TIDMPMO
RNS Number : 1020S
Premier Oil PLC
07 March 2019
Premier Oil plc (Premier)
Full Year Results for the year ended 31 December 2018
Press Release
Tony Durrant, Chief Executive Officer, commented:
"2018 saw higher production, positive free cash flow and a
return to profitability. The Group is ahead of plans to restore
balance sheet strength and remains focused on consistently
delivering free cash flows. Growth projects such as Tolmount, Zama
and Sea Lion, together with promising exploration in Mexico and
Indonesia, are being advanced within a disciplined financial
framework."
2018 Operational highlights
-- Record production of 80.5 kboepd (2017: 75.0 kboepd)
-- Catcher oil plateau rates increased to 66 kbopd (gross)
-- Tolmount Main (UK) gas project sanctioned; estimated peak production of 58 kboepd (gross)
-- Highly prospective new licences secured offshore Mexico and Indonesia
-- US$73.4 million of cash receipts from non-core asset disposals
2018 Financial highlights
-- US$133.4 million post tax profit (2017: post tax loss of US$253.8 million)
-- EBITDAX increased to US$882.3 million, up 50% (2017: US$589.7 million)
-- Cash flows from operations of US$777.2 million, up 64% (2017: US$475.3 million)
-- Opex of US$10/boe with additional lease costs of US$7/boe; low cost base maintained
-- Total capex (development, exploration and abandonment) of US$353 million, below forecast
-- US$181 million debt reduction from accelerated conversion of convertible bonds
-- Year-end net debt of US$2.3 billion, down US$393 million (2017: US$2.7 billion)
-- Covenant leverage ratio reduced to 3.1x (2017: 6.0x)
2019 Outlook
-- Production guidance of 75 kboepd, a 5% increase after disposals; 89 kboepd year to date
-- Cash margins expected to be 30% higher at comparable commodity pricing
-- Opex (excluding lease costs) and capex guidance of US$13/boe
and US$340 million, respectively
-- Project sanction of Catcher Area additions (Catcher North and Laverda) anticipated 1H
-- Zama, Tolmount East appraisal programmes to complete Q3
-- Formal loan application for Sea Lion funding to be submitted in Q2
-- Material free cash flow, driving further debt reduction of US$250 million to US$350 million
ENQUIRIES
Premier Oil plc Tel: + 44 (0)20 7730 1111
Tony Durrant
Richard Rose
Camarco Tel: + 44 (0)20 3757 4980
Billy Clegg
Georgia Edmonds
A presentation to analysts will be held at 9.30am today at the
offices of Premier Oil, 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
Oil prices increased during the first three quarters of 2018,
peaking at US$86.2/bbl in October before falling steeply to close
the year at US$50.2/bbl. Against this volatile backdrop, 2018 was
another year of solid operational delivery by Premier, resulting in
significantly higher cash flows and a return to profit.
Production increased year-on-year averaging 80.5 kboepd, despite
material asset sales. This was driven by new production from our
operated Catcher Area and continued high operating efficiency
across the portfolio.
Production (kboepd) Working interest Entitlement
2018 2017 2018 2017
--------- -------- ------ ------
Indonesia 13.2 14.1 8.7 10.3
--------- -------- ------ ------
Pakistan 5.3 6.5 5.3 6.4
--------- -------- ------ ------
UK 46.8 39.5 46.8 39.5
--------- -------- ------ ------
Vietnam 15.2 14.9 13.0 13.0
--------- -------- ------ ------
Total 80.5 75.0 73.8 69.2
--------- -------- ------ ------
Our production portfolio today is concentrated in two main
geographical areas: South East Asia (Indonesia and Vietnam) and the
UK Continental Shelf. Our operated Asian assets, driven by high
uptime and low cost structures, generated material free cash flows
for the Group. Singapore demand for our Indonesian gas remained
robust and the opportunity remains to develop and deliver
additional resource into the Singapore market under our long term
gas sales agreements. Our Chim Sáo field in Vietnam continued to
outperform and we again increased our reserves estimates for the
field at the end of 2018, a third increase since first oil in
2011.
Production from our UK assets, which represents over half the
Group's production, grew materially during 2018. This was driven by
our Catcher Area which reached increased plateau rates of 66 kbopd
(gross) in the fourth quarter, considerably in excess of the 50
kbopd (gross) envisaged at sanction. This strong performance has
continued into 2019 and further underpins our confidence in the
longer term cash flow generation potential of this asset. At year
end, we revised upwards our Catcher Area reserves to include the
Catcher North and Laverda accumulations. In addition, with more
production history to calibrate our dynamic models and to
underwrite a higher recovery, we would hope to be able to revise
over time our estimate of the Catcher Area reserves. We also aim to
drill infill wells to target unswept areas of the reservoir to
extend plateau rates and to ensure that the Catcher Area FPSO
continues to operate at full capacity.
The sanction of our operated 500 Bcf (gross) Tolmount Main gas
field in August was a significant achievement for the Group.
Tolmount Main is, in barrel of oil equivalent terms, of similar
size to our Catcher project at sanction. By partnering with
infrastructure company Kellas Midstream, we have been able to
minimise our share of capital expenditure while retaining our
equity exposure to the upside in the project, significantly
enhancing the expected returns on our investment. Once on-stream,
Tolmount Main will provide the next phase of growth for the UK
business unit and will contribute materially to the Group's cash
flows, given our tax-advantaged position in the UK.
The HGS (Humber Gathering System) infrastructure through which
Tolmount Main volumes will flow has the potential to develop into a
significant new production hub over time. It is highly economic for
us to deliver additional equity gas resource over the HGS
infrastructure and we are on track to spud the Tolmount East
appraisal well, which is seeking to confirm resource potential of
up to 300 Bcf (gross), in July. We also plan to acquire seismic
data over the Greater Tolmount Area during the first half of 2019
to further define prospectivity in the area. In addition, there is
the potential to benefit from third party volumes transported over
the Tolmount Main platform.
Our largest pre-development project is the fully appraised Sea
Lion field which, at over 220 mmboe (gross) of resources in Phase 1
alone, represents a material opportunity for Premier. During 2018
we selected the key contractors for the project, many of whom also
worked on our operated Catcher project, and put in place LOIs for
the provision of services. Our key contractors, having carried out
extensive due diligence, agreed to provide up to US$400 million of
financing for Sea Lion Phase 1, underlining the robust nature of
the project and the opportunity to be involved in developing the
first field in a new basin. The critical path to a final investment
decision remains securing a senior debt funding structure, likely
involving a combination of export credit financing and project bank
funding. The industry continues to follow closely our progress and
it remains our preference to bring in an additional equity partner
to the project once we have finalised the funding structure.
Our exploration team has done an excellent job of refocusing our
portfolio towards lower risk but more impactful opportunities
whilst operating within significantly reduced budgetary
constraints. A notable success was the Zama discovery in 2017. Much
of 2018 was spent preparing for the Zama appraisal campaign as well
as progressing early engineering work on potential development
concepts. The programme is well underway with encouraging initial
results.
We have further enhanced our exploration portfolio through the
capture of additional acreage in our basins of choice. We were
particularly pleased to have secured the heavily contested Block 30
in Round 3.1 just prior to the new government placing a moratorium
on further licensing rounds. We were also successful in securing
the Andaman II licence offshore Indonesia in the highly prospective
North Sumatra basin. This has attracted considerable industry
attention with the opening up of a potential commercialisation
route via the onshore Arun gas terminal. Today, our exploration
portfolio is capable of delivering a series of high impact wells
which have the potential to augment materially the Group's resource
base. We have also continued to exit our more mature, legacy
positions which do not meet our internal investment hurdles.
At 31 December 2018, Group proven and probable (2P) reserves and
contingent (2C) resources, on a working interest basis, were 867
mmboe (2017: 902 mmboe), including the effect of 2018 production
and asset sales. The sanction of the Tolmount Main project added 46
mmboe to 2P reserves. In addition, Premier booked the 3 mmboe (net)
2P reserves related to the Catcher North and Laverda fields while
there were also reserve upgrades at Chim Sáo and Elgin
Franklin.
2P reserves (mmboe) 2P reserves + 2C
resources (mmboe)
1 January 2018 302 902
-------------------- -------------------
Production (30) (30)
-------------------- -------------------
Net additions, revisions 66 21
-------------------- -------------------
Sea Lion recategorisation (134) -
-------------------- -------------------
Disposals, relinquishments (10) (26)
-------------------- -------------------
31 December 2018 194 867
-------------------- -------------------
Our proven and probable (2P) reserves, on a working interest
basis, reduced to 194 mmboe (2017: 302 mmboe), primarily due to the
recategorisation of Sea Lion Phase 1 2P reserves (134 mmboe) as 2C
resources following new guidelines issued by the Society of
Petroleum Engineers. These point to holding Sea Lion undeveloped
resources as contingent until financing for the project and formal
approvals have been secured. To rebook the 2C resources of Sea Lion
as 2P reserves the funding and other approvals would need to be in
place. The booking of the Tolmount Main field as 2P reserves,
following its sanction, and an upward revision in our estimate of
2P reserves at Catcher, Chim Sáo and Elgin Franklin, more than
offset the impact of 2018 production and disposals. This represents
a reserves replacement ratio of 220 per cent, excluding the
technical recategorisation of Sea Lion resources.
We are the operator of the majority of our assets which provides
us with strong control over future expenditure programmes and the
ability to flex our discretionary spend in the event of another
downturn in the commodity price. During 2018, development,
exploration and abandonment spend was US$353 million, below
original guidance, due to deferrals of appraisal and abandonment
expenditure and tight cost control. Total 2019 capital expenditure
(including abandonment) is expected to be US$340 million. Full year
2018 operating costs were US$10/boe while leasing costs associated
with our operated Chim Sáo, Huntington and Catcher FPSOs amounted
to US$7/boe. 2019 operating costs are forecast at US$13/boe,
slightly higher than 2018, reflecting the impact of disposals of
low cost gas production and expected natural decline from fixed
cost base assets, while lease costs are expected to be of the order
of US$7/boe.
Debt reduction remains a key corporate priority. The Group's
strong operational performance supported by its low cost base and a
disciplined capex programme resulted in us generating material free
cash flow during 2018. This, together with proceeds of US$73
million from selective disposals of non-core assets and the early
exchange of the convertible bond, resulted in a reduction of net
debt by US$393 million to US$2.33 billion, ahead of the plan agreed
with our lenders. We also significantly reduced our covenant
leverage ratio (covenant net debt / EBITDA) to 3.1x (2017: 6.0x)
comfortably within the covenant of 5.0x at year end and back in
line with many of our peers.
Looking to the year ahead, we have a highly cash generative
production base, which is supported by a substantial hedging
programme, an improved portfolio mix (underpinned by high margin
Catcher barrels) and a tightly controlled cost base. This positions
us well to deliver further debt reduction in 2019 while progressing
our future growth projects to create material value to all of our
stakeholders over the longer term.
We have considerable optionality within our portfolio to grow
organically and deliver value over the longer term. At the same
time, Premier has an excellent track record of delivering value
from acquisitions and we continue to evaluate potential acquisition
opportunities that enhance our asset base and create synergies with
the existing core businesses. With many of the majors and larger
independents looking to refocus their portfolios away from the UK
North Sea, there is an opportunity for Premier to acquire mid-life,
cash flow generative and profitable production assets with
potentially significant upsides, which have not been pursued by the
previous asset holders. Of course, any potential acquisitions have
to be measured against and compete for capital with the existing
organic opportunities within our portfolio.
It is our highest priority to continue to operate all of our
assets in a safe and responsible manner, to ensure the safety of
our workforce and to minimise potential risk to the environment.
Not only is it the right thing to do, it is also a prerequisite for
maintaining our social and legal licence to operate for the longer
term. We are pleased to report that we recorded no serious
injuries, no spills and no material process safety events during
2018. We also had record low Greenhouse Gas Intensity at Premier's
operated assets. In all our HSES metrics, we aim to deliver
continuous improvement and upper quartile performance against our
peer group.
The composition of the Board and its committees is continually
under review. As Jane Hinkley will reach the ninth anniversary of
her appointment during 2019 we are pleased to announce that Barbara
Jeremiah, subject to the approvals of shareholders at the AGM in
May, will join the Board. It is intended that, following a
transitional period, Barbara will take over as Chair of the
Remuneration Committee from Jane.
UNITED KINGDOM
The UK delivered record production in 2018 of 46.8 kboepd, up
almost 20 per cent on 2017, driven by increased Catcher Area
(Premier 50 per cent operated interest) production. In November and
December, UK production averaged over 60 kboepd, supported by high
uptime across the asset base and increased rates from the Catcher
Area, offset by the Babbage Area sale in early December. In August,
Premier sanctioned its next UK growth project, the 500 Bcf Tolmount
Main gas development (Premier 50 per cent operated interest) which
is now in the execution phase.
Production
The Catcher Area FPSO, which produces from the Catcher, Varadero
and Burgman fields, reached oil production rates of 60 kbopd
(gross) in May, as commissioning of the gas plant was completed. In
the fourth quarter, continued strong reservoir performance and
increased plant availability, following final commissioning of the
FPSO secondary systems, resulted in oil plateau production rates
being increased to 66 kbopd and Premier issuing the final
acceptance certificate to the FPSO provider. We have safely
delivered 38 Catcher cargoes since first oil.
Four further Catcher Area producer wells were drilled during
2018 with the 18(th) well, a Burgman field producer, completed in
October. This concluded a highly successful three year drilling
programme which was 33 per cent below budget and delivered well
productivity on average 30 per cent higher than forecast. In
addition, dynamic data continues to demonstrate good connectivity
between the reservoirs and strong pressure support provided by the
aquifer and injector wells. The Group remains highly encouraged
about the potential overall recovery from the Catcher Area and
expects to refine its estimates as more production data is
obtained.
The non-operated Elgin-Franklin field (Premier 5.2 per cent
non-operated interest) averaged 6.7 kboepd (net), ahead of
forecast. Production was boosted by a strong performance from the
new wells brought on-stream, successful remedial work on existing
wells and continued high operating efficiency. At year end, Premier
revised upwards its 2P reserves by 7 mmboe (net) which brings them
in line with the operator's estimates and reflecting the inclusion
of planned additional infill wells.
Premier's operated Huntington field (Premier 100 per cent
operated interest) averaged 5.8 kboepd (net) during 2018,
reflecting forecast natural decline and several unplanned shut
downs. Modifications to the FPSO were made to facilitate gas import
which, together with the conversion of a former production well to
a water injector, has improved reservoir deliverability and plant
stability. The Huntington field has continued to benefit from high
operating efficiency post period end with production averaging over
6 kboepd year to date in 2019.
Production from the Premier-operated Solan field (Premier 100
per cent operated interest) averaged 4.6 kboepd, ahead of forecast,
driven by high operating efficiency of over 90 per cent. Premier
expects to drill a new producer (P3) in 2020 targeted at increasing
production from the Central Northern part of the field. Separately,
Premier continues to review the potential for third party volumes
over the Solan infrastructure.
The Balmoral Area, comprising the Balmoral, Brenda, Nicol and
Stirling fields, delivered 1.3 kboepd (net) in 2018 with production
impacted by an extended summer maintenance shut down. Production
from the Kyle field (Premier 40 per cent non-operated interest)
averaged 1.6 kboepd (net). As a result of cost control and asset
performance, cessation of production from the Balmoral Area has now
been deferred until 2021 while the lease of the Banff FPSO, which
handles Kyle's production, has been extended to August 2019. In the
Southern North Sea, the Rita (Premier 74 per cent operated
interest) and Hunter (Premier 79 per cent operated interest) fields
ceased production in mid-2018 following closure of the
Theddlethorpe gas processing terminal.
UK unit field operating costs on a per barrel of oil equivalent
reduced to US$13/boe (2017: US$18/boe) while lease costs increased
to US$10/boe (2017: US$5/boe). These reflect new production from
the leased Catcher FPSO. In 2019, Premier expects UK operating
costs (including lease costs) to remain around US$23/boe with the
impact of a full year of Catcher production at increased rates
offset by natural decline on more mature, fixed cost base assets
such as Huntington, Kyle and the Balmoral Area.
Developments
Premier has identified several high value subsea tie-backs and
infill drilling locations to maintain and extend production rates
from the Catcher Area. Premier expects to sanction the development
of the Catcher North and Laverda oil accumulations (Premier 50 per
cent operated interest) during the first half of 2019 and, as a
result, at year end 2018 booked the 3 mmboe (net) reserves
associated with the two fields. The US$70 million (net) project
will entail two development wells drilled from a common drill
centre and tied back to the Varadero field. Drilling is scheduled
to commence in mid-2020 with first oil targeted for early 2021. In
addition, Premier expects to drill an infill well on the Varadero
field immediately before the Catcher North and Laverda drilling
programme to target resources beyond the reach of the initial
production wells. Premier plans to acquire 4D seismic across the
Catcher Area in the second quarter of 2020 to help confirm
additional future infill well locations.
In August, Premier and its partners sanctioned the development
of the Tolmount Main gas field (Premier 50 per cent operated
interest) in the Southern Gas Basin. The Tolmount Main gas field is
expected to produce around 500 Bcf (96 mmboe) (gross) of gas with
peak production of up to 300 mmscfd (58 kboepd) (gross).
The Tolmount Main gas project is now well into its execution
phase. Construction of the minimal facilities platform commenced in
Rosetti Marino's Ravenna yard in December 2018 with fabrication of
the primary structural steel and nodes as well as the rolling of
the tubulars underway and progressing to plan. Detailed engineering
and procurement of the trees, wellheads and subsea pipeline has
also started. At Easington, Centrica's onshore receiving terminal,
preparation for modifications required for Tolmount gas import has
started and significant purchase orders are being placed for
engineering work-scopes. The four well development drilling
programme is scheduled to commence mid-2020 with the first well
expected to come on-stream in the fourth quarter of that year.
Premier continues to estimate that its share of the capex to
develop Tolmount Main will be around US$120 million, comprising
project management and development drilling costs, with the
infrastructure joint venture between Kellas Midstream and Dana
Petroleum funding the platform, pipeline and the terminal
modifications.
Exploration and appraisal
Premier has contracted the Ensco 123 rig to drill the Tolmount
East appraisal well in July ahead of drilling the Tolmount Main
development wells in 2020. The well is targeting 220 Bcf to 300 Bcf
(P50 to P10) of gross unrisked resource in an area to the east of
the main Tolmount field which sits above the Tolmount Main gas
water contact. On success, the Tolmount East appraisal well will be
suspended for use as a future producer to be tied back to the HGS
infrastructure. A 3D seismic survey across the Greater Tolmount
Area is scheduled to commence later this month. The survey will be
used to help optimise development drilling at Tolmount Main as well
as the location of a potential Tolmount Far East exploration well,
in addition to defining further prospectivity in the area.
Portfolio management
During 2018 Premier continued its programme of non-core asset
disposals from the E.ON portfolio with the sale of its 30 per cent
interest in the Esmond Transportation System (ETS) to Kellas
Management Ltd for total cash proceeds of US$22.9 million (after
working capital adjustments). Premier also completed the sale of
its interests in the Babbage Area to Verus Petroleum SNS Ltd
(Verus) in December 2018 receiving cash proceeds of US$38.7
million, after adjustments for Babbage cash flows collected since
the effective date of 1 January 2018. The sale proceeds from both
transactions were used to pay down the Company's debt.
VIETNAM
The Vietnam business unit continued to generate material free
cash flow for the Group during 2018. This was driven by a strong
production performance, underpinned by a better than forecast
subsurface performance and sustained high operating efficiency,
combined with a continued low operating cost base. On the back of
this outperformance, Premier again increased its total recoverable
reserves estimate to over 120 mmboe.
Production
Production from Block 12W (Premier 53.13 per cent operated
interest), which contains the Chim Sáo and Dua fields, averaged
15.2 kboepd (net), up on the prior corresponding period and above
budget. This strong performance was driven by high operating
efficiency of the Chim Sáo FPSO and successful ongoing well
intervention programmes which offset natural decline from
established reservoir horizons.
The Chim Sáo and Dua fields continued to produce with a high
operating efficiency of over 90 per cent during 2018 with
maintenance programmes completed on schedule. Production from the
fields was also boosted by four well intervention campaigns, which
perforated new zones in the shallower reservoir sections of
existing production wells and resulted in an additional 1 kboepd
(net) of production during 2018. The two Chim Sáo infill wells,
drilled and completed in December 2017, have also continued to
perform strongly contributing over 1 million barrels of net oil
production since coming online. As a result of this strong
subsurface performance, Premier again increased its reserves
estimates of Chim Sáo by 5 mmboe (net) at year end 2018.
Operating costs from Block 12W have remained low at US$5/boe
while the lease cost of the FPSO averaged US$6/boe as Premier
continues to maintain tight control of its cost base in Vietnam.
Premier also continued to sell its Chim Sáo crude at a premium to
Brent during 2018.
INDONESIA
The Premier-operated Natuna Sea Block A (NSBA) fields delivered
a robust performance in 2018, underpinned by an increased market
share within GSA1. This, together with continued low operating
costs, led to the Indonesian business generating US$110 million of
net cash flows for the Group.
Production and development
Production from Indonesia in 2018 averaged 13.2 kboepd (net)
with the Natuna Sea Block A fields (Premier 28.67 per cent operated
interest) delivering 12.9 kboepd (net) and the Kakap field (Premier
18.75 non-operated interest), now sold, averaging 0.3 kboepd
(net).
Gas supply by contract
(BBtud, gross) GSA1 GSA2
---------- ----------
2018 2017 2018 2017
----------------------- ---- ---- ---- ----
Anoa, Pelikan 153 143 - -
----------------------- ---- ---- ---- ----
Gajah Baru, Naga - - 80 91
----------------------- ---- ---- ---- ----
Kakap 4 17 - -
----------------------- ---- ---- ---- ----
Total 157 160 80 91
----------------------- ---- ---- ---- ----
Premier sold an average of 233 BBtud (gross) (2017: 234 BBtud)
from its operated Natuna Sea Block A fields during 2018.
Singapore demand for gas sold under GSA1 remained robust,
averaging 292 BBtud (2017: 286 BBtud). Premier's Anoa and Pelikan
fields delivered 153 BBtud (gross) (2017: 143 BBtud), capturing
52.4 per cent (2017: 49.6 per cent) of GSA1 deliveries, above
Natuna Sea Block A's contractual share of 51.7 per cent. Gajah Baru
and Naga delivered production of 80 BBtud (gross) (2017: 91 BBtud)
under GSA2, representing 100 per cent nomination delivery by
Premier. Gross liquids production from the Anoa field was 1.2 kbopd
(2017: 1.1 kbopd).
Gas sales from the Kakap field averaged 4 BBtud (gross) (2017:
17 BBtud (gross)) while gross liquids production was 0.7 kbopd
(2017: 2.6 kbopd). The reduction on the prior corresponding period
reflects the sale of Kakap to Batavia Oil which completed in
April.
Premier continues to benefit from a low cost base in Indonesia
with operating costs averaging US$6.7/boe for the period.
Development
The development of the Bison, Iguana, Gajah-Pueri (BIG-P) gas
fields (Premier 28.67 per cent operated interest) involves a three
well subsea tie-back to existing infrastructure and is progressing
to budget and to schedule. The Naga and Pelikan deck extensions and
the Pelikan and AGX platform spools were successfully installed
offshore during the third quarter. Fabrication of the subsea
structures commenced in October and will be installed offshore
along with the flowlines, flexible risers and umbilicals in
mid-2019. A DSV will then complete the final hook up and tie-ins
during the second half of the year. Drilling of the three BIG-P
development wells is on track to commence in the first half of 2019
with first gas planned for late 2019. Once on-stream, the BIG-P gas
fields will support the Group's long term gas contracts into
Singapore and will help to maintain production from Natuna Sea
Block A.
Exploration and appraisal
In January, Premier was awarded a 40 per cent operated interest
in the Andaman II licence in the underexplored but proven North
Sumatra basin offshore Aceh in the 2017 Indonesian Licence Round.
PGS has commenced a 3D seismic acquisition programme designed to
mature the numerous prospects and leads identified on existing 2D
seismic, many of which exhibit direct hydrocarbon indicators.
Drilling is targeted for late 2020. The licence has the potential
to deliver significant gas volumes into North Sumatra and adds a
potentially material new gas play to Premier's Indonesian
portfolio.
On Natuna Sea Block A, Premier's exploration team is
reprocessing existing Anoa 3D datasets and analysing production
data from the WL-5X well to assess the ultimate potential of the
Lama play beneath the Anoa field and to identify potential infill
drilling locations within the Anoa main field.
Elsewhere in Indonesia, Premier and its joint venture partners
continue to seek a farm in offer to the Tuna PSC (Premier 65 per
cent operated interest) ahead of a two well campaign to appraise
the Tuna field.
THE FALKLAND ISLANDS
During 2018, the focus has been on securing LOIs (Letters of
Intent) with key contractors and progressing the financing
structure for the first phase of the development of the Sea Lion
field in the North Falklands Basin ahead of a final investment
decision.
The Sea Lion project represents a material opportunity for the
Group with around 400 mmboe (net to Premier) to be developed over
several phases. Sea Lion Phase 1 (Premier 60 per cent operated
interest) will develop over 220 mmbbls of gross resources in PL032,
using a conventional FPSO based scheme, similar to Premier's
successful Catcher development.
During 2018, Premier completed the selection of its key
contractors and put in place LOIs for the provision of key
services, including an FPSO, the drilling rig, well services, SURF,
subsea production systems and installation services, as well as
vendor financing. Premier is now working with its selected
contractors to complete FEED and to convert the LOIs into fully
termed contracts.
Premier has also continued to progress discussions with senior
debt providers, including export credit finance agencies, around
the funding structure of the project. In particular, Premier is
preparing to submit an application for project funding once FEED
has been completed, scheduled for the second quarter of 2019. In
addition, it remains the Group's preference to optimise its level
of participation in the project by bringing in an additional equity
partner once the funding structure has been finalised.
PAKISTAN
Premier's Pakistan business continued to generate positive net
cash flows for the Group, supported by high operating efficiency of
over 95 per cent and a low cost base.
Production from Premier's six non-operated producing gas fields
in Pakistan averaged 5.3 kboepd (2017: 6.2 kboepd) during 2018. The
fall in production reflects natural decline in the main gas fields
partially offset by better than expected results achieved from the
new Kadanwari development wells brought onstream. Premier realised
an average price of US$3.4/mscf for its Pakistani gas during the
period while operating costs remained low at US$0.9/mscf
(US$4.9/boe).
In April 2017, Premier announced the sale of its Pakistan
business to Al-Haj Group for US$65.6 million. To date, Premier has
received US$40 million of deposits from the buyer and also
collected US$25 million in cash flows since the economic date of
the transaction (1 January 2017). Premier expects the sale to
complete on settlement of final working capital adjustments, which
is scheduled for the end of the first quarter of 2019.
EXPLORATION AND APPRAISAL
In recent years, Premier has sought to rebalance its exploration
portfolio away from traditional but now mature areas to
under-explored but proven hydrocarbon basins with the potential to
develop into new business units over the medium term.
MEXICO
In Mexico, pre-unitisation terms were agreed by all potential
partners in the Zama field and approved by the Mexican government
in September. The pre-unitisation agreement provides a framework to
enable the sharing of data to ensure the safe and optimal appraisal
of the Zama field and, in the event a shared reservoir is proven,
it establishes a defined process for the overall development of the
field and the initial participation of each party.
In September, the Mexican government approved the Block 7
(Premier 25 per cent non-operated interest) appraisal programme,
comprising two back-to-back wells and one side track. The first
appraisal well, Zama-2, spudded to the north of the Zama discovery
well at the end of November. The well penetrated 152 metres of net
pay above the oil water contact and encountered a better than
anticipated net to gross ratio. The rig subsequently spudded the
up-dip vertical Zama-2 well side-track and has encountered the main
reservoir on prognosis. A comprehensive coring programme is now
being undertaken ahead of a drill stem test with the results
expected in early April. The rig will then move to drill the second
appraisal well (Zama-3) to evaluate the southern part of the Zama
oil field. The results of the appraisal programme will feed into
the early engineering work, being undertaken by McDermott and IO,
and will help inform the concept select decision ahead of a final
investment decision which is targeted for 2020.
In March 2018, Premier was awarded three new licences in Round
3.1, significantly enhancing the Group's acreage position offshore
Mexico. Premier, together with its joint venture partners (DEA
(operator) and Sapura), secured the highly contested Block 30
(Premier 30 per cent non-operated interest) which is directly to
the south west of Premier's Zama discovery in the shallow water
Sureste Basin. A block wide 3D seismic acquisition programme is
scheduled to commence in June 2019. The programme will further
define potential exploration targets, including the high impact
Wahoo prospect, which exhibits a flat spot on 2D seismic analogous
to the Zama discovery, and the Cabrilla prospect ahead of a
drilling campaign in 2020.
Premier also secured a 100 per cent operated interest in two
blocks - Blocks 11 and 13 - in the more frontier Burgos Basin,
which is directly inboard from the deep water Perdido fold belt. An
environmental baseline study across the two blocks was completed in
2018 and the forward plan is to reprocess existing 3D seismic
during 2019 with the aim of identifying potential drilling
targets.
On Block 2 (Premier 10 per cent non-operated interest) in the
Sureste Basin, Premier's option to participate and convert its
carried 10 per cent interest to a paying interest of up to 25 per
cent equity or to withdraw was triggered in May 2018. Premier has
opted to exit and received final government approval for its
withdrawal from the block in February 2019.
BRAZIL
Premier has continued to take an operational lead for
environmental licensing and well planning in the offshore Ceará
Basin, where the Group plans to drill two wells in 2020.
In the first quarter of 2018 Premier secured approval from the
ANP to replace the two well commitment on its operated Block 717
(Premier 50 per cent operated interest) with a single deeper well
targeting the stacked Berimbau and Maraca prospects. Premier
intends to drill this well in the first half of 2020 as part of a
two well campaign with Block 661 (Premier 30 per cent non-operated
interest). The 661 well will test the Itarema and Tatajuba
prospects. The two wells combined will test in excess of 500 mmbbls
of gross prospective resource.
Having matured and evaluated the prospectivity on Block 665
(Premier 50 per cent operated interest) utilising the high quality
3D seismic acquired by Premier and its partner, the decision has
been taken to relinquish the licence at the end of the initial term
in July 2019.
FINANCIAL REVIEW
Overview
2018 saw continuing oil price volatility. Brent crude opened the
year at US$66.9/bbl, rising to US$86.2/bbl in October before then
weakening considerably towards the end of the year to close at
US$50.2/bbl at 31 December 2018, which was the lowest observed
price in 2018. The average for 2018 was US$71.4/bbl against
US$54.2/bbl for 2017. Subsequent to the year-end, prices have
strengthened and averaged US$62/bbl in January and February
2019.
Against this economic backdrop we have achieved our best ever
full year of production, averaging 80.5 kboepd (2017: 75.0 kboepd),
resulting in total revenue from all operations of US$1,438.3
million compared with US$1,102 million in 2017. In addition, we
have reduced Net Debt to US$2,330.7 million, following the
successful conversion of the Group's convertible bond notes during
the year and strong cash flow generation.
Business performance
EBITDAX for the year from continuing operations was US$882.3
million compared to US$589.7 million for 2017. The increase in
EBITDAX is mainly due to higher production and realised prices
during the year.
Business Performance (continuing operations) 2018 2017
$ million $ million
Operating profit 531.0 33.8
----------- -----------
Add: Depreciation, depletion, amortisation and impairment 358.4 667.8
----------- -----------
Add: Exploration expense and pre-licence costs 35.2 17.1
----------- -----------
Less: Gain on disposal of assets (42.3) (129.0)
----------- -----------
EBITDAX 882.3 589.7
----------- -----------
Income statement
Production and commodity prices
Group production on a working interest basis averaged 80.5
kboepd compared to 75.0 kboepd in 2017. This was driven by a full
year of production from the Catcher field which achieved first oil
in December 2017 and outperformance from the Chim Sáo field.
Average entitlement production for the period was 73.8 kboepd
(2017: 69.2 kboepd).
Premier realised an average oil price for the year of
US$67.9/bbl (2017: US$52.9/bbl). Including the effect of oil swaps
which settled during 2018, the realised oil price was US$63.5/bbl
(2017: US$52.1/bbl). In the UK, average natural gas prices achieved
were 57 pence/therm (2017: 47 pence/therm), which included 58.2
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$11.2/mscf (2017: US$8.4/mscf).
Realised prices 2018 2017
Oil price (US$/bbl) post hedging 63.5 52.1
---- ----
UK natural gas (pence/therm) 57 47
---- ----
Singapore HSFO (US$/mscf) 11.2 8.4
---- ----
Total revenue from all operations (including Pakistan) increased
to US$1,438.3 million (2017: US$1,102 million). From continuing
operations (excluding Pakistan), sales revenue increased to
US$1,397.5 million from US$1,043.1 million for the prior year.
Cost of operations
Cost of operations comprises operating costs, changes in lifting
positions, inventory movements and royalties. Cost of operations
for the Group from continuing operations was US$500.0 million for
2018, compared to US$455.4 million for 2017.
Operating Costs 2018 2017
$ million $ million
Continuing operations 487.5 438.4
----------- -----------
Discontinuing operations (Pakistan) 9.5 9.6
----------- -----------
Operating costs 497.0 448.0
----------- -----------
Operating costs per barrel 16.9 16.4
----------- -----------
Amortisation and depreciation of oil and gas properties 2018 2017
$ million $ million
Continuing operations 386.5 409.0
----------- -----------
Discontinuing operations (Pakistan) - 7.2
----------- -----------
Total 386.5 416.2
----------- -----------
Depreciation, depletion and amortisation ('DD&A') per barrel 13.2 15.2
----------- -----------
The increase in absolute operating costs reflects a full year
production contribution 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. Full year 2018 total operating costs
were below the low end of US$17-US$18/boe guidance at US$16.9/boe
(2017: US$16.4/bbl). The DD&A charge has reduced to US$13.2/bbl
(2017: US$15.2/bbl).
Impairment of oil and gas properties
A non-cash net impairment reversal credit of US$35.2 million
(pre-tax) (US$25.0 million post-tax) has been recognised in the
income statement. This relates to the Solan field in the UK North
Sea as a result of a reduction in the expected gross
decommissioning cost attributable to the asset, giving rise to a
reversal of previously recognised impairment of US$55.7 million.
This reversal has been partially offset by an impairment charge of
US$20.5 million for the Huntington asset. After recognition of the
net impairment charge there is US$2,245.6 million capitalised in
relation to PP&E assets and US$240.8 million for goodwill.
Exploration expenditure and pre-licence costs
Exploration expense and pre-licence expenditure costs amounted
to US$35.2 million (2017: US$17.1 million), primarily relating to
historical costs incurred on the Block 2 licence in Mexico, the
Sunbeam prospect in the UK and Block 665 licence in Brazil. After
recognition of these expenditures, the exploration and evaluation
assets remaining on the balance sheet at 31 December 2018 amount to
US$812.6 million, principally for the Sea Lion asset and our share
of the Zama prospect and Block 30 in Mexico. US$224.5 million of
costs in relation to the Tolmount project previously recognised
within exploration assets, which mostly represents fair value
allocated to the project on acquisition from E.ON, have been
reclassified to PP&E in the year following sanction of the
project in 2018.
General and administrative expenses
Net G&A costs of US$14.0 million (2017: US$16.8 million)
were comparable with the prior year.
Finance gains and charges
Net finance gains and charges of US$372.8 million, have
increased compared to the prior year (US$316.4 million). The step
up in the interest margin on our financing facilities following the
completion of the refinancing in July 2017 has been partially
offset by a reduction in the fair value of the Group's outstanding
equity and synthetic warrants to US$31.8 million from US$59.8
million at 31 December 2017. Cash interest expense in the period
was US$228.7 million (2017: US$223.7 million).
Taxation
The Group's total tax charge for 2018 from continuing operations
is US$53.1 million (2017: credit of US$96.1 million) which
comprises a current tax charge for the period of US$90.6 million
and a non-cash deferred tax credit for the period of US$37.5
million.
The total tax charge represents an effective tax rate of 33.5
per cent (2017: 26.2 per cent). The effective tax rate for the year
is primarily impacted by three specific UK deferred tax items. The
first is the impact of ring fence expenditure supplement claims in
the UK during the year (US$76.6 million credit). The second is the
impact of the Babbage disposal resulting in a clawback of UK tax
allowances (US$30.4 million charge) and the third is foreign
exchange movements on historical deferred tax balances (US$17.8
million charge). After adjusting for the net impact of the above
items of US$28.4 million, the underlying Group tax charge for the
period is US$81.5 million and an effective tax rate of 51.5 per
cent.
The Group has a net deferred tax asset of US$1,294.6 million at
31 December 2018 (2017: US$1,297.5 million), which is broadly
comparable with the prior year.
Profit after tax
Profit after tax is US$133.4 million (2017: loss of US$253.8
million) resulting in a basic earnings per share of 17.3 cents from
continuing and discontinued operations (2017: loss of 49.4 cents).
The profit after tax in the year is driven principally by the
increased sales revenue and consequent impact on operating
profits.
Cash flows
Cash flow from operating activities was US$777.2 million (2017:
US$475.3 million) after accounting for tax payments of US$128.8
million (2017: US$69.6 million) and before the movement in joint
venture cash balances in the period of US$54.4 million. The
increase in operating cash flows was largely driven by higher
production, sales volumes and realised prices.
Capital expenditure in 2018 totalled US$279.8 million (2017:
US$275.6 million).
Capital expenditure 2018 2017
$ million $ million
Fields/development projects 234.3 236.8
----------- -----------
Exploration and evaluation 43.6 37.6
----------- -----------
Other 1.9 1.2
----------- -----------
Total 279.8 275.6
----------- -----------
The principal development project was the Catcher field in the
UK. The majority of exploration spend was related to the
commencement of the appraisal drilling programme on the Zama
prospect in Mexico and the licence payment on Block 30. In
addition, cash expenditure for decommissioning activity in the
period was US$72.7 million (2017: US$25.7 million). Further to
this, US$17.7 million (2017: US$16.7 million) of cash was placed
into long-term abandonment escrow accounts for future
decommissioning activities.
Total 2019 development and exploration capex is expected to be
US$290 million of which c. US$70 million relates to the BIG-P
development and c. US$100 million to exploration and appraisal
(including US$60 million for the Zama appraisal programme and US$20
million for the Tolmount East appraisal well). Abandonment spend in
2019 is expected to be US$50 million, before taking into account
the benefits of tax relief, and primarily relates to abandonment
activities in the UK North Sea.
Discontinued operations, disposals and assets held for sale
During the year, Premier completed the previously announced
sales of its interests in the Babbage field in the UK, the Kakap
field in Indonesia and its 30 per cent non-operated interest in the
Esmond Transportation System (ETS). A net gain on disposal of
US$42.3 million has been recognised in the period.
During 2018, Premier received a further US$10 million cash
deposit from Al-Haj, in addition to the US$25 million deposit
received in 2017. Due to the expectation of the completion of the
disposal, the business unit continued to be classified as a
disposal group held for sale and presented separately in the
current and prior year balance sheet. Results for the disposal
group in both the current and prior periods have been presented as
a discontinued operation. Subsequent to the year-end, Premier
received a further US$5 million deposit from Al-Haj, bringing total
cash received to date of US$40 million, against the headline
consideration of US$65.6 million.
Balance sheet position
Net debt
Net debt at 31 December 2018 amounted to US$2,330.7 million (31
December 2017: US$2,724.2 million), with cash resources of US$244.6
million (31 December 2017: US$365.4 million). The maturity of all
of Premier's facilities at year-end is May 2021.
Following completion of the Wytch Farm disposal in December
2017, net cash proceeds received of US$176 million were used to pay
down and cancel the equivalent value of the RCF debt facility in
January 2018. Furthermore, the total available RCF facility was
reduced by a further US$39 million in December 2018 by the cash
proceeds received from the Babbage disposal. Following these two
disposals, the total available RCF facility reduced from US$2,050
million to US$1,835 million at year-end.
In January 2018, Premier invited convertible bondholders to
exercise their exchange rights in respect of any and all of their
bonds. 87.5 per cent or US$205.8 million of the US$235.2 million
bonds outstanding were accepted for early exchange with an
incentive amount of US$50 per US$1,000 in principal of bonds. The
exchange resulted in the issue of 231,882,091 Ordinary Shares,
which included 7,578,343 incentive shares. Completion of this
offer, resulted in a remaining convertible bond liability of
US$28.8 million.
Following this, in July 2018, the Group announced its intention
to exercise the mandatory conversion option in the remaining
outstanding convertible bonds. The exercise of this option
converted all of the remaining US$28.8 million outstanding
convertible bonds into approximately 31.4 million new Ordinary
Shares of Premier. This resulted in Premier's convertible bond
liability being fully extinguished in September 2018.
At 31 December 2018, after the exclusion of US$30.2 million of
cash held on behalf of our JV partners, Premier retained cash of
US$214.4 million. Combined with undrawn facilities of US$355.2
million, the Group had liquidity of US$569.6 million at the
year-end (31 December 2017: US$541.2 million). Subsequent to the
year-end, in January 2019, a further US$100.3 million of the
Group's RCF debt facility was cancelled by Premier, which will
result in reduced commitment fee costs for the Group in 2019.
Provisions
The Group's decommissioning provision decreased to US$1,214.5
million at 31 December 2018, down from US$1,432.1 million at the
end of 2017. The reduction is driven by a reduction in the forecast
for the gross cost estimate for the Solan asset and expenditure in
the year.
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, Operating cost per barrel, DD&A
per barrel, Net Debt and Liquidity and are defined in the
glossary.
Financial risk management
Commodity prices
Premier took advantage of the improved oil price environment
observed at times during 2018 to increase its hedging position in
2019 and 2020 to protect future free cash flows and covenant
compliance. The Group's current hedge position to the end of 31
December 2019 is as follows:
Oil swaps/forwards 2019 1H 2019 2H
Volume (mmbbls) 3.77 3.84
------- -------
Average price 68.5 69.2
------- -------
The fair value of open oil swaps at 31 December 2018 was an
asset of US$102.0 million (2017: liability of US$31.7 million),
which is expected to be released to the income statement during
2019 as the related barrels are lifted. During 2018, forward oil
swaps of 5.9 mmbbls expired resulting in a net charge of US$71.2
million (2017: US$11.4 million) which has been included in sales
revenue for the year.
In addition, the Group currently has forward UK gas sales of
48.8 mm therms at an average price of 61 pence/therm that will be
physically settled during 2019. Furthermore, Premier has hedged
part of its Indonesian gas production through the sale of 330,000
MT of HSFO Sing 180 in 2019 and 2020 at an average price of
US$378/MT.
Foreign exchange
Premier's functional and reporting currency is US dollars.
Exchange rate exposures relate only to local currency receipts, and
expenditures within individual business units. Local currency needs
are acquired on a short-term basis. At the year-end, the Group
recorded a mark-to-market loss of US$17.2 million on its
outstanding foreign exchange contracts (2017: gain of US$32.5
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.
Interest rates
The Group has various financing instruments including senior
loan notes, convertible bonds, UK retail bonds, term loans and
revolving credit facilities. Currently, approximately 60 per cent
of total borrowings are fixed or have been fixed using interest
rate options. On average, the cost of drawn funds for the year was
7.6 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
2018, US$1.4 million of cash proceeds were received (net to
Premier) in relation to settled insurance claims (2017: US$7.2
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 assumes an oil price of
US$60/bbl and US$65/bbl in 2019 and 2020, respectively and
production in line with prevailing rates. The Group has run
downside scenarios, where oil and gas prices are reduced by a flat
US$5/bbl throughout the going concern period and where total group
production is forecast to reduce by 10 per cent.
At 31 December 2018 the Group continued to have significant
headroom on its financing facilities and cash on hand. The base
case forecasts show that the Group will have sufficient financial
headroom for the 12 months from the date of approval of the 2018
Annual Report and Accounts. In the downside scenarios ran, no
covenant breach is forecasted in the going concern period. If more
severe sustained downside cases were to materialise then, in the
absence of any mitigating actions, a breach of one or more of the
financial covenants may arise during the 12 month going concern
assessment period. Potential mitigating actions could include
further non-core asset disposals, additional hedging activity or
deferral of expenditure.
Accordingly, after making enquiries and considering the risks
described above, the Directors have a reasonable expectation that
the Company has adequate resources to continue in operational
existence for the foreseeable future. Accordingly, the Directors
continue to adopt the going concern basis of accounting in
preparing these consolidated financial statements.
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:
-- Further oil price weakness and volatility.
-- Underperformance of Catcher asset.
-- Failure to maintain schedule of Tolmount project.
-- Negative drilling results from key appraisal assets.
-- Ability to fund existing and planned growth projects.
-- Breach of banking covenants if oil prices fall or assets
underperform.
-- Timing and uncertainty of decommissioning liabilities.
-- Continued ability to maintain core competencies.
-- Political and security instability in countries of current
and planned activity.
-- Rising costs if oil prices recover could limit access to
services.
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 2018
2018 2017
$ million $ million
---------------------------------------------
Continuing operations
Sales revenues 1,397.5 1,043.1
Other operating (costs)/income (1.2) 18.8
Costs of operation (500.0) (455.4)
Depreciation, depletion, amortisation
and impairment (358.4) (667.8)
Exploration expense and pre-licence costs (35.2) (17.1)
Profit on disposal of non-current assets 42.3 129.0
General and administration costs (14.0) (16.8)
------------ ------------
Operating profit 531.0 33.8
Interest revenue, finance and other gains 27.8 12.6
Finance costs, other finance expenses
and losses (400.6) (329.0)
Loss on substantial modification - (83.7)
Profit/(loss) before tax from continuing
operations 158.2 (366.3)
Tax (charge)/credit (53.1) 96.1
------------ ------------
Profit/(loss) for the year from continuing
operations 105.1 (270.2)
------------ ------------
Discontinued operations
Profit for the year from discontinued
operations 28.3 16.4
------------ ------------
Profit/(loss) after tax 133.4 (253.8)
------------ ------------
Earnings/(loss) per share (cents):
From continuing operations
Basic 13.6 (52.6)
Diluted 12.2 (52.6)
------------ ------------
From continuing and discontinued operations
Basic 17.3 (49.4)
Diluted 15.5 (49.4)
------------ ------------
Consolidated Statement of Comprehensive Income
For the year ended 31 December 2018
2018 2017
$ million $ million
--------------------------------------------------- ------------
Profit/(loss) for the year 133.4 (253.8)
--------------------------------------------------- ------------ ------------
Cash flow hedges on commodity swaps:
Gains/(losses) arising during the year 85.7 (25.6)
Add: reclassification adjustments for
losses in the year 71.2 11.4
------------ ------------
156.9 (14.2)
Cash flow hedges on interest rate and
foreign exchange swaps:
Gains/(losses) arising during the year 21.5 (33.9)
Less: reclassification adjustments for
(gains)/losses in the
year (11.4) 23.1
------------ ------------
10.1 (10.8)
Tax relating to components of other comprehensive
income (33.8) 7.5
Exchange differences on translation of
foreign operations 7.4 (4.9)
Other comprehensive income/(expense) 140.6 (22.4)
Total comprehensive income/(expense)
for the year 274.0 (276.2)
------------ ------------
All comprehensive income is attributable to the equity holders
of the parent.
Consolidated Balance Sheet
As at 31 December 2018
2018 2017
$ million $ million
---------------------------------------
Non-current assets:
Intangible exploration and evaluation
assets 812.6 1,061.9
Property, plant and equipment 2,245.6 2,381.0
Goodwill 240.8 240.8
Long-term receivables 159.8 160.8
Deferred tax assets 1,434.1 1,461.5
------------ ------------
4,892.9 5,306.0
------------ ------------
Current assets:
Inventories 12.5 13.5
Trade and other receivables 282.3 340.6
Derivative financial instruments 127.4 14.5
Cash and cash equivalents 244.6 365.4
Assets held for sale 55.2 96.6
------------ ------------
722.0 830.6
------------ ------------
Total assets 5,614.9 6,136.6
------------ ------------
Current liabilities:
Trade and other payables (375.6) (572.9)
Short-term provisions (46.0) (91.2)
Derivative financial instruments (41.4) (99.8)
Deferred income (11.0) (13.1)
Liabilities directly associated with
assets held for sale (21.9) (46.6)
------------ ------------
(495.9) (823.6)
------------ ------------
Net current assets 226.1 7.0
------------ ------------
Non-current liabilities:
Long-term debt (2,552.0) (2,972.6)
Deferred tax liabilities (139.5) (164.0)
Deferred income (76.0) (80.3)
Derivative financial instruments (129.4) (108.3)
Long-term provisions (1,196.1) (1,370.9)
------------ ------------
(4,093.0) (4,696.1)
------------ ------------
Total liabilities (4,588.9) (5,519.7)
------------ ------------
Net assets 1,026.0 616.9
------------ ------------
Equity and reserves:
Share capital 154.2 109.0
Share premium account 491.7 284.5
Other reserves 380.1 223.4
------------ ------------
1,026.0 616.9
------------ ------------
Consolidated Statement of Changes in Equity
For the year ended 31 December 2018
Share premium
Share capital account Other reserves Total
$ million $ million $ million $ million
------------------------------
At 1 January 2017 106.7 275.4 427.0 809.1
Issue of Ordinary Shares 2.3 9.1 1.1 12.5
Purchase of ESOP Trust shares - - (0.2) (0.2)
Provision for share-based
payments - - 14.5 14.5
Incremental equity component
of revised convertible bonds - - 57.2 57.2
Loss for the year - - (253.8) (253.8)
Other comprehensive expense - - (22.4) (22.4)
------------------------------ ------------- ------------- -------------- ----------
At 31 December 2017 109.0 284.5 223.4 616.9
------------- ------------- -------------- ----------
Adjustment on adoption of
IFRS 9(1) - - (82.0) (82.0)
------------- ------------- -------------- ----------
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 31 December 2018 154.2 491.7 380.1 1,026.0
------------- ------------- -------------- ----------
(1) As described in note 1.
Consolidated Cash Flow Statement
For the year ended 31 December 2018
2018 2017
$ million $ million
-------------------------------------------------------------------------------------------------------------------------------------------
Net cash from operating activities 722.8 496.0
----------- -----------
Investing activities:
Capital expenditure (279.8) (275.6)
Decommissioning pre-funding (17.8) (16.7)
Decommissioning expenditure (72.7) (25.7)
Proceeds from disposal of oil and gas properties 73.4 202.3
Net cash used in investing activities (296.9) (115.7)
Financing activities:
Issuance of Ordinary shares 13.8 0.8
Net purchase of ESOP Trust shares (1.5) (0.2)
Proceeds from drawdown of long-term bank loans 105.0 45.0
Repayment of long-term bank loans (415.3) -
Debt arrangement fees - (86.0)
Interest paid (228.7) (223.7)
----------- -----------
Net cash from financing activities (526.7) (264.1)
----------- -----------
Currency translation differences relating to cash and cash equivalents (20.0) (6.7)
----------- -----------
Net (decrease)/increase in cash and cash equivalents (120.8) 109.5
----------- -----------
Cash and cash equivalents at the beginning of the year 365.4 255.9
----------- -----------
Cash and cash equivalents at the end of the year 244.6 365.4
----------- -----------
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 31 December 2018
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 6 March 2019.
The financial information for the year ended 31 December 2018
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 2017 were
approved by the Board of Directors on 7 March 2018 and delivered to
the Registrar of Companies and those for 2018 will be delivered
following the Company's Annual General Meeting ('AGM'). The auditor
has reported on the 2018 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 2019.
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 2017, as described in
those annual financial statements, except for the adoption of IFRS
9 Financial Instruments and IFRS 15 Revenue from Contracts with
Customers.
IFRS 9 'Financial Instruments'
The overall impact on transition to IFRS 9 was an US$82 million
increase in long-term debt and corresponding reduction in net
assets. This adjustment relates entirely to an adjustment to the
Group's accounting for its refinancing that completed in July 2017.
On adoption of IFRS 9, additional interest charges for facilities
that were not deemed to be substantially modified have been
expensed at the point of completion of the refinancing. Under the
previous accounting policies these additional interest charges had
been expected to be amortised to the income statement on an
effective interest rate basis over the life of the facilities.
Under IFRS 9, this would have increased the interest charge
recognised in 2017 by US$82 million, with a corresponding reduction
in net assets at 31 December 2017. Going forward, this reduces
Premier's forecast interest charges by c. US$20 million per annum.
The impact on the current period balance sheet is to increase
long-term debt and reduce retained earnings by US$82 million. As
permitted by IFRS 9 comparatives have not been restated.
For certain line items in the balance sheet the closing balance
at 31 December 2017 as previously reported and the opening balance
at 1 January 2018 therefore differ (see statement of changes in
equity). The Group's accounting policy has been revised to reflect
the requirements of IFRS 9. However, excluding the impact on the
accounting treatment applied to the Group's 2017 refinancing, the
Standard has not had a significant impact. The Group's accounting
policy for IFRS 9 is set out below:
(a) Classification of financial assets and financial
liabilities
IFRS 9 requires the use of two criteria to determine the
classification of financial assets: the entity's business model for
the financial assets and the contractual cash flow characteristics
of the financial assets. The Standard goes on to identify three
categories of financial assets - amortised cost; fair value through
profit or loss (FVTPL); and fair value through other comprehensive
income (FVOCI). The accounting for the Group's financial
liabilities remains largely the same as it was under IAS 39.
Similar to the requirements of IAS 39, IFRS 9 requires contingent
consideration liabilities to be treated as financial instruments
measured at fair value, with the changes in fair value recognised
in the statement of profit or loss.
Under IFRS 9, embedded derivatives are no longer separated from
a host financial asset. Instead, financial assets are classified
based on their contractual terms and the Group's business model.
The accounting for derivatives embedded in financial liabilities
and in non-financial host contracts has not changed from that
required by IAS 39.
(b) Impairment
IFRS 9 mandates the use of an expected credit loss model to
calculate impairment losses rather than an incurred loss model, and
therefore it is not necessary for a credit event to have occurred
before credit losses are recognised. The new impairment model
applies to the Group's financial assets and loan commitments. No
changes to the impairment provisions were made on transition to
IFRS 9.
The IFRS 9 impairment model requiring the recognition of
'expected credit losses', in contrast to the requirement to
recognise 'incurred credit losses' under IAS 39, has not had a
material impact on the Group's financial statements.
Trade receivables are generally settled on a short time frame
and the Group's other financial assets are due from counterparties
without material credit risk concerns at the time of
transition.
(c) Hedge accounting
The hedge accounting requirements of IFRS 9 have been simplified
and are more closely aligned to an entity's risk management
strategy. Under IFRS 9 all existing hedging relationships will
qualify as continuing hedging relationships and the Group also
intends to apply hedge accounting prospectively to certain of its
commodity price risk management activities for which hedge
accounting was not possible under IAS 39. This had no impact on the
2018 opening balance sheet.
IFRS 15 'Revenue from Contracts with Customers'
Premier has elected to apply the 'modified retrospective'
approach to transition permitted by IFRS 15 under which comparative
financial information is not restated. The Standard did not have a
material effect on the Group's financial statements as at 1 January
2018 and so no transition adjustment has been made. The standard
has not had a material impact on the Group's accounting policy in
respect to revenue as previously disclosed in the 2017 financial
statements.
Revenue from contracts with customers for the 2018 period is
presented in Note 2. Amounts presented for comparative periods in
2017 include revenues determined in accordance with the Group's
previous accounting policies relating to revenue. The total amounts
presented do not, therefore, represent the revenue from contracts
with customers that would have been reported for those periods had
IFRS 15 been applied using a fully retrospective approach to
transition but the differences are not material.
The Group's accounting policy for IFRS 15 is set out below:
Under IFRS 15, revenue from contracts with customers is
recognized when or as the Group satisfies a performance obligation
by transferring a promised good or service to a customer. A good or
service is transferred when the customer obtains control of that
good or service. The transfer of control of oil, natural gas,
natural gas liquids, and other items sold by the Group usually
coincides with title passing to the customer and the customer
taking physical possession. The Group principally satisfies its
performance obligations at a point in time and the amounts of
revenue recognized relating to performance obligations satisfied
over time are not significant.
A number of additional new standards, amendments to existing
standards and interpretations were effective from 1 January 2018.
The adoption of these amendments did not have a material impact on
the Group's condensed financial statements for the year ended 31
December 2018.
There are also a number of amendments to accounting standards
and new interpretations issued by the International Accounting
Standards Board which will be applicable from 1 January 2019
onwards. These are not expected to have a material impact on the
accounting policies, methods of computation or presentation applied
by the Group, except for IFRS 16 Leases.
Further details on new International Financial Reporting
Standards adopted and yet to be adopted will be disclosed in the
2018 Annual Report and Accounts.
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.
2018 2017
$ million $ million
----------------------------------------------------
Revenue:
Indonesia 192.8 171.8
Vietnam 272.4 210.7
United Kingdom 931.5 655.9
Rest of the World(1) 0.8 4.7
Total Group sales revenue 1,397.5 1,043.1
Other operating income - United Kingdom - 18.8
Interest and other finance revenue 7.6 1.7
----------- -----------
Total Group revenue from continuing operations 1,405.1 1,063.6
----------- -----------
Group operating profit:
Indonesia 111.8 65.3
Vietnam 142.2 82.6
United Kingdom 326.2 (86.4)
Rest of the World(1) (29.6) (5.0)
Unallocated (2) (19.6) (22.7)
----------- -----------
Group operating profit 531.0 33.8
Interest revenue, finance and other gains 27.8 12.6
Finance costs and other finance expenses (400.6) (329.0)
Loss on substantial modification - (83.7)
----------- -----------
Profit/(loss) before tax from continuing operations 158.2 (366.3)
Tax (53.1) 96.1
----------- -----------
Profit/(loss) after tax from continuing operations 105.1 (270.2)
----------- -----------
Profit from discontinued operations 28.3 16.4
----------- -----------
2. Operating segments (continued)
2018 2017
$ million $ million
----------------------------------------------------
Balance sheet
Segment assets:
Falkland Islands 648.1 633.1
Indonesia 417.7 440.4
Vietnam 312.0 374.4
United Kingdom 3,706.1 4,116.2
Rest of the World 103.8 96.0
Assets held for sale 55.2 96.6
Unallocated(2) 372.0 379.9
Total assets 5,614.9 6,136.6
Liabilities:
Falkland Islands (12.8) (8.2)
Indonesia (174.0) (223.9)
Vietnam (174.1) (203.4)
United Kingdom (1,431.9) (1,802.1)
Rest of the World (51.4) (54.8)
Liabilities directly associated with assets held for sale (21.9) (46.6)
Unallocated(2) (2,722.8) (3,180.7)
----------- -----------
Total liabilities (4,588.9) (5,519.7)
----------- -----------
Other information
Capital additions and acquisitions:
Falkland Islands 15.1 12.9
Indonesia 24.5 7.4
Pakistan 4.1 10.5
Vietnam (0.1) 20.2
United Kingdom(4) (50.3) 444.3
Rest of the World(1) 37.2 25.3
----------- -----------
Total capital additions and acquisitions 30.5 520.6
----------- -----------
2. Operating segments (continued)
2018 2017
$ million $ million
------------------------------------------------------
Depreciation, depletion, amortisation and impairment:
Indonesia 46.6 57.2
Vietnam 55.6 64.5
United Kingdom 254.8 542.9
Rest of the World(1) 1.4 3.2
----------- -----------
Total DD&A and impairment (continuing operations) 358.4 667.8
----------- -----------
Total DD&A and impairment (discontinued operations) - 7.3
----------- -----------
1 Segmental income, assets, liabilities and capital additions
for Mauritania have been included within the Rest of the World.
2 Unallocated expenditure, assets and liabilities include
amounts of a corporate nature and not specifically attributable to
a geographical segment. These items include corporate general and
administration costs, pre-licence exploration costs, cash and cash
equivalents, mark-to market valuations of commodity contracts and
interest rate swaps and options, convertible bonds, warrants and
other long-term debt.
3 Depreciation, depletion and amortisation for the Pakistan
business unit was charged until 30 June 2017, which was the date of
reclassification of an asset held for sale.
4 Includes revisions to decommissioning estimates in the
year
Out of the total Group worldwide sales revenues of US$1,397.5
million (2017: US$1,043.1 million), revenues of US$931.5 million
(2017: US$655.9 million) arose from sales of oil and gas to
customers located in the UK. Included within the total revenues
were revenues of US$1,468.7 million (2017: US$1,054.4 million) from
contracts with customers. This was offset by hedging losses of
US$71.2 million (2017: US$11.3 million).
Included in assets arising from the United Kingdom segment are
non-current assets (excluding deferred tax assets) of US$2,090.5
million (2017: US$2,455.7 million) located in the UK. Included in
depreciation, depletion, amortisation and impairment is a net
impairment credit in relation to the UK of US$35.2 million (2017:
US$252.2 million net charge).
Revenue from three customers (2017: three customers) each
exceeded 10 per cent of the Group's consolidated revenue. Sales to
two customers in the UK amounted to US$454.7 million (2017: two
customers US$361.7 million). Sales to one customer in Indonesia
totalled US$186.5 million (2017: one customer amounting to US$168.3
million).
3. Cost of operation
2018 2017
$ million $ million
----------------------------------
Operating costs 487.5 438.4
Gas purchases 9.6 5.5
Stock overlift/underlift movement (11.1) 1.3
Royalties 14.0 10.2
500.0 455.4
4. Tax
2018 2017
$ million $ million
------------------------------------------------------------
Current tax:
UK corporation tax on profits (23.2) (0.8)
UK petroleum revenue tax - (8.2)
Overseas tax 120.7 75.6
Adjustments in respect of prior years (6.9) 8.2
----------- -----------
Total current tax 90.6 74.8
----------- -----------
Deferred tax:
UK corporation tax (13.5) (146.2)
Overseas tax (24.0) (24.7)
----------- -----------
Total deferred tax (37.5) (170.9)
----------- -----------
Tax charge/(credit) on profit/(loss) on ordinary activities 53.1 (96.1)
----------- -----------
The tax charge for the year can be reconciled to the profit per
the consolidated income statement as follows:
2018 2017
$ million $ million
--------------------------------------------------------------------------------------------
Group profit/(loss) on ordinary activities before tax 158.2 (366.3)
----------- -----------
Group profit/(loss) on ordinary activities before tax at 44.7% weighted average rate (2017:
29.1%) 70.8 (106.6)
Tax effects of:
Income/expenses that are not taxable/deductible in determining taxable profit (8.7) 40.6
Financing costs disallowed for UK supplementary charge 22.6 16.4
Non-deductible field expenditure 6.1 36.1
Tax and tax credits not related to profit before tax (mainly Ring Fenced Expenditure
Supplement) (46.1) (69.9)
Group relief 2.7 -
Unrecognised tax losses 14.8 6.1
Effect of change in foreign exchange 17.8 -
Adjustments in respect of prior years (31.2) (3.2)
Utilisation and recognition of tax losses not previously recognised - (0.8)
Effect of differences in tax rates (0.4) (0.5)
Recognition that decommissioning provision will unwind at 50% 4.7 (14.3)
Tax charge/(credit) for the year 53.1 (96.1)
Effective tax rate for the year 33.5% 26.2%
----------- -----------
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 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. Discontinued operations, disposals and assets held for
sale
2018 2017
$ million $ million
----------------------------------------------
Assets held for:
Pakistan Business Unit 55.2 52.2
Esmond Transportation System ('ETS') - 27.0
Kakap field - 17.4
---------- -----------
Total assets classified as held for sale 55.2 96.6
---------- -----------
Liabilities held for:
Pakistan Business Unit (21.9) (25.4)
Esmond Transportation System ('ETS') - (7.0)
Kakap field - (14.2)
---------- -----------
Total liabilities classified as held for sale (21.9) (46.6)
---------- -----------
Disposals
During the period, Premier completed the previously announced
sales of its interest in the Kakap field, its 30 per cent
non-operated interest in the Esmond Transportation System ('ETS')
and its interest in the Babbage Area. A net gain for these
disposals has been recognised in the income statement for the year.
The gain recognised has been partially offset by a charge of US$5.6
million due to a write-off of a contingent consideration receivable
from Kris Energy in relation to the Aceh disposal by Premier in
2014.
Discontinued operations - Pakistan Business Unit
In April 2017, Premier announced it had reached agreement and
signed an SPA with Al-Haj Energy Limited ('Al-Haj') for the sale of
Premier Oil Pakistan Holdings BV, which comprises Premier's
Pakistan Business Unit, for a cash consideration of US$65.6
million. During the year, Al-Haj paid a deposit to Premier of
US$10.0 million, on top of the US$25.0 million deposit received in
2017.
The disposal of the Pakistan Business Unit is expected to
complete in 2019 and, as this is within 12 months of the balance
sheet date, the business unit continued to be classified as a
disposal group held for sale in the year-end balance sheets.
The results of the disposal group which have been included as
discontinued operations in the consolidated income statement were
as follows:
2018 2017
$ million $ million
-------------------------------------------------------
Revenue 40.8 40.8
Expenses (15.0) (22.4)
----------- -----------
Profit before tax 25.8 18.4
----------- -----------
Attributable tax credit/(charge) 2.5 (2.0)
----------- -----------
Net profit for the period from discontinued operations 28.3 16.4
----------- -----------
During the year to 31 December 2018, the Pakistan disposal group
contributed US$29.0 million (2017 US$16.8 million) to the Group's
net operating cash flows and paid US$5.0 million (2017 US$6.8
million) in respect of investing activities). There were no
financing cash flows in either the current or the prior years.
The effect of the disposal group on segments results is
disclosed in note 2. The major classes of assets and liabilities
comprising the disposal group classified as held for sale are as
follows:
2018 2017
$ million $ million
-------------------------------------------------
Property, plant and equipment 27.6 23.3
Long-term receivables 0.2 0.4
Deferred tax asset 1.9 0.8
Inventory 8.2 9.0
Trade and other receivables 16.8 17.8
Cash 0.5 0.9
---------- ----------
Pakistan assets classified as held for sale 55.2 52.2
------------------------------------------------- ---------- ----------
Trade and other payables (5.2) (7.8)
Long-term provisions (16.7) (17.6)
---------- ----------
Pakistan liabilities classified as held for sale (21.9) (25.4)
---------- ----------
Net assets of disposal group 33.3 26.8
---------- ----------
Following completion of the disposal, Premier will retain a
provision of US$16.4 million for potential costs in relation to the
business unit for the period of ownership by Premier prior to the
disposal. The provision is not included in the discontinued
operations assets and liabilities in the table above.
6. Earnings/ (loss) per share
The calculation of basic earnings/ (loss) per share is based on
the profit/ (loss) after tax and the weighted average number of
Ordinary Shares in issue during the year. Basic and diluted
earnings/ (loss) per share are calculated as follows:
2018 2017
$ million $ million
--------------------------------------------------------------------------------------------
Earnings / (loss)
Earnings/(loss) for the purpose of diluted earnings/(loss) per share on continuing
operations 105.1 (270.2)
Profit from discontinued operations 28.3 16.4
Earnings/(loss) for the purposes of diluted earnings/(loss) per share on continuing and
discontinued
operations 133.4 (253.8)
----------- -----------
Number of shares (millions)
Weighted average number of Ordinary Shares for the purposes of basic earnings per share 774.0 513.7
Effects of dilutive potential Ordinary Shares:
Contingently issuable shares (2017: anti-dilutive) 88.3 -
----------- -----------
Weighted average number of Ordinary Shares for the purposes of diluted earnings per share 862.3 513.7
----------- -----------
Earnings/(loss) per share from continuing operations (cents)
Basic 13.6 (52.6)
Diluted 12.2 (52.6)
----------- -----------
Earnings per share from discontinued operations (cents)
Basic 3.7 3.2
Diluted 3.3 3.2
----------- -----------
The inclusion of the contingently issuable shares in the current
year produces diluted earnings per share for both continuing and
discontinued operations (2017: anti-dilutive). At 31 December 2018
there were 88.3 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 $ million
Cost:
At 1 January 2017 1,011.4
Exchange movements (0.9)
Additions during the year 63.1
Acquisition of subsidiaries (0.5)
Exploration expense (1) (11.2)
----------
At 31 December 2017 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
----------
1 Expensed in the income statement with pre-licence expenses of
US$5.6 million in 2018 (2017: US$5.9 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 costs incurred in Mexico on the
Block 2 license, the Sunbeam prospect in the UK and Block 665 in
Brazil.
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.
During the year, the costs associated with the Tolmount project
were transferred to PP&E following project sanction in August.
The balance carried forward is predominantly in relation to the
Group's prospects in the Falkland Islands and the non-operated Zama
prospect and Block 30 in Mexico.
8. Property, plant and equipment
Other fixed
Oil and gas properties assets Total
$ million $ million $ million
=========================================================
Cost:
At 1 January 2017 8,028.6 64.3 8,092.9
Exchange movements 4.6 2.4 7.0
Additions and changes in decommissioning during the year 445.4 2.3 447.7
Asset acquisition 9.8 - 9.8
Assets classified as held for sale (489.6) (1.7) (491.3)
Disposals (409.4) (0.6) (410.0)
====================== =========== ==========
At 31 December 2017 7,589.4 66.7 7,656.1
Exchange movements 1.2 (2.1) (0.9)
Additions and changes in decommissioning during the year (33.5) 1.9 (31.6)
Transferred from E&E 274.2 - 274.2
Assets transferred 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
====================== =========== ==========
Amortisation and depreciation:
At 1 January 2017 5,318.9 47.8 5,366.7
Exchange movements (0.3) 1.9 1.6
Charge for the year 416.2 6.7 422.9
Net impairment charge 252.2 - 252.2
Assets classified as held for sale (434.6) (0.9) (435.5)
Disposals (332.1) (0.6) (332.7)
====================== =========== ==========
At 31 December 2017 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
Net book value:
At 31 December 2017 2,369.1 11.8 2,380.9
====================== =========== ==========
At 31 December 2018 2,239.4 6.2 2,245.6
====================== =========== ==========
Finance costs that have been capitalised within oil and gas
properties during the year total US$1.2 million (2017: US$41.3
million), at a weighted average interest rate of 7.6 per cent
(2017: 7.3 per cent).
Amortisation and depreciation of oil and gas properties is
calculated on a unit-of-production basis, using the ratio of oil
and gas production in the period to the estimated quantities of
proved and probable reserves on an entitlement basis at the end of
the period plus production in the period, on a field-by-field
basis. Proved and probable reserve estimates are based on a number
of underlying assumptions including oil and gas prices, future
costs, oil and gas in place and reservoir performance, which are
inherently uncertain. Management uses established industry
techniques to generate its estimates and regularly references its
estimates against those of joint venture partners or external
consultants. However, the amount of reserves that will ultimately
be recovered from any field cannot be known with certainty until
the end of the field's life.
Impairment charge
The impairment charge in the current year relates entirely to
the Huntington asset in the UK. The impairment charge of US$20.5
million was calculated by comparing the future discounted pre-tax
cash flows expected to be derived from production of commercial
reserves (the value-in-use) against the carrying value of the
asset. The future cash flows were estimated using the following oil
price assumption: US$60/bbl in 2019, US$65/bbl in 2020, US$70/bbl
in 2021 and US$75/bbl in 'real' terms thereafter (2017: two years
at forward curve, year three 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 (2017: 9 per cent)
and 12.5 per cent for the non-UK assets (2017: 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.
The principal cause of the impairment charge being recognised in
the year was as a result of an increase in the expected
decommissioning costs attributed to the asset. The prior year
impairment charge was principally driven by a downgrade in 2P
reserves on the Solan asset.
Reversal of previously recognised impairment charges
Under the requirements of IAS 36, if there is an indication that
a factor that resulted in an impairment charge may have changed or
been reversed, then the previously recognised impairment charge may
no longer exist or may have decreased. For a number of assets, due
to an increase in the near-term oil price assumption (based on the
Dated Brent forward curve), we have reassessed the recoverable
amount of the asset to assess whether an increase in the
recoverable amount (value-in-use) is indicative of a reversal of a
previously recognised impairment charge. The future cash flows were
determined using the same assumptions as those used for the
impairment charge outlined above.
A reversal of impairment of US$55.7 million has been credited to
the income statement for the year, which has been partially offset
by the impairment charge recognised. The impairment reversal
relates entirely to Solan in the UK as a result of a reduction in
the expected gross decommissioning cost attributed to the asset.
The recoverable amount of Solan at 31 December 2018 was US$171.4
million. The prior year reversal of impairment was driven by a one
year extension of COP on the Huntington asset.
Sensitivity
A 1 per cent increase in the discount rates used when
determining the value-in-use for each oil and gas property would
result in a reduction in the net impairment reversal of
approximately US$6.1 million. A US$5/bbl reduction in the long-term
oil price (to US$70/bbl (real)) would reduce the net impairment
reversal by approximately US$19.5 million.
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
(2017: 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, including
the goodwill is US$166.8 million. The key assumptions to which the
calculation of 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.
9. Deferred income
In June 2015, Premier received US$100.0 million from FlowStream
in return for granting them 15 per cent of production from the
Solan field until sufficient barrels have been delivered to achieve
the rate of return within the agreement. This balance is being
released to the income statement within revenue as barrels are
delivered to FlowStream from production from Solan. The balance has
reduced by US$16.2 million during the year reflecting barrels
delivered to FlowStream and a charge to finance costs of US$9.8
million.
The portion of the deferred income that is expected to be
delivered to FlowStream within the next 12 months has been
classified as a current liability.
10. Borrowings
The Group's loans are carried at amortised cost as follows:
2018 2017
$ million $ million
Carrying Fees Total Carrying Fees Total
value value
===================== ========= ========= ======== ========
Bank loans 1,846.7 (21.0) 1,825.7 2,165.0 (106.9) 2,058.1
Senior loan notes 538.1 - 538.1 541.6 - 541.6
Retail bonds 190.5 (2.3) 188.2 202.5 (10.1) 192.4
Convertible bonds - - - 180.5 - 180.5
========= ======= ======== ========= ======== ========
Total borrowings 2,575.3 (23.3) 2,552.0 3,089.6 (117.0) 2,972.6
========= ======= ======== ========= ======== ========
Due within one year - -
Due after more than
one year 2,552.0 2,972.6
========= ======= ======== ========= ======== ========
Total borrowings 2,552.0 2,972.6
========= ======= ======== ========= ======== ========
At the year-end, the Group's principal credit facilities
comprised:
-- Bank loans: US$2.5 billion revolving and letter of credit
facility ('RCF'), US$150 million and GBP100 million term loans
(together the 'Term Loan')
-- Senior loan notes: US$335 million and EUR63.6 million of US
Private Placement ('USPP') notes and US$130 million converted loan
facility; and
-- GBP150 million of retail bonds.
All of the above facilities mature in May 2021.Refinancing of
all the above facilities completed in July 2017. On completion, a
loss of US$83.7 million was recognised in relation to the
facilities that were deemed to be substantially modified in
accordance with IAS 39. In addition, an adoption of IFRS 9 at 1
January 2018, additional interest charges of US$82 million had to
be recognised in 2017, with a corresponding reduction in net assets
at 31 December 2017. As permitted by IFRS 9 comparatives have not
been restated (see note 1).
10. Borrowings (continued)
Convertible bonds
In January 2018, Premier invited convertible bondholders to
exercise their exchange rights in respect of any and all of their
bonds. 87.5 per cent or US$205.8 million of the US$235.2 million
bonds outstanding were accepted for early exchange with an
incentive amount of US$50 per US$1,000 in principal of bonds. The
exchange resulted in the issue of 231,882,091 Ordinary Shares,
which included 7,578,343 incentive shares. Completion of this
offer, resulted in a remaining convertible bond liability of
US$28.8 million.
Following this, in July 2018, the Group announced its intention
to exercise the mandatory conversion option in the remaining
outstanding convertible bonds. The exercise of this option
converted all the remaining US$28.8 million outstanding convertible
bonds into approximately 31.4 million new Ordinary Shares of
Premier. This resulted in Premier's convertible bond liability
being fully extinguished in September 2018.
11. Notes to the cash flow statement
2018 2017
$ million $ million
---------------------------------------------------------
Profit/(loss) before tax for the year 158.2 (366.3)
Adjustments for:
Depreciation, depletion, amortisation and impairment 358.4 667.8
Other operating (income)/costs 1.2 (18.8)
Exploration expense 29.6 11.2
Provision for share-based payments 10.8 8.6
Interest revenue and finance gains (27.8) (12.6)
Finance costs and other finance expenses 400.6 412.7
Profit on disposal of non-current assets (42.3) (129.0)
Operating cash flows before movements in working capital 888.7 573.6
Decrease/(increase) in inventories 1.2 (1.2)
Decrease/(increase) in receivables 72.6 (182.0)
(Decrease)/ increase in payables (93.0) 136.6
---------- ----------
Cash generated by operations 869.5 527.0
Income taxes paid (128.8) (69.6)
Interest income received 7.5 1.1
---------- ----------
Net cash from continuing operating activities 748.2 458.5
---------- ----------
Net cash from discontinued operating activities 29.0 16.8
---------- ----------
Net cash from operating activities 777.2 475.3
---------- ----------
Movement in JV cash (54.4) 20.7
---------- ----------
Total net cash from operating activities 722.8 496.0
---------- ----------
Analysis of changes in net debt:
2018 2017
$ million $ million
a) Reconciliation of net cash flow to movement in net debt:
Movement in cash and cash equivalents (120.8) 109.5
Proceeds from drawdown of long-term bank loans (105.0) (45.0)
Repayment of long-term bank loans 415.3 -
USPP make-whole adjustment - (41.3)
Adjustment to revised fair value of convertible bonds - 58.6
Conversion of convertible bonds 181.9 5.5
Non-cash movements on debt and cash balances (predominantly FX) 22.1 (46.3)
---------- ----------
Reduction in net debt in the year 393.5 41.0
Opening net debt (2,724.2) (2,765.2)
---------- ----------
Closing net debt (2,330.7) (2,724.2)
---------- ----------
b) Analysis of net debt:
Cash and cash equivalents 244.6 365.4
Borrowings (2,575.3) (3,089.6)
---------- ----------
Total net debt (2,330.7) (2,724.2)
---------- ----------
The carrying amounts of the borrowings on the balance sheet are
stated net of the unamortised portion of the refinancing fees of
US$23.3 million (2017: US$117.0 million) and the impact of IFRS
9.
12. Subsequent Events
Assets held for sale
In February 2019, Premier received a further US$5 million cash
deposit from Al-Haj in relation to the disposal of the Pakistan
business unit. This brought the total cash deposit received by
Premier to date of US$40 million, against the headline
consideration of US$65.6 million.
Debt Reduction
Subsequent to the year-end, in January 2019, a further US$100.3
million of the RCF debt facility was cancelled by Premier, which
will result in reduced commitment fee costs for the Group in
2019.
13. External audit
This preliminary announcement is consistent with the audited
financial statements of the Group for the year-ended 31 December
2018.
14. Publication of financial statements
It is anticipated that the full Annual Report and Financial
Statements will be published in April 2019. 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).
15. Annual General Meeting
The Annual General Meeting will be held at the King's Fund,
11-13 Cavendish Square, London W1G 0AN on Wednesday 16 May 2019 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.
-- 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 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 2018
Working interest basis
Falkland Pakistan/
Islands Indonesia Mauritania UK Vietnam Total
----------------- --------------- --------------- ---------------- -------------- --------------------------
Oil,
Oil Oil Oil Oil Oil Oil NGLs
and and and and and and and
NGLs Gas NGLs Gas NGLs Gas NGLs Gas NGLs Gas NGLs Gas(4) gas
-------- ------- ------ ------- ------ ------- ------- ------- ------ ------ -------- ------- -------
mmbbls bcf mmbbls bcf mmbbls bcf mmbbls bcf mmbbls bcf mmbbls bcf mmboe
-------- ------- ------ ------- ------ ------- ------- ------- ------ ------ -------- ------- -------
Group proved plus probable reserves:
At 1 January
2018 126.46 43.83 1.48 199.43 0.08 51.21 68.99 144.38 19.17 26.55 216.18 465.4 301.84
-------- ------- ------ ------- ------ ------- ------- ------- ------ ------ -------- ------- -------
Revisions(1) (126.46) (43.83) 0.07 (6.60) (0.01) (4.26) 12.01 262.76 2.87 2.16 (111.52) 210.23 (68.74)
-------- ------- ------ ------- ------ ------- ------- ------- ------ ------ -------- ------- -------
Discoveries
and extensions(2) - - - - - - - - - - - - -
-------- ------- ------ ------- ------ ------- ------- ------- ------ ------ -------- ------- -------
Acquisitions
and divestments(3) - - (0.40) (7.40) - - - (43.91) - - (0.40) (51.31) (9.87)
-------- ------- ------ ------- ------ ------- ------- ------- ------ ------ -------- ------- -------
Production - - (0.12) (24.67) (0.02) (12.06) (12.95) (21.07) (4.42) (5.45) (17.51) (63.25) (29.55)
-------- ------- ------ ------- ------ ------- ------- ------- ------ ------ -------- ------- -------
At 31 December
2018 - - 1.03 160.76 0.05 34.89 68.05 342.16 17.62 23.26 86.75 561.07 193.68
-------- ------- ------ ------- ------ ------- ------- ------- ------ ------ -------- ------- -------
Total Group developed and undeveloped reserves
Proved on
production - - 0.48 94.81 0.04 26.01 34.32 65.03 16.09 20.74 50.93 206.59 90.38
-------- ------- ------ ------- ------ ------- ------- ------- ------ ------ -------- ------- -------
Proved
approved/justified
for development - - 0.36 49.01 - - 12.46 138.96 0.03 0.49 12.85 188.46 48.96
-------- ------- ------ ------- ------ ------- ------- ------- ------ ------ -------- ------- -------
Probable
on production - - - - 0.01 8.88 16.39 23.95 1.48 1.61 17.88 34.44 23.99
-------- ------- ------ ------- ------ ------- ------- ------- ------ ------ -------- ------- -------
Probable
approved/justified
for development - - 0.19 16.94 - - 4.88 114.22 0.02 0.42 5.09 131.58 30.35
-------- ------- ------ ------- ------ ------- ------- ------- ------ ------ -------- ------- -------
At 31 December
2018 - - 1.03 160.76 0.05 34.89 68.05 342.16 17.62 23.26 86.75 561.07 193.68
-------- ------- ------ ------- ------ ------- ------- ------- ------ ------ -------- ------- -------
Notes:
1 The most significant revisions in the year relate to Sea Lion
and Tolmount. Sealion has been reclassified from Reserves
(Justified for Development) to Contingent Resources (Development
Pending) to align with the new SPE-PRMS Standards issued in June
2018.The booking of the Tolmount Main field as 2P reserves reflects
the sanction of the project in 2018.
2 The Zama discovery in Mexico is classified as contingent
resource and does not appear in this table
3 Divestment of Babbage (UK) and Kakap (Indonesia)
4 Proved plus probable gas includes 96.3 bcf of fuel gas reserves (2017: 95 bcf).
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 181.5 mmboe as at 31
December 2018 (2017: 284.9 mmboe). This was calculated at year-end
2018, using the following oil price assumption: US$60/bbl in 2019,
US$65/bbl in 2020, US$70/bbl in 2021 and US$75/bbl in 'real' terms
thereafter (2017: Dated Brent forward curve for 2018 and 2019,
US$70/bbl in 2020 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 XQLLBKXFXBBB
(END) Dow Jones Newswires
March 07, 2019 02:01 ET (07:01 GMT)
Harbour Energy (LSE:HBR)
Historical Stock Chart
From Jun 2024 to Jul 2024
Harbour Energy (LSE:HBR)
Historical Stock Chart
From Jul 2023 to Jul 2024
