two customers at US$312.4 million and US$142.3
million). Sales to one customer in Indonesia totalled US$160.4
million (2018: one customer amounting to US$186.5 million).
3. Cost of operation
2019 2018
US$ million US$ million
----------------------------------
Operating costs 322.6 487.5
Gas purchases 21.6 9.6
Stock overlift/underlift movement (10.5) (11.1)
Royalties 9.1 14.0
342.8 500.0
4. Tax
2019 2018
US$ million US$ million
-----------------------------------------------------
Current tax:
UK corporation tax on profits (6.0) (23.2)
Overseas tax 81.6 120.7
Adjustments in respect of prior years (24.5) (6.9)
------------ ------------
Total current tax 51.1 90.6
------------ ------------
Deferred tax:
UK corporation tax (94.0) (13.5)
Overseas tax (9.6) (24.0)
------------ ------------
Total deferred tax (103.6) (37.5)
------------ ------------
Tax (credit)/charge on profit on ordinary activities (52.5) 53.1
------------ ------------
The tax credit for the year can be reconciled to the profit per
the consolidated income statement as follows:
2019 2018
US$ million US$ million
------------------------------------------------------------------------------------------
Group profit on ordinary activities before tax 102.5 158.2
------------ ------------
Group profit on ordinary activities before tax at 46.0% weighted average rate (2018:
44.7%) 47.2 70.8
Tax effects of:
Income/expenses that are not taxable/deductible in determining taxable profit 16.2 (8.7)
Financing costs disallowed for UK supplementary charge 19.4 22.6
Non-deductible field expenditure 11.3 6.1
Tax and tax credits not related to profit before tax (mainly Ring Fenced Expenditure
Supplement) (89.2) (46.1)
Group relief - 2.7
Unrecognised tax losses 10.0 14.8
Effect of change in foreign exchange 0.3 17.8
Adjustments in respect of prior years (40.3) (31.2)
Utilisation and recognition of tax losses not previously recognised - -
Effect of differences in tax rates - (0.4)
Recognition that decommissioning provision will unwind at 50% (8.0) 4.7
Recognition of deferred tax asset (19.4) -
Tax (credit)/charge for the year (52.5) 53.1
Effective tax rate for the year (51.2%) 33.5%
------------ ------------
The UK deferred tax credit arises due to Ring Fence Expenditure
Supplement and is offset by other items impacting deferred tax. The
overseas deferred tax credit arises on fixed asset balances.
The prior year adjustments include overseas tax disputes found
in Premier's favour. The Group has not recognised any tax benefit
for ongoing tax disputes where a ruling in the Group's favour is
not yet considered to be probable.
In addition, during the year, the Group recognised a deferred
tax asset and associated tax credit in relation to an expected
future tax deduction associated with decommissioning costs funded
by E.ON. An offsetting finance cost, which is classified within
exchange differences and others, has also been recognised as this
tax deduction will be reimbursed to E.ON once received by
Premier.
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 55 per cent), assumptions
around future oil prices and changes to tax rates and
legislation.
5. Deferred tax
2019 2018
US$ million US$ million
-------------------------
Deferred tax assets 1,556.1 1,434.1
Deferred tax liabilities (129.9) (139.5)
1,426.2 1,294.6
(Charged)
/credited to Charge to
At 1 January Exchange income retained Disposal of At 31 December
2019 movements statement earnings asset 2019
US$ million 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
--------------- --------------- --------------- --------------- --------------- ---------------
5. Deferred tax (continued)
(Charged)
/credited to Charge to
At 1 January Exchange income retained Disposal of At 31 December
2018 movements statement earnings asset 2018
US$ million US$ million US$ million US$ million US$ million US$ million
----------------
UK deferred
corporation tax:
Fixed assets and
allowances (737.4) (0.3) 133.0 - (4.5) (609.2)
Decommissioning 476.9 (1.5) (99.1) - 0.5 376.8
Tax losses and
allowances 1,639.8 (1.0) (36.3) - - 1,602.5
Investment
allowance 71.2 (0.1) 6.7 - - 77.8
Derivative
financial
instruments 10.9 (0.1) 9.2 (33.8) - (13.8)
--------------- --------------- --------------- --------------- --------------- ---------------
Total UK
deferred
corporation tax 1,461.4 (3.0) 13.5 (33.8) (4.0) 1,434.1
--------------- --------------- --------------- --------------- --------------- ---------------
Overseas
deferred tax 1 (163.9) - 24.0 - 0.4 (139.5)
--------------- --------------- --------------- --------------- --------------- ---------------
Total 1,297.5 (3.0) 37.5 (33.8) (3.6) 1,294.6
--------------- --------------- --------------- --------------- --------------- ---------------
1 The overseas deferred tax relates mainly to temporary
differences associated with fixed asset balances
The Group's deferred tax assets at 31 December 2019 are
recognised to the extent that taxable profits are expected to arise
in the future against which the UK ring fence tax 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 2019 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$65/bbl
in 2020 and 2021, US$70/bbl in 2020 and US$70/bbl in 'real' terms
thereafter. These price assumptions are consistent with that used
when assessing the Group's underlying assets for impairment. The
cash flows included in the corporate model are predominantly
derived from future revenue from existing UKCS assets. The existing
UKCS assets include both existing producing assets and certain
future currently unsanctioned assets. The cash flows also include
future revenue from the proposed acquisition assets announced on 7
January 2020 on the basis that, at the balance sheet date,
management consider it probable that the acquisitions will complete
and that the cash flows will arise within Premier's UK ring-fence.
The acquisitions represent approximately US$267 million of the
deferred tax assets recognised at 31 December 2019. The results of
the corporate model concluded that it was appropriate to continue
to recognise the Group's deferred tax assets in respect of UK ring
fence tax losses and allowances with the exception of US$18.1
million of tax losses and US$24.4 million of allowances relating to
supplementary charge.
In addition to the above, there are carried forward non-ring
fence UK tax losses of approximately US$376.4 million (2018:
US$359.1 million) and overseas tax losses of US$267.7 million
(2018: US$154.8 million) for which a deferred tax asset has not
been recognised. None of the UK tax losses (ring fence and non-ring
fence) have a fixed expiry date for tax purposes. No deferred tax
has been provided on unremitted earnings of overseas subsidiaries,
following a change in UK tax legislation in 2009 which exempted
foreign dividends from the scope of UK corporation tax, where
certain conditions are satisfied.
6. Earnings per share
The calculation of basic earnings per share is based on the
profit after tax and the weighted average number of Ordinary Shares
in issue during the year. Basic and diluted earnings per share are
calculated as follows:
2019 2018
US$ million US$ million
------------------------------------------------------------------------------------------
Earnings
Earnings for the purpose of diluted earnings per share on continuing operations 155.0 105.1
Profit from discontinued operations 9.3 28.3
Earnings for the purposes of diluted earnings per share on continuing and discontinued
operations 164.3 133.4
------------ ------------
Number of shares (millions)
Weighted average number of Ordinary Shares for the purposes of basic earnings per share 826.2 774.0
Effects of dilutive potential Ordinary Shares:
Contingently issuable shares 76.9 88.3
------------ ------------
Weighted average number of Ordinary Shares for the purposes of diluted earnings per share 903.1 862.3
------------ ------------
Earnings per share from continuing operations (cents)
Basic 18.8 13.6
Diluted 17.2 12.2
------------ ------------
Earnings per share from discontinued operations (cents)
Basic 1.1 3.7
Diluted 1.0 3.3
------------ ------------
The inclusion of the contingently issuable shares in the current
and prior year produces diluted earnings per share for both
continuing and discontinued operations. At 31 December 2019 there
were 76.9 million potential Ordinary Shares in the Company that are
underlying the Company's equity warrants and share options that may
dilute earnings per share in the future. These have been included
in the calculation of diluted earnings per share.
7. Intangible exploration and evaluation ('E&E') assets
Total
Oil and Gas Properties US$ million
Cost:
At 1 January 2018 1,061.9
Exchange movements (5.6)
Additions during the year 62.1
Transfer to PP&E (274.2)
Disposals (1.4)
Assets classified as held for sale (0.6)
Exploration expense (1) (29.6)
------------
At 31 December 2018 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
------------
(1) Expensed in the income statement with pre-licence expenses
of US$14.0 million in 2019 (2018: US$5.6 million)
The amounts for intangible E&E assets represent costs
incurred on active exploration projects. These amounts are written
off to the income statement as exploration expense unless
commercial reserves are established or the determination process is
not completed and there are no indications of impairment. Assets
written off in the year include the Ibu Lembu prospect in Indonesia
following management's decision to no longer pursue the
prospect.
The outcome of ongoing exploration, and therefore whether the
carrying value of E&E assets will ultimately be recovered, is
inherently uncertain. To the extent that we have an active licence
to continue to explore for resources and have an intention to
continue exploration activity, the exploration cost associated with
the licence will remain capitalised as an E&E asset on the
balance sheet. Once exploration activity has completed and we have
no further intention to explore the licence for resources, costs
capitalised until that point will be expensed and no further costs
associated with the licence will be capitalised.
The balance carried forward is predominantly in relation to the
Group's prospects in the Falkland Islands, Tuna in Indonesia and
the non-operated Zama prospect and Block 30 in Mexico.
8. Property, plant and equipment
Right-of-use assets Other fixed
Oil and gas properties US$ million assets Total
US$ million US$ million US$ million
=============================================
Cost:
At 1 January 2018 7,589.4 - 66.7 7,656.1
Exchange movements 1.2 - (2.1) (0.9)
Additions and changes in decommissioning
estimates (33.5) - 1.9 (31.6)
Transferred from E&E 274.2 - - 274.2
Assets classified as held for sale (4.1) - - (4.1)
Disposals (19.6) - (9.2) (28.8)
====================== =================== ============ ============
At 31 December 2018 7,807.6 - 57.3 7,864.9
Implementation of IFRS 16 - 803.3 - 803.3
====================== =================== ============ ============
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
====================== =================== ============ ============
Amortisation, depreciation and impairment:
At 1 January 2018 5,220.3 - 54.9 5,275.2
Exchange movements 2.1 - (1.7) 0.4
Charge for the year 386.5 - 7.1 393.6
Net impairment credit (35.2) - - (35.2)
Disposals (5.5) - (9.2) (14.7)
At 31 December 2018 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 charge 41.5 - - 41.5
At 31 December 2019 6,098.0 223.0 56.0 6,377.0
Net book value:
At 31 December 2018 2,239.4 - 6.2 2,245.6
====================== =================== ============ ============
At 31 December 2019 1,888.6 588.0 5.2 2,481.8
====================== =================== ============ ============
Finance costs that have been capitalised within oil and gas
properties during the year total US$4.3 million (2018: US$1.2
million), at a weighted average interest rate of 8.2 per cent
(2018: 7.6 per cent).
8. Property, plant and equipment (continued)
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.
Impairment charge
The impairment charge in the current year relates to UK assets.
The impairment charge of US$41.5 million (pre-tax) (2018: net
impairment reversal of US$35.2 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 asset. In the period, Group-wide
indicators of impairment, being a reduction in both the long-term
oil price and decommissioning discount rate assumptions, were
identified. US$30.5 million of the current year charge relates to
the net effect of changes in decommissioning estimates on assets
previously depreciated to nil net book value. The remainder relates
primarily to Solan. When testing producing assets for impairment,
future cash flows were estimated using the following oil price
assumption: US$65/bbl in 2020 and 2021, US$70/bbl in 2022 and
US$70/bbl in 'real' terms thereafter (2018: US$60/bbl in 2019,
US$65/bbl in 2020, 2021 at US$70/bbl followed by a long-term price
of US$75/bbl (real)) and were discounted using a pre-tax discount
rate of 9 per cent for the UK assets (2018: 9 per cent) and 12.5
per cent for the non-UK assets (2018: 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$65/bbl
(real)) would increase the impairment charge by US$13.4 million,
all on the UK Solan asset. No other assets would be impaired.
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
(2018: 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 2026. 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$203.8
million (2018: US$166.8 million).
The key assumptions applied in the measurement of the
value-in-use of the Catcher asset are discount rate, oil prices,
forecasted recoverable reserves and estimated future costs. No
reasonably possible change in any of these key assumptions would
cause the asset's carrying amount to exceed its recoverable
amount.
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
COP dates during the year based on field performance.
In addition to the above the Group has a net investment in
sublease of US$75.7 million (1 January 2019: US$96.3 million), of
which US$54.1 million is classified as a long-term receivable and
US$21.6 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$5.3 million, which predominantly represents
unwinding of the net investment in sublease, has been recognised as
finance income in the year.
9. Leases
Lease liabilities
US$ million
At 1 January 2019 899.6
Re-measurement 8.3
Finance costs 50.0
Cash outflows for lease arrangements (224.7)
Exchange differences (0.7)
===================================== =================
At 31 December 2019 732.5
=================
Classified as:
- short-term 149.7
- non-current 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$23.3 million
were expensed. Lease liabilities have been classified as either
short-term or non-current in the balance sheet according to whether
they are expected to be settled within 12 months of the balance
sheet date.
The significant portion of the Group's lease liabilities
represent lease arrangements for FPSO vessels on the Catcher, Chim
Sáo and Huntington assets. The lease liabilities, and associated
right-of-use-assets have been calculated by reference to
in-substance fixed lease payments in the underlying agreements
incurred throughout the non-cancellable period of the lease along
with periods covered by options to extend the lease where the Group
is reasonably certain that such options will be exercised. When
assessing whether extension options were likely to be exercised,
assumptions are consistent with those applied when testing for
impairment.
Under the modified retrospective transition method, lease
payments were discounted at 1 January 2019 using an incremental
borrowing rate representing the rate of interest that Premier would
have to pay to borrow over a similar term, and with a similar
security, the funds necessary to obtain an asset of a similar value
to the right-of-use asset in a similar economic environment. The
incremental borrowing rate applied to each lease was determined by
taking into account the risk-free rate, adjusted for factors such
as the credit rating linked to the life of the underlying lease
agreement. The weighted average incremental borrowing rate applied
by Premier upon transition was 7.2 per cent. Incremental borrowing
rates applied to individual leases ranged between 5.4 per cent and
8.2 per cent.
10. Notes to the cash flow statement
2019 2018
US$ million US$ million
---------------------------------------------------------
Profit before tax for the year 102.5 158.2
Adjustments for:
Depreciation, depletion, amortisation and impairment 757.9 358.4
Other operating costs 2.9 1.2
Exploration expense 7.3 29.6
Provision for share-based payments 7.1 10.8
Interest revenue and finance gains (31.4) (27.8)
Finance costs and other finance expenses 383.9 400.6
Profit on disposal of non-current assets (4.2) (42.3)
Operating cash flows before movements in working capital 1,226.0 888.7
(Increase)/decrease in inventories (3.8) 1.2
(Increase)/decrease in receivables (74.9) 72.6
(Decrease) in payables (19.5) (93.0)
------------ ------------
Cash generated by operations 1,127.8 869.5
Income taxes paid (61.2) (128.8)
Interest income received 6.2 7.5
------------ ------------
Net cash from continuing operating activities 1,072.8 748.2
------------ ------------
Net cash from discontinued operating activities 7.2 29.0
------------ ------------
Net cash from operating activities 1,080.0 777.2
------------ ------------
Movement in JV cash 28.7 (54.4)
------------ ------------
Total net cash from operating activities 1,108.7 722.8
------------ ------------
10. Notes to the cash flow statement (continued)
Analysis of changes in net debt:
2019 2018
US$ million US$ million
a) Reconciliation of net cash flow to movement in net debt:
Movement in cash and cash equivalents (46.5) (120.8)
Proceeds from drawdown of long-term bank loans - (105.0)
Repayment of long-term bank loans 399.7 415.3
Conversion of convertible bonds - 181.9
Non-cash movements on debt and case balances (primarily, FX) (12.3) 22.1
Reduction in net debt in the year 340.9 393.5
Opening net debt (2,330.7) (2,724.2)
------------ ------------
Closing net debt (1,989.8) (2,330.7)
------------ ------------
b) Analysis of net debt:
Cash and cash equivalents 198.1 244.6
Borrowings (2,187.9) (2,575.3)
------------ ------------
Total net debt (1,989.8) (2,330.7)
------------ ------------
The carrying amounts of the borrowings on the balance sheet are
stated net of the unamortised portion of the refinancing fees of
US$18.1 million (2018: US$23.3 million).
11. Subsequent Events
Debt Reduction
Subsequent to year-end, US$129.5 million of the RCF debt
facility was cancelled and a further US$50 million was repaid,
which will result in a reduction in commitment fee costs in
2020.
Corporate actions
In January 2020, the Group publicly announced the agreement it
had reached to undertake the following corporate actions (together
the 'Corporate Actions'):
-- an amend and extend ('A&E') of all the Group's
refinancing facilities, including extension of maturities from May
2021 to November 2023;
-- the proposed acquisition of a 25 per cent working interest in
Tolmount from Dana and interests in Andrew and Shearwater (together
the 'Acquisitions' or 'Acquired Assets');
-- entering into a US$300 million bridge facility to partly
finance the Acquisitions ('the Bridge Facility'). Based on current
forecasts it is not expected that the Bridge Facility will be
unitised; and
-- raising equity from shareholders via a combination of a
placing and a rights issue (the 'Equity Raise') which is fully
underwritten.
Lender consents were obtained from the required proportion of
lenders for the above Corporate Actions, prior to their
announcement. As part of this consent process, pending the Schemes
becoming effective, sufficient lenders have provided forbearances
in respect of any defaults that may be argued to have arisen under
Premier's existing credit facilities by virtue of the
implementation of the Schemes and other aspects of the Corporate
Actions. Accordingly, no resulting action can be taken to
accelerate, or prevent drawings being made under, the Group's
existing credit facilities in respect of the Scheme or Corporate
Actions.
In February 2020, more than 75 per cent of the Group's creditors
voted to support the Group's scheme of arrangement. Therefore,
management believes it is probable that the above actions will be
approved via a court scheme of arrangement in March 2020.
Non-adjusting post balance sheet event
Premier are exposed to macro-economic risks, including pandemic
diseases that could have a material adverse effect on our
operations. We continue to monitor the recent coronavirus COVID 19
outbreak, which is causing economic disruption in China and
elsewhere and may impact our performance in 2020. However, at
present, it is not possible to predict whether or not the COVID-19
outbreak will have a material adverse effect on our earnings, cash
flows and financial condition.
12. External audit
This preliminary announcement is consistent with the audited
financial statements of the Group for the year-ended 31 December
2019.
13. Publication of financial statements
It is anticipated that the full Annual Report and Financial
Statements will be published in April 2020. Copies will be
available from this date at the Company's head office, 23 Lower
Belgrave Street, London SW1W 0NR, and on the Company's website (
www.premier-oil.com ).
14. Annual General Meeting
The Annual General Meeting will be held at the King's Fund,
11-13 Cavendish Square, London W1G 0AN on Tuesday 12(th) May 2020
at 11:00 am
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.
-- Cash margin: Operating cash flow for the year divided by
working interest production. This is a useful indicator of cash
generation from the Group's producing assets.
-- 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 2019
Working interest basis
Falkland Pakistan/
Islands Indonesia Mauritania UK Vietnam Mexico Total
----------- -------------- -------------- -------------- ------------- ----------- --------------------------
Oil
Oil and
Oil Oil Oil Oil Oil Oil and NGLs
and and and and and and NGLs Gas and
NGLs Gas NGLs Gas NGLs Gas NGLs Gas NGLs Gas NGLs Gas Gas
------ --- ------ ------ ------ ------ ------ ------ ------ ----- ------ --- ------- -------- -------
mmbbls bcf mmbbls bcf mmbbls bcf mmbbls bcf mmbbls bcf mmbbls bcf mmbbls bcf mmboe
------ --- ------ ------ ------ ------ ------ ------ ------ ----- ------ --- ------- -------- -------
Group proved plus probable reserves:
At 1 January
2019 - - 1.03 160.76 0.05 34.89 68.04 342.17 17.62 23.27 - - 86.74 561.09 193.7
------ --- ------ ------ ------ ------ ------ ------ ------ ----- ------ --- ------- -------- -------
Revisions - - 0.2 16.42 - - 5.46 32.96 -0.15 0.42 - - 5.51 49.8 14.58
------ --- ------ ------ ------ ------ ------ ------ ------ ----- ------ --- ------- -------- -------
Discoveries
and extensions - - - - - - - - - - - - - - -
------ --- ------ ------ ------ ------ ------ ------ ------ ----- ------ --- ------- -------- -------
Acquisitions
and divestments - - - 0.26 -0.05 -32.12 - - - - - - -0.05 -31.86 -5.05
------ --- ------ ------ ------ ------ ------ ------ ------ ----- ------ --- ------- -------- -------
Production - - -0.14 -20.65 - -2.77 -16.67 -17.83 -3.31 -4.31 - - -20.12 -45.56 -28.49
------ --- ------ ------ ------ ------ ------ ------ ------ ----- ------ --- ------- -------- -------
At 31 December
2019 - - 1.09 156.79 - - 56.83 357.3 14.16 19.38 - - 72.08 533.47 174.74
------ --- ------ ------ ------ ------ ------ ------ ------ ----- ------ --- ------- -------- -------
Total Group developed and undeveloped reserves
--------------------------
Proved on
production - - 0.82 116.72 - - 23.25 57.95 12.53 16.45 - - 36.6 191.12 73.74
------ --- ------ ------ ------ ------ ------ ------ ------ ----- ------ --- ------- -------- -------
Proved
approved/justified
for development - - 0.08 17.48 - - 12.21 156.84 0.2 0.46 - - 12.49 174.78 45.93
------ --- ------ ------ ------ ------ ------ ------ ------ ----- ------ --- ------- -------- -------
Probable
on production - - 0.18 9.53 - - 14.89 17.85 1.12 1.78 - - 16.19 29.16 21.8
------ --- ------ ------ ------ ------ ------ ------ ------ ----- ------ --- ------- -------- -------
Probable
approved/justified
for development - - 0.01 13.06 - - 6.48 124.66 0.31 0.69 - - 6.8 138.41 33.27
------ --- ------ ------ ------ ------ ------ ------ ------ ----- ------ --- ------- -------- -------
At 31 December
2019 - - 1.09 156.79 - - 56.83 357.3 14.16 19.38 - - 72.08 533.47 174.74
------ --- ------ ------ ------ ------ ------ ------ ------ ----- ------ --- ------- -------- -------
Notes:
1 Both the Zama discovery and Sea Lion remained as contingent
resources awaiting FID/Sanction and do not appear in this
table.
2 All assets in Pakistan have been divested as of April 2019.
3 Proved plus probable gas includes fuel gas
Premier Oil plc 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 ('OIAC'), 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 164.4 mmboe as at 31
December 2019 (2018: 181.5 mmboe). This was calculated at year-end
2019, using the following oil price assumption: US$65/bbl in 2020
and 2021, US$70/bbl in 2022, US$70/bbl in 'real' terms thereafter
(2018: Dated Brent forward curve of US$60/bbl in 2019, US$65/bbl in
2020, US$70/bbl in 2021 and US$75/bbl in 'real' terms
thereafter).
This information is provided by RNS, the news service of the
London Stock Exchange. RNS is approved by the Financial Conduct
Authority to act as a Primary Information Provider in the United
Kingdom. Terms and conditions relating to the use and distribution
of this information may apply. For further information, please
contact rns@lseg.com or visit www.rns.com.
END
FR FFFIVVVISIII
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