TIDMPMO
RNS Number : 0531H
Premier Oil PLC
08 March 2018
Premier Oil
Full Year Results for the year ended 31 December 2017
Press Release
Tony Durrant, Chief Executive, commented:
"2017 was a successful year for Premier with the refinancing
completed, our producing portfolio performing well, the Catcher
field brought on-stream and the notable Zama oil discovery in
Mexico. 2018 will see further production growth, allowing us to
deliver on our plans for reducing net debt to restore balance sheet
strength while also progressing projects that deliver the highest
financial returns."
2017 Operational highlights
-- Production of 75 kboepd (2016: 71.4 kboepd)
-- Catcher first oil achieved in December, on schedule and under budget
-- Tolmount funding secured
-- World class discovery offshore Mexico, estimated 600 mmbbls (gross)
-- US$300 million of non-core asset disposals
-- Reserves and resources of 902 mmboe (2016: 835 mmboe)
2017 Financial highlights
-- Comprehensive refinancing completed; cash and undrawn
facilities at year-end of US$541.2 million
-- Cash flows from operations of US$496.0 million up 15% (2016: US$431.4 million)
-- Opex of US$16.4/boe, maintaining low cost base
-- Development and exploration capex of US$275.6 million, down 58%
-- Positive free cash flow of US$71.2 million, net debt reduced to US$2.7 billion
-- EBITDAX increased to US$589.7 million (2016: US$494.1 million)
-- US$253.8 million post-tax loss after previously disclosed impairments and refinancing costs
2018 Outlook
-- Production guidance of 80-85 kboepd
-- Opex and capex guidance of US$17-18/boe and US$300 million, respectively
-- Catcher expected to reach 60 kbopd (gross) in April ahead of plan
-- Tolmount project sanction anticipated
-- Material progress on Sea Lion towards final investment decision
-- Zama: rig contracting in progress for 2H appraisal
-- Significant covenant headroom forecast by year-end
-- Rising free cash flow, driving debt reduction through 2018 and 2019
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.
CHIEF EXECUTIVE OFFICER'S REVIEW
2017 saw continued volatility in commodity prices contributing
to economic and market uncertainty for the industry. For Premier,
the year contained three very significant highlights with a world
class oil discovery at Zama offshore Mexico, first oil from the
Catcher development, and the completion of our comprehensive debt
refinancing. These events, together with a strong production
performance from the existing business, continuing cost control and
selective disposals of non-core assets, mean that Premier is
already delivering ahead of its strategic plan agreed at the time
of the refinancing. More recently the outlook has improved with oil
prices closing 2017 at a two-year high of US$66.9/bbl.
Regardless of the external environment, Health, Safety,
Environment and Security ('HSES') matters will always be of
paramount importance to us and we will not compromise on the
integrity and safety of our people and our operations. We continue
to set ourselves challenging HSES targets to drive continuous
improvement. Our HSES performance in 2017, as measured against our
Group aggregate HSES targets, improved. In addition, all of our
production and drilling operations retain their OHSAS 18001 and ISO
14001 certifications. More broadly, our corporate responsibility
efforts continue to be guided by the Ten Principles of the UN
Global Compact, to which we remain committed.
In the near-term Premier's focus is on reducing debt by
utilising the Group's cash flow generated from our low cost stable
production base. In 2017, Premier delivered production of 75.0
kboepd, in line with full year guidance and up five per cent on
2016. This increase in production was driven by a record first half
underpinned by high operating efficiency across the portfolio and a
full year contribution from the ex-E.ON assets.
Production Working interest Entitlement
(kboepd)
-------------- ------------------- -----------------------
2017 2016 2017 2016
-------------- --------- -------- ----------- ----------
Indonesia 14.1 14.3 10.3 10.1
-------------- --------- -------- ----------- ----------
Pakistan and
Mauritania 6.5 7.9 6.4 7.9
-------------- --------- -------- ----------- ----------
UK 39.5 33.0 39.5 33.0
-------------- --------- -------- ----------- ----------
Vietnam 14.9 16.2 13.0 15.1
-------------- --------- -------- ----------- ----------
Total 75.0 71.4 69.2 66.1
-------------- --------- -------- ----------- ----------
Our South East Asia assets performed well during 2017. In
Indonesia, demand from Singapore for our gas was strong and our
operated Natuna Sea Block A fields secured an increased market
share within its principal gas sales contract ('GSA1') of 49.6 per
cent against a contractual share of 47.25 per cent. It also
delivered record production under the second gas sales contract
('GSA2'). Across the border in Vietnam, gross production from the
Premier-operated Chim Sáo field passed 50 million barrels, in
excess of the original total sanctioned volumes. The field exceeded
expectations both in terms of operating efficiency and better than
expected reservoir performance, with a successful well intervention
programme helping to mitigate natural decline from the field.
Year-end production levels were also boosted by a further 6.5
kboepd (gross) after completing a low cost, two well infill
drilling programme.
UK production, which represents over half of Group production,
grew 20 per cent from 2016 principally as a result of a full year's
contribution from the ex-E.ON assets, which continue to exceed
expectations at the time of acquisition. The Huntington field saw
particular outperformance, contributing 13.0 kboepd, and it remains
the highest net producer in our UK portfolio prior to the ramp up
of production from the Catcher Area. The continuing strong
reservoir performance, together with an improved lease rate
structure on the FPSO agreed with Teekay, means that we expect
Huntington to continue to produce longer than previously envisaged.
The long-life Elgin-Franklin field continued to benefit from an
ongoing infill drilling programme and our Babbage gas field
delivered a strong performance in 2017 underpinned by well
intervention and optimisation of the existing well stock.
Production from the Solan field was lower than originally expected
due to poorer performance in the East reservoir. This has resulted
in a write down in recoverable reserves leading to a non-cash
impairment charge in the year. Current production from Solan is
performing in line with our revised expectations and we continue to
evaluate options to improve production levels and recovery. Profits
from UK production continue to be sheltered by Premier's brought
forward cumulative tax loss and allowance position.
In December we were delighted to safely deliver first oil from
the Catcher Area, marking a significant milestone for Premier. The
successful execution of this project on schedule, and with total
project costs expected to be some 30 per cent below the original
sanctioned budget, is testament to the hard work, skill and
capability of the project team and our contractors. We are bringing
the development on-stream in a phased manner from the three fields
that make up the Catcher Area, firstly from the Catcher field, then
Varadero and shortly from Burgman, as the final commissioning
activities on the FPSO are completed. Once the field is fully
operational we will be producing at a plateau production rate of 60
kbopd (gross) which we expect to achieve during April. Development
drilling throughout the project has been encouraging with 14 wells
now completed and a further 4 wells to be drilled by September
2018. Catcher is an example of Premier's capability to deliver full
cycle FPSO projects from exploration through to production and the
increased cash flows it generates will play an important role in
our debt reduction plans in 2018 and beyond.
During 2018, we expect Group production to increase to 80-85
kboepd reflecting the phased ramp up from the Catcher Area, offset
by natural decline in certain of our fields and the impact of
disposals.
Strict management of our operating cost base and our committed
capital expenditure have remained a key focus for Premier in 2017.
Our operating costs were US$16.4/boe (2016: US$15.8/boe) in line
with budget, reflecting changes in the production portfolio and
ongoing cost saving initiatives. We continue to see opportunities
for further savings from collaboration initiatives and competitive
re-tendering, and expect to maintain a low cost base for the
medium-term. 2017 capital expenditure was well below our original
guidance as we secured further savings on the Catcher project and
on our drilling campaign in Mexico. As the current phase of the
Catcher development completes in the middle of 2018, Premier's
forward committed capex will fall significantly.
Alongside increasing production and cost control discipline, our
selective disposal programme of non-core assets announced in 2017
has enabled us to start deleveraging our balance sheet. These
disposals included the sale of our Pakistan business that will
complete after the receipt of Pakistani authorities approval, the
ongoing rationalisation of assets acquired with the E.ON portfolio
and the disposal of our non-operated interest in the Wytch Farm
field which completed in December. These disposals, which will
generate consideration of US$300 million, are an important part of
meeting our debt reduction targets.
In the medium-term Premier intends to invest selectively in our
portfolio of future projects to maintain and grow our production in
the 2019-2021 timeframe and deliver value for all stakeholders. In
July we were delighted to announce a material exploration success
in Mexico. The world class oil discovery at the Zama-1 exploration
well vindicated our strategy of focusing on under-explored but
proven hydrocarbon basins and our initial estimates for the full
field are a P90-P10 gross unrisked resource range of 400-800
mmbbls, well ahead of pre-drill expectations. Premier continues to
work with both our joint venture partners and PEMEX in the
neighbouring block to secure a pre-unitisation agreement to
progress the appraisal of this significant discovery. Discussions
are underway to secure an option on a rig to undertake the
appraisal programme which is expected to commence in the second
half of 2018 or early 2019.
Our next development is an incremental gas project in Indonesia,
which was sanctioned by the Board in March 2017. Bison, Iguana,
Gajah Puteri ('BIGP'), which is designed to back fill our existing
Singapore and domestic gas sales contracts, is proceeding well and
is on budget and scheduled to deliver first gas in 2019.
Our Tolmount Main gas development in the Southern North Sea,
which will provide the next significant phase of our growth, is
targeted for project sanction in 2018. This initial phase is
targeting gross resources of 540 Bcf (100 mmboe) and is an
economically robust project for Premier even at low gas prices.
There is also significant resource upside, currently estimated at a
further 400 Bcf (gross) in the Greater Tolmount Area. Front End
Engineering Design ('FEED') work is progressing well, the
environmental assessments for the project are underway and a draft
field development plan has been submitted to the OGA. We are
pleased to have agreed an innovative financing arrangement for the
project, establishing an infrastructure partnership for the field
facilities. The impact of this arrangement is to reduce Premier's
share of the capex required to develop this large gas field to
approximately US$100 million.
Our Sea Lion project in the Falkland Islands is Premier's
largest pre-development project with around 400 mmboe reserves and
resources (net to Premier) to be developed over several phases.
With considerable progress made in 2016 to optimise the project
economics for the first phase of the development, work in 2017
focused on the commercial, regulatory and fiscal work streams and
on securing a financing solution. Discussions are ongoing with
senior debt providers and supply chain contractors to secure
suitable funding and commercial terms. Letters of Intent have now
been signed with contractors for the provision of a range of
services including vendor financing. Premier is working towards a
final investment decision by the end of 2018.
At 31 December 2017 group proven and probable (2P) reserves, on
a working interest basis, were 302 mmboe (2016: 353 mmboe) and
total 2P reserves and 2C resources increased to 902 mmboe (2016:
835 mmboe).
2P reserves
Proven and and 2C
probable contingent
2P reserves resources
(mmboe) (mmboe)
---------------------------- ------------- ------------
1 January 2017 353 835
---------------------------- ------------- ------------
Production (27) (27)
---------------------------- ------------- ------------
Net additions, revisions,
discoveries (12) 120
---------------------------- ------------- ------------
Disposals, relinquishments (12) (26)
---------------------------- ------------- ------------
31 December 2017 302 902
---------------------------- ------------- ------------
The decrease in 2P reserves is driven by the impact of 2017
production, a downward revision to our Solan 2P reserve estimates
and the disposal of our Wytch Farm interests. This is partially
offset by upward revisions to our estimates of 2P reserves at both
Huntington and Babbage. The increase in our 2C resources of 118
mmboe was principally a result of the Zama oil discovery offshore
Mexico, the addition of Tolmount East as a contingent resource and
upward revision to the Sea Lion Phase 2 resources including the
2015 Zebedee discovery.
The completion of the refinancing of our debt facilities in July
marked a major milestone for Premier and has established a solid
foundation for us to fulfil our strategic plans. Debt reduction
remains our top priority, but the refinancing provides the headroom
and flexibility to plan for future investment in selective new
projects. At year-end net debt stood at US$2.7 billion. Positive
free cash flow including disposals was offset by adjustments to
reflect the terms and costs of the refinancing and non-cash foreign
exchange movements. Post year-end Premier invited our convertible
bondholders to accelerate the conversion of their bonds.
Approximately US$200 million was converted resulting in a further
reduction in net debt.
As we enter 2018, our stable production delivered from a
competitive operating cost base and lower capital commitments will
generate increasing free cash flows, which in the short-term will
be directed at reducing our debt. Looking forward, we will
selectively invest in new development projects within a strict
capital discipline framework to provide growth in the medium-term
and deliver future value for all stakeholders.
Tony Durrant
Chief Executive Officer
OPERATIONAL REVIEW
UNITED KINGDOM
The UK delivered 20 per cent higher production in 2017, with a
full year's contribution from the E.ON assets acquired during 2016
and high operating efficiency across the portfolio. First oil from
the Catcher Area, which was delivered on 23 December on schedule
and with total forecast project costs some 30 per cent below the
sanctioned budget, will deliver a further increase to UK production
in 2018. Looking forward, we expect to sanction the Tolmount gas
project during 2018, providing the next phase of growth for the UK
business, which is expected to average around 50 kboepd (net) over
the next five years.
Production
Production from Premier's UK fields averaged 39.5 kboepd (net)
(2016: 33.0 kboepd (net)), up 20 per cent on 2016. Following
delivery of first oil from Catcher at the end of the year, there
will be a further production growth in 2018, despite the impact of
the Wytch Farm disposal in December. Production from the Catcher
Area is currently ramping up and is expected to reach plateau rates
during April.
The Premier-operated Huntington field (100 per cent interest)
was the highest producer in the UK portfolio in 2017 with
production averaging 13.0 kboepd (2016: 10.8 kboepd), 28 per cent
higher than budget. This strong performance was achieved by
improved reservoir management and high FPSO operating efficiency.
The lease agreement with Teekay, the owner of the Voyageur Spirit
FPSO, has been extended beyond April 2018 for a minimum of a year
with a revised lower lease cost structure. The combination of
better than expected reservoir performance and a lower FPSO lease
rate has led Premier to increase its estimate of Huntington's
remaining net 2P reserves by 4 mmboe.
Production from the non-operated Elgin-Franklin field (5.2 per
cent interest) was marginally below budget, averaging 5.4 kboepd
(net). Strong underlying field performance as a result of an
ongoing infill drilling campaign was offset by an extended summer
maintenance shutdown required to replace a large platform riser
shutdown valve, and by downtime of the Forties Pipeline System
('FPS') export pipeline during the fourth quarter of 2017. 2018
production to the end of February has averaged 7.7 kboepd (net),
above expectations, due to contributions from infill drilling and
high operating efficiency. The non-operated Glenelg field (18.75
per cent interest), a satellite field within the Elgin-Franklin
area, produced intermittently during 2017 due to downhole scaling
in the single well. This is likely to require an intervention in
2018/19 to rectify fully.
A successful well intervention programme and continued
production optimisation of the existing well stock led to the
Premier-operated Babbage field (47 per cent interest) delivering
3.1 kboepd (net), ahead of budget. In addition, field operating
costs were reduced by more than 20 per cent as a result of the
platform being transitioned to a Not Permanently Attended
Installation ('NPAI') in April. Premier will continue to undertake
production optimisation activities at the field which are expected
to add incremental production for low additional expenditure in
coming years. As a result of the improved production performance
and lower operating costs, Premier now expects a longer than
expected field life beyond 2030 and has revised upwards its
estimates of Babbage's remaining net 2P reserves.
In the Southern North Sea, similar well optimisation efforts,
including re-instatement of inactive wells and interventions in
existing well stock, have seen production restart at the Rita gas
field (74 per cent interest) after being shut in for almost two
years. There have also been successful well re-instatements at the
Johnston gas field (50.1 per cent interest). These low cost
activities typically deliver short-term cash payback in less than
12 months.
Production from the Premier-operated Solan field (100 per cent
interest) averaged 5.9 kboepd, lower than originally expected, as a
result of the first production well ('P1') being shut in for a
period in February following the failure of the existing electric
submersible pump ('ESP'). P1 is currently producing as expected on
free flow and as a result the Company has no immediate requirement
for workover operations. Production rates from the second producer
('P2') remain limited due to poor reservoir performance in the
eastern part of the field. During the year further topside
enhancements were completed with the successful installation and
commissioning of a water injection upgrade and produced water
handling projects. Options to improve production levels and
recovery at Solan continue to be evaluated including a possible
further drilling campaign starting in 2019 or 2020. Premier has
reduced its estimates of Solan's remaining net 2P reserves,
reflecting lower expected recovery from the asset over its economic
life. This reduction does not take account of any potential upside
from the deeper Triassic play on the Solan licence or the impact of
any potential third-party volumes across the Solan infrastructure,
which are currently being assessed.
Production from the Premier-operated Balmoral Area performed as
expected delivering 2.2 kboepd (net) (2016: 2.1 kboepd (net)).
Previous plans for cessation of production at Balmoral by April
2019 have been re-evaluated, driven by the asset's performance and
improving market oil prices. Planning for the decommissioning of
the area is well advanced, including the disposal and sale of the
Balmoral Floating Production Vessel ('FPV'). Some decommissioning
work has started and during the fourth quarter, the Helix Well Op's
Seawell intervention vessel entered four old suspended Balmoral
water injection wells to gather information on well status and to
prepare the wells for later abandonment. Premier is now considering
moving cessation of production out to 2021, subject to partner and
Government approvals. In order to do this, some modest further
investment on wells, subsea and topsides may be required to
maintain performance and asset integrity, whilst a lower but
appropriate level of decommissioning planning works would also
continue.
Production from the non-operated Wytch Farm field (33.8 per cent
interest) averaged 4.4 kboepd (net) (2016: 5.1 kboepd (net),
reflecting natural reservoir decline and a reduced contribution
following disposal of the asset in December.
UK unit operating costs for the year were US$23/boe (2016:
US$24/boe) as a result of favourable asset uptime, continued cost
control measures and a full year's contribution from the E.ON
assets. In 2018, Premier expects a further reduction in the UK
operating costs per barrel with increased production from the
start-up of the Catcher Area and the lower leased FPSO rates at
Huntington, offsetting natural decline at certain fields.
Development
Catcher
First oil was successfully delivered on schedule on the
Premier-operated Catcher project on 23 December. The Catcher Area
(50 per cent interest) comprises three fields - Catcher, Varadero
and Burgman - with production initially started from the Catcher
field. Total forecast capex remains at US$1.6 billion, 30 per cent
lower than the sanctioned estimate.
Following successful final construction and pre-commissioning
activity during the period, the Catcher FPSO departed the Keppel
shipyard in Singapore on 10 August and completed its journey to the
UK via the Suez Canal without incident and ahead of schedule. The
vessel then completed a planned stop at Nigg Port, Scotland for
preparatory work ahead of arrival at the Catcher field location on
18 October. By 20 October it was successfully connected in-field to
the pre-installed buoy and had completed the initial rotation test.
The installation, hook-up and commissioning ('IHUC') work has
proceeded to plan. All production and injection risers were
permanently hung-off, shutdown valving installed and subsea control
umbilicals attached. The remaining offshore construction period of
work was complete by the end of November, when the focus switched
to final commissioning of subsea systems and the interfaces with
the vessel. A trial for oil tanker offloading completed
successfully in the third week of November ahead of first oil in
December.
The initial production wells from the Catcher field were cleaned
up and tested at rates in excess of 20 kbopd (gross) each, in line
with expectations and reflecting initial high productivity. As
planned, production is being ramped up in phases with first oil
from Varadero brought on in early January, to be followed by
Burgman shortly. Production levels have had to be deliberately
constrained during the ramp up phase while commissioning of the
full gas processing modules and the water injection systems on the
FPSO are carried out. Water injection was brought on in
mid-February and the final gas compression commissioning is
underway. Following this, full production from the Catcher Area of
60 kbopd (gross) is expected during April. The first two export
cargos of over 500,000 barrels each were lifted on 23 January and
18 February and both were sold at a premium to Brent.
Drilling activities using the Ensco 100 rig have continued with
operations ahead of schedule and under budget. Fourteen production
and injection wells have now been drilled and completed with
consistently positive reservoir results, with 12 of these wells
being tied-in ahead of first oil. The rig is currently drilling the
CCP6 well on the second Catcher template and will drill a further
Catcher well before moving to the Burgman field. A total of 18
wells will be drilled by September 2018 before a planned drilling
break. As a result of initial production from the field and these
positive well results to date, Premier is encouraged about the
potential overall recovery from the Catcher Area and continues to
target peak plateau production of approximately 60 kbopd (gross),
20 per cent higher than that envisaged at sanction.
Premier and its joint venture partners are already examining
future Catcher Area development opportunities to make full use of
the newly commissioned facilities. Studies are underway for the
future development of the 2016 Laverda discovery in conjunction
with an infill well in the northern area of the Catcher field.
These future activities, amongst others, are planned to provide
incremental production from 2020 onwards.
Pre-development
Good progress has been achieved on the Premier-operated Tolmount
project (50 per cent interest) in the Southern Gas Basin. It is
envisaged that the initial phase, which will target the Tolmount
main structure, will recover 540 Bcf (gross) of gas from four
producing wells at a production capacity of up to 300 mmscfd
(gross).
In February 2017, the development concept, comprising a
standalone normally unmanned installation ('NUI') and a new gas
export pipeline to shore, was selected. A commercial Heads of Terms
was also signed with a terminal operator to process the Tolmount
fluids and to undertake terminal modification works on behalf of
the Tolmount project. Front End Engineering & Design ('FEED')
work is progressing well, with platform and pipeline FEED completed
and tenders received for the project scopes under evaluation. Bids
are also being evaluated from drilling rig providers to cover the
development drilling programme, and the earlier drilling of the
Tolmount East appraisal well in 2019.
Alongside the FEED process, Premier signed a Heads of Terms to
enter into an infrastructure partnership for the Tolmount
development with Dana Petroleum and CATS Management Limited,
whereby they will jointly finance, construct and own the Tolmount
platform and export pipeline as a standalone development, as well
as undertaking the onshore modifications at the onshore gas
receiving terminal. The Tolmount field will be tied-in to the
platform and a tariff will be paid to the infrastructure owners by
the upstream partners for the transportation of gas production
through the infrastructure over the life of the field. As a result,
Premier's share of capex is estimated to be approximately US$100
million. Fully termed agreements are being progressed ahead of
project sanction which is scheduled during 2018.
Exploration
During 2017, well operations on the Ravenspurn North Deep well
(five per cent carried interest), which was testing the deep
Carboniferous play underlying the Ravenspurn North field in the
Southern Gas Basin, were completed. The well was plugged and
abandoned.
Premier continues to actively manage its UK exploration
portfolio. In September, Premier exited the P2184 Licence which
carried a commitment well obligation on the Ekland prospect and a
further four licences were relinquished by the end of the year.
This includes the P2136 Artemis Licence, where a well commitment
was offset against other activity in the UKCS.
Portfolio management
During the first half of the year Premier exercised its
pre-emption rights to acquire an additional 3.71 per cent of the
Wytch Farm field for approximately US$15 million, taking Premier's
overall interest in the field to 33.8 per cent. Subsequently,
Premier agreed to dispose of its entire 33.8 per cent interest in
the Wytch Farm field to Perenco UK Limited for a cash consideration
of US$200 million, realising an attractive valuation in excess of
that implied from the previous transaction and above Premier's
internal valuation. Premier was also able to release Letters of
Credit, amounting to approximately US$75 million, held in respect
of future field abandonment liabilities. The sale completed in
December, generating a pre-tax profit on disposal of approximately
US$133 million.
Premier continued its programme of non-core asset disposals in
2017 principally from the E.ON portfolio acquired in 2016. It
disposed of its interests in the Austen and Arran fields in the
Central North Sea during the year and in December announced the
disposal of its 30 per cent interest in the Esmond Transportation
System ('ETS') pipeline for up to US$31.6 million. These disposals,
together with the relinquishment of other licences, has meant that
Premier has actively managed its current UK licence position down
from 63 blocks in 2016 to 39 blocks today, and this rationalisation
activity is expected to continue in 2018.
INDONESIA
The Premier-operated Natuna Sea Block A fields delivered a
robust and stable performance in 2017 with production of 12.9
kboepd (net), underpinned by supplying an increased market share of
49.6 per cent within GSA1 and strong Singapore demand for gas
deliveries under GSA2. This, together with continued low operating
costs of US$9.6/boe, once again led to the Indonesian business unit
generating material positive net cash flows for the Group.
Production and development
Production from Indonesia in 2017 on a working interest basis
was in line with budget at 14.1 kboepd (net) (2016: 14.3 kboepd
(net)). The Premier-operated Natuna Sea Block A fields (28.67 per
cent interest) delivered 12.9 kboepd (net) while production from
the non-operated Kakap field (18.75 per cent interest) averaged 1.2
kboepd (net). Operating efficiency remained high at over 99 per
cent.
Gas supply by contract
GSA1 GSA2 GSA5
-------------- ---------- ---------- ----------
BBtud (gross) 2017 2016 2017 2016 2017 2016
-------------- ---- ---- ---- ---- ---- ----
Anoa (Pelikan
field) 143 132 - - - -
-------------- ---- ---- ---- ---- ---- ----
Gajah Baru
(Naga field) - - 91 94 - 11
-------------- ---- ---- ---- ---- ---- ----
Total Block
A 143 132 91 94 - 11
-------------- ---- ---- ---- ---- ---- ----
Kakap 17 17 - - - -
-------------- ---- ---- ---- ---- ---- ----
Total 160 149 91 94 - 11
-------------- ---- ---- ---- ---- ---- ----
Premier sold an average of 234 BBtud (gross) (2016: 237 BBtud)
from its operated Natuna Sea Block A fields during 2017. Singapore
demand for gas sold under GSA1 remained robust, averaging 286 BBtud
(2016: 297 BBtud). Premier's Anoa and Pelikan fields delivered 143
BBtud (gross) (2016: 132 BBtud (gross)), capturing 49.6 per cent
(2016: 44.4 per cent) of GSA1 deliveries, above Natuna Sea Block
A's contractual share of 47.2 per cent. Natuna Sea Block A's
contractual share for 2018 has been increased to 51.7 per cent.
Gajah Baru and Naga delivered production of 91 BBtud (gross)
(2016: 94 BBtud (gross)) under GSA2, representing 100 per cent
nomination delivery by Premier. There were no deliveries under GSA5
(2016: 11 BBtud (gross)) following the expiry of the Domestic Gas
Supply Agreement.
Gas sales from the non-operated Kakap field averaged 17 BBtud
(gross) (2016: 17 BBtud (gross)) while gross liquids production was
2.6 kbopd (2016: 2.7 kbopd). Gross liquids production from the Anoa
field was 1.1 kbopd (2016: 1.4 kbopd), underpinned by successful
well intervention work.
Premier continues to benefit from a low cost base in Indonesia,
delivering further cost reductions in 2017. Based on current
production levels, Natuna Sea Block A remains well placed to
deliver operating costs of around US$9/boe into the
medium-term.
The Anoa development well ('WL-5X'), which made the Lama
discovery under Anoa in 2012, was re-completed in August 2017. The
well was brought on-stream to carry out a long-term production test
which will help to define the potential of these deeper zones
within the Anoa field.
The development of the Bison, Iguana and Gajah Puteri ('BIGP')
gas fields was sanctioned in 2017 which marks the next generation
of Natuna Sea Block A projects to support Premier's long-term gas
contracts into Singapore. The EPCI contract for BIGP, which will be
developed as subsea tiebacks to existing infrastructure, was
executed in October 2017 and development drilling is planned for
early 2019. First gas remains on budget and on schedule for the
second half of 2019.
In January Premier was granted a three-year extension to the
exploration period of the Premier-operated Tuna PSC licence where
the evaluation of potential development scenarios for the 2014 Kuda
Laut and Singa Laut discoveries, now collectively known as the Tuna
field (65 per cent interest), is ongoing. In November a Memorandum
of Understanding between PetroVietnam, SKK Migas (on behalf of the
Indonesian Government) and Premier for future gas sales from the
Tuna field in Indonesia into Vietnam was signed, enhancing future
commercialisation. In 2018, a farm-out process has been launched
with a view to funding Premier's share of an appraisal campaign in
2019.
Exploration and appraisal
As a result of the production performance from the Anoa
development well WL-5X, brought on-stream in August, Premier is
reprocessing 3D seismic over the Anoa field to enhance the seismic
imaging across the Lama Play area. Premier will use this
reprocessed data to identify and mature Lama Play leads and
prospects on its Natuna Sea Block A acreage.
Since the year-end, Premier together with its joint venture
partners has been awarded the Andaman II licence (40 per cent,
operated interest) in the North Sumatra basin offshore Aceh,
Indonesia. The licence has the potential to deliver significant gas
volumes into North Sumatra and adds a potentially material gas play
to Premier's Indonesian portfolio.
Portfolio management
In December, Premier signed a sale and purchase agreement with
Batavia Oil to sell its entire 18.75 per cent non-operated interest
in the Kakap field for a cash consideration of US$3.2 million.
Completion is subject to approval from the Government of
Indonesia.
VIETNAM
The Vietnam business generated strong operating cash flows in
2017 due to a higher than budgeted production performance combined
with continued low operating costs. During the period, gross
cumulative production surpassed 50 million barrels, in excess of
the original volumes estimated at project sanction.
Production
Production from the Premier-operated Block 12W (53.13 per cent
interest), which contains the Chim Sáo and Dua fields, was ahead of
budget, averaging 14.9 kboepd (net) (2016: 16.2 kboped (net))
underpinned by high operating efficiency, excellent reservoir
performance and a successful well intervention programme which
helped to mitigate natural decline from the fields.
A two well infill drilling programme completed in December 2017
proved highly successful, adding incremental net production of 3.3
kboepd and further extending the long-term potential from the
field. The infill drilling programme comprised two low cost wells.
The first well was a side-track of a water injector well no longer
required which was re-completed as a production well while the
second well was drilled from the final unused slot on the Chim Sáo
wellhead platform. Using lessons learnt from previous drilling
campaigns, reservoir performance has been improved and production
increased, with some further zones remaining unperforated. This
will allow us to target bringing further incremental production
on-stream in 2018.
Overlying the two main reservoirs in the Chim Sáo field are
several smaller but significant hydrocarbon bearing sandstones
which are intersected by the production wells. In 2017, as the rate
of hydrocarbon flow from the main reservoirs reduced, the shallower
reservoirs of selected wells were perforated to access new zones.
In addition, producing zones in several wells were worked over to
accelerate hydrocarbon production. This intervention programme on
existing wells reduced the rate of natural production decline and
contributed 1.0 kboepd (net) to Premier's 2017 production at a cost
of only US$4/barrel.
Chim Sáo's operating efficiency remained at over 90 per cent in
2017. This was the result of safe and reliable operations and
maintenance services, minimal unplanned events, and planned
shutdown and slowdown campaigns being completed on schedule.
During 2017 Chim Sáo operating costs remained low at US$9.8/boe
(2016: US$8.7/boe). Low costs were maintained by replacing the
supply vessel contract at depressed market rates, improved vessel
management, and the impact of the lower Chim Sáo FPSO lease rate
agreed at the end of 2016. These savings, along with Chim Sáo crude
continuing to sell at premiums to the Brent oil price, contributed
to a positive net operating cash flow from the Vietnam business
unit in 2017 despite the cost of the infill programme.
PAKISTAN
Premier's Pakistan business continued to generate positive and
stable net cash flows for the Group. During 2017, the average
realised gas price was US$3.0/mscf while operating costs remained
low at US$4.2/boe (US$0.6/mscf).
Production and Development
Net production in Pakistan averaged 6.2 kboepd (39.1 mmscfd)
(2016: 7.5 kboepd (47.4 mmscfd)) from Premier's six non-operated
producing gas fields. The fall in production reflects natural
decline in the main gas fields which was partially offset by
successful well intervention campaigns at the Bhit and Badhra
fields.
Mmscfd (net) Production Equity interest
%
--------------- ----------------
2017 2016
--------------- ------ ----- ----------------
Bhit 7.0 8.4 6.0
--------------- ------ ----- ----------------
Badhra 4.6 5.7 6.0
--------------- ------ ----- ----------------
Qadirpur 14.9 16.1 4.75
--------------- ------ ----- ----------------
Kadanwari 4.1 5.5 15.79
--------------- ------ ----- ----------------
Zamzama 7.9 11.3 9.38
--------------- ------ ----- ----------------
Zarghun South 0.6 0.4 3.75
--------------- ------ ----- ----------------
Total 39.1 47.4
--------------- ------ ----- ----------------
Portfolio management
In April, Premier announced the sale of its Pakistan business to
Al-Haj Group for US$65.6 million. To date, Al-Haj has paid deposits
of US$25.0 million. Completion of the sale is awaiting final
approvals from the Pakistani authorities and in the meantime
Premier continues to collect the cash flows generated from the
Pakistan assets.
MAURITANIA
Production and development
Production from the Chinguetti field (8.12 per cent interest)
averaged 257 bopd (2016: 368 bopd) net to Premier during 2017. The
fall in production was driven by natural decline from the existing
wells. As a result of these low production volumes and resulting
marginal cash flows, the joint venture partners ceased production
from the field on 30 December 2017 and the FPSO is being prepared
for sail away. A drill ship has now been mobilised to the
Chinguetti field to start a six-month campaign for temporary
suspension of wells starting with the water injection wells. The
permanent abandonment of the wells is scheduled for 2019. The field
abandonment and decommissioning plan is awaiting approval by the
Government of Mauritania. In addition, plans are being prepared for
the abandonment of the suspended exploration and appraisal wells on
the previously relinquished Banda and Tiof discoveries.
THE FALKLAND ISLANDS
The focus in 2017 for the Premier-operated Sea Lion Phase 1
project has been on progressing commercial and regulatory work
streams and on securing commitments from key contractors for the
project.
Pre - development
The Sea Lion project and the wider North Falklands Basin, has
the potential to be significant for Premier and the strategy is to
develop the discovered resources in several phases. Sea Lion Phase
1 (60 per cent interest), which is targeting gross reserves of over
220 mmbbls in PL032, will utilise a conventional FPSO based scheme,
very similar to Premier's successful Catcher development.
Engineering design work which was largely completed in 2016,
focused on optimising the facilities design and installation
methodology required reducing the estimated gross capex to first
oil to US$1.5 billion.
During 2017, Premier focused on securing agreement with key
supply chain contractors for the project. Good progress was made in
this respect with Letters of Intent signed with a number of
contractors for the provision of a range of services and vendor
financing. Further discussions with senior debt providers including
commercial banks and export credit finance agencies will progress
in 2018.
Alongside this, Premier continued to engage with the Falkland
Islands Government ('FIG') on environmental, fiscal and other
regulatory matters with a view to obtaining the consents and
agreements necessary to be in a position to reach a final
investment by the end of 2018. As part of this process the latest
drafts of the Field Development Plan and Environmental Impact
Statement ('EIS') for Sea Lion Phase 1 were submitted to FIG and
the formal public consultation of the EIS commenced in January
2018.
It is estimated that a subsequent Phase 2 development will
recover over 300 mmbbls (gross) from the remaining volumes in PL032
and the satellite accumulations in the north of the adjacent PL004.
During 2017 further technical analysis carried out on Phase 2,
including the 2015 Zebedee discovery in PL004, has resulted in an
increase in net 2C resources at the year-end.
EXPLORATION
In recent years, Premier's strategy has been to focus its
exploration portfolio on under-explored but proven hydrocarbon
basins rather than traditional but now mature areas, with priority
given to lower cost operating environments. This strategy resulted
in a major success with the world class oil discovery at the Zama-1
well offshore Mexico during 2017, capitalising on Premier's first
mover advantage as the country opened up to foreign investment.
MEXICO
During 2017 Premier, together with its joint venture partners
Talos Energy (Operator) and Sierra Oil & Gas, drilled the Zama
prospect in Block 7 in the Sureste Basin, offshore Mexico which
resulted in a significant oil discovery. The Zama-1 well
encountered a continuous oil bearing interval of over 335 metres
(1,100 feet) with up to 200 metres of net oil bearing reservoir in
upper Miocene sandstones with no water contact. Initial tests of
hydrocarbon samples recovered to the surface showed light oil with
API gravities between 28 and 30 degrees. Premier's initial gross
oil-in-place estimates are 1.2-1.8 billion barrels, with an
estimated recoverable P90-P10 gross resource range of 400-800
mmbbls. These estimates include those volumes that extend into the
neighbouring block which is operated by PEMEX. The joint venture is
now working with PEMEX to secure a pre-unitisation agreement in
order to progress the appraisal programme which is expected to
commence on Premier's block in the second half of 2018 or in early
2019. Our joint venture is close to securing an option on a rig to
complete the appraisal programme on Block 7 and PEMEX has indicated
that they intend to appraise the Zama discovery on their licence
with a well scheduled to spud in the second quarter of 2018. In
addition to appraisal well planning, pre-FEED scoping studies have
been received from seven vendors aiding appraisal planning and
identifying additional data to be acquired in the up and coming
drilling programme. Premier holds a 25 per cent paying interest in
Block 7.
Premier also currently holds a carried 10 per cent interest in
Block 2, with an option to increase to 25 per cent or to exit. The
joint venture is evaluating which prospect will be the first to be
drilled, targeting a well in 2019. Premier continues to evaluate
opportunities for growth in Mexico, from future licensing
rounds.
BRAZIL
Premier received 4,000 km(2) of final processed broadband
seismic data across all three of its Ceará Basin blocks in April
2017. The data has now been interpreted, the best prospects
selected and the wells are being planned in advance of a potential
drilling campaign in 2019 or 2020. Significant progress has been
made on obtaining environmental and drilling permits as Premier
continues to leverage its position as the largest acreage holder in
the Ceará Basin, along with its growing experience in Brazil, to
coordinate operational synergies. In October the ANP, the Brazilian
Government regulator, published an option to all Round 11 awards
that entitles Premier to request extension of its licences by a
further two years to at least July 2021.
FINANCIAL REVIEW
Overview
2017 saw continuing oil price volatility. Brent crude opened the
year at US$56.6/bbl before falling to US$44.8/bbl in June and then
strengthening considerably in the second half of the year to close
at US$66.9/bbl at 31 December 2017. The average for 2017 was
US$54.2/bbl against US$43.7/bbl for 2016. Subsequent to the
year-end, prices improved during January reaching a high of
US$71.3/bbl, before falling to US$64.2/bbl on 7 March 2018, below
the year end observed price.
Against this economic backdrop we have achieved our best ever
full year of production, averaging 75.0 kboepd (2016: 71.4 kboepd),
resulting in total revenue from all operations of US$1,102 million
compared with US$983.4 million in 2016 and Free Cash Flow after
disposals of US$71 million (2016: US$580 million cash outflow). In
addition, we successfully completed the refinancing of all of our
debt facilities in July 2017 and reached first oil on the Catcher
field in the UK North Sea in December 2017.
Business performance
EBITDAX for the year from continuing operations was US$589.7
million compared to US$494.1 million for 2016. The increase in
EBITDAX is mainly due to higher production and sales volumes
realised during the year.
Business Performance (continuing operations) 2017 2016
$ million $ million
--------------------------------------------- ----------- -----------
Operating profit / (loss) 33.8 (170.1)
--------------------------------------------- ----------- -----------
Add: Amortisation and depreciation 415.6 326.4
--------------------------------------------- ----------- -----------
Add: Impairment charge on oil and gas
properties 252.2 561.9
--------------------------------------------- ----------- -----------
Add: Exploration expense and pre-licence
costs 17.1 58.5
--------------------------------------------- ----------- -----------
Less: Gain on disposal of assets (129.0) -
--------------------------------------------- ----------- -----------
Reduction in decommissioning estimates - (75.7)
--------------------------------------------- ----------- -----------
Acquisition of subsidiaries:
- Excess of fair value over consideration - (228.5)
- Costs related to the acquisition - 21.6
EBITDAX(1) 589.7 494.1
--------------------------------------------- ----------- -----------
1. Prior year has been restated for results from the Pakistan
business unit, which has been reclassified as a discontinued
operation in the year.
Income statement
Production and commodity prices
Group production on a working interest basis averaged 75.0
kboepd compared to 71.4 kboepd in 2016. This was driven by high
operating efficiency, better than predicted reservoir performance
on certain fields and a full period contribution from the E.ON UK
portfolio acquired in April 2016. Average entitlement production
for the period was 69.2 kboepd (2016: 66.1 kboepd).
Premier realised an average oil price for the year of
US$52.9/bbl (2016: US$44.1/bbl). Including the effect of oil swaps
which settled during 2017, the realised oil price was US$52.1/bbl
(2016: US$52.2/bbl).
In the UK, average natural gas prices achieved were 47.2
pence/therm (2016: 47.6 pence/therm), which included 95.8 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$8.4/mscf (2016: US$7.8/mscf).
Total revenue from all operations (including Pakistan) increased
to US$1,102 million (2016: US$983.4 million). From continuing
operations (excluding Pakistan), sales revenue increased to
US$1,043.1 million from US$937.0 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$455.4 million for
2017, compared to US$412.7 million for 2016.
Operating Costs 2017 2016
$ million $ million
------------------------------------ ----------- -----------
Continuing operations 438.4 402.7
------------------------------------ ----------- -----------
Discontinuing operations (Pakistan) 9.6 10.1
------------------------------------ ----------- -----------
Operating costs 448.0 412.8
------------------------------------ ----------- -----------
Operating costs per barrel 16.4 15.8
------------------------------------ ----------- -----------
Amortisation and depreciation of oil
and gas properties 2017 2016
$ million $ million
----------------------------------------- ----------- -----------
Continuing operations 409.0 318.3
----------------------------------------- ----------- -----------
Discontinuing operations (Pakistan) 7.2 13.9
----------------------------------------- ----------- -----------
Total 416.2 332.2
----------------------------------------- ----------- -----------
Depreciation, depletion and amortisation
('DD&A') per barrel 15.2 12.7
----------------------------------------- ----------- -----------
The increase in absolute operating costs reflects a full year
contribution from the former E.ON assets and the Solan field.
Ongoing cost reduction initiatives, successful contract
renegotiations and strict management of discretionary spend
continue to deliver low and stable operating costs. On a per barrel
basis, operating costs increased by 4 per cent due to portfolio mix
effects in the production base.
The DD&A charge has increased to US$15.2 per barrel
reflecting the accelerated DD&A charge attributable to Solan in
the UK.
Impairment of oil and gas properties
A non-cash net impairment charge of US$252.2 million (pre-tax)
(US$170.9 million post-tax) has been recognised in the income
statement. This relates principally to the Solan field in the UK
North Sea as a result of a reduction in the 2P reserves expected to
be recovered from the asset over its economic life, partially
offset by the recognition of a reversal of impairment for the
Huntington asset in the UK. The reversal of impairment is
principally caused by a 12 month extension in the life of the asset
and a reduction in the lease rate payable for the FPSO. After
recognition of the net impairment charge there is US$2,381.0
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$17.1 million (2016: US$58.5 million). After recognition of
these expenditures, the exploration and evaluation assets remaining
on the balance sheet at 31 December 2017 amount to US$1,061.9
million, principally for the Sea Lion and Tolmount assets, as well
as our share of drilling costs for the Zama prospect in Mexico.
General and administrative expenses
Net G&A costs of US$16.8 million (2016: US$24.1 million)
reduced year-on-year. 2016 included E.ON's unallocated G&A
costs which fell significantly post integration of the E.ON
operations into the Group's UK business unit. Underlying gross
G&A has fallen in 2017 and is broadly in line with 2015
levels.
Finance gains and charges
Finance costs, other finance expenses and losses of US$329.0
million, have increased compared to the prior year (US$258.8
million), principally due to a step up in the interest margin on
our financing facilities following the completion of the
refinancing.
Taxation
The Group's total tax credit for 2017 is US$96.1 million (2016:
US$522.6 million restated for the exclusion of the Pakistan
business unit) which comprises a current tax charge for the period
of US$74.8 million and a non-cash deferred tax credit for the
period of US$170.9 million.
The total tax charge represents an effective tax rate of 26.2
per cent (2016: 126.3 per cent). The low effective tax rate for the
year is primarily impacted by two UK specific deferred tax items.
The first is the impact of ring fence expenditure supplement claims
in the UK during the year (US$69.1 million credit) and the second
is the element of the UK impairment charge for the year that does
not attract a deferred tax offset (US$19.6 million charge). After
adjusting for the net impact of the above items of US$49.5 million,
the underlying Group tax charge for the period is a credit of
US$145.6 million and an effective tax rate of 40 per cent.
The Group has a net deferred tax asset of US$1,297.5 million at
31 December 2017 (2016: US$1,111.4 million). The increase in
deferred tax asset primarily arises due to new UK tax losses and
allowances generated in the year. The Group continues to recognise
its deferred tax assets in respect of UK tax losses and allowances
in full.
Loss after tax
Loss after tax is US$253.8 million (2016: profit of US$122.6
million) resulting in a basic loss per share of 49.4 cents from
continuing and discontinued operations (2016: earning of 24.0
cents). The loss after tax in the year is driven by the non-cash
impairment charges recognised and the one-time fees expensed in
relation to the Group's refinancing, partially offset by the gain
on disposal of the Wytch Farm interests.
Cash flows
Cash flow from operating activities was US$496.0 million (2016:
US$431.4 million) after accounting for tax payments of US$69.6
million (2016: US$60.9 million). The increase in operating cash
flows was largely driven by higher production and sales
volumes.
Capital expenditure in 2017 totalled US$275.6 million (2016:
US$662.6 million).
Capital expenditure 2017 2016
$ million $ million
---------------------------- ----------- -----------
Fields/development projects 236.8 533.1
---------------------------- ----------- -----------
Exploration and evaluation 37.6 126.6
---------------------------- ----------- -----------
Other 1.2 2.9
---------------------------- ----------- -----------
Total 275.6 662.6
---------------------------- ----------- -----------
The principal development project was the Catcher field in the
UK and the majority of exploration spend was related to the
drilling programme on the Zama prospect in Mexico. In addition,
cash expenditure for decommissioning activity in the period was
US$25.7 million. Further to this, US$16.7 million of cash was
placed into long-term abandonment escrow accounts for future
decommissioning activities.
In 2018 development and exploration spend is expected to be
around US$300 million, of which US$170 million relates to the
Catcher development (including a one off contractual first oil
payment made to the FPSO provider BW Offshore) and US$45 million to
exploration. Capex will be weighted to the first half of 2018 as
spending on the Catcher project completes with the drilling
programme on the asset due to finish by the end of the third
quarter. Abandonment spend is expected to be approximately US$80
million in 2018, before taking into account the benefits of cost
recovery and tax relief.
Discontinued operations, disposals and assets held for sale
During the year, Premier signed a share purchase agreement 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 cash deposit to Premier of US$25.0 million.
The disposal of the Pakistan business unit is expected to
complete in 2018 and, as this is within 12 months of the balance
sheet date, the business unit has been classified as a disposal
group held for sale and presented separately in the balance sheet.
Results for the disposal group in both the current and prior
periods have been presented as a discontinued operation. Profit
after tax for the business unit for the year is US$16.4 million
(2016: US$22.7 million). Assets and liabilities held for sale in
relation to the Pakistan disposal group are US$52.2 million and
US$25.4 million, respectively.
In September 2017, Premier entered into a sale and purchase
agreement to sell its entire interests in Licences PL089 and P534,
which contain the Wytch Farm field ('Wytch Farm'), to Verus
Petroleum SNS Limited ('Verus') for a cash consideration of US$200
million, subject to certain customary financial adjustments. The
disposal included the additional 3.71 per cent equity interest
Premier acquired in September 2017 for US$9.8 million.
The disposal was subject to the pre-emption rights of existing
joint venture partners and Premier subsequently received
notification from Perenco UK Limited ('Perenco') of its intention
to exercise those rights. Therefore, in November 2017, Premier
entered into a sale and purchase agreement with Perenco on
materially the same terms as those agreed with Verus.
The disposal to Perenco completed in December 2017, with Premier
receiving final cash consideration, after working capital
adjustments, of US$177.1 million. This resulted in a gain on
disposal of US$133.0 million and enabled Premier to release letters
of credit totalling approximately US$75 million which had been
issued in relation to future decommissioning liabilities that were
transferred as part of the disposal.
In December 2017, Premier entered into separate sale and
purchase agreements ('SPAs') to dispose of its entire equity
interest in the ETS pipeline in the UK for total consideration of
US$31.6 million (including a potential future payment of US$3.5
million linked to the future development of the Pegasus field) and
its entire non-operated interest in the Kakap field in Indonesia
for US$3.2 million. The assets and liabilities for both of these
interests have been classified as assets held for sale in the
balance sheet at 31 December 2017.
Refinancing
In July 2017, Premier completed a comprehensive refinancing of
its debt facilities with the lenders under the Company's Revolving
Credit Facility ('RCF'), Term Loan, Schuldschein ('SSL') and US
Private Placement ('USPP') notes (together the 'Private Lenders'),
the retail bonds and the convertible bonds. Completion of the
refinancing provides a solid foundation for Premier to deliver its
strategic plans by preserving the Group's debt facilities,
resetting financial covenant headroom and extending maturities to
2021 and beyond.
During the year it was determined that the refinancing
represented a substantial modification of the terms of the USPPs,
the SSL and the convertible bonds. Accordingly, extinguishment
accounting has been applied for the USPPs, SSL and convertible
bonds, resulting in the de-recognition of the carrying amount of
the financial liability and the recognition of a new financial
liability for each of these revised facilities at their fair value.
The de-recognition includes costs in relation to the refinancing of
US$83.7 million.
Furthermore, it was determined that the refinancing did not
represent a substantial modification of the terms of the RCF, the
Term Loan or the retail bonds. Therefore refinancing costs in
relation to the RCF, the Term Loan and the retail bonds of US$121.6
million have been deducted from the carrying amount of these
financial liabilities in the balance sheet. These costs, along with
previous unamortised arrangement fees, will be amortised over the
revised term of these facilities.
The total refinancing costs include the recognition of the USPP
make-whole adjustment, amendment and adviser fees, including the
recognition of the equity and synthetic warrants at fair value. In
connection with the refinancing, Premier issued 71.0 million equity
warrants and 21.4 million synthetic warrants to its Private Lenders
and retail bondholders and 18.1 million equity warrants to its
convertible bondholders in July 2017. At issue the equity warrants
had an exercise price of 42.75 pence and are exercisable from their
issuance until 31 May 2022. The fair value liability for the equity
and synthetic warrants recognised on the date of issue was US$47.7
million. Prior to the end of the year, 13.9 million equity warrants
had been exercised by warrant holders. The closing fair value at 31
December 2017 was US$59.8 million.
Balance sheet position
Net debt
Net debt at 31 December 2017 amounted to US$2,724.2 million (31
December 2016: US$2,765.2 million), with cash resources of US$365.4
million (31 December 2016: US$255.9 million). With the refinancing
completed, the maturity of all of Premier's facilities has been
extended to May 2021, except for the convertible bonds which are
May 2022. Therefore, all of Premier's facilities have been
classified as long-term debt on the year-end balance sheet.
At 31 December 2017, Premier retained significant cash of
US$297.2 million, once cash of US$68.2 million held on behalf of
our joint venture partners is excluded, and undrawn facilities of
US$244.0 million, giving Liquidity of US$541.2 million (31 December
2016: US$592.9 million).
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.
Provisions
The Group's decommissioning provision increased to US$1,432.1
million at 31 December 2017, up from US$1,325.3 million at the end
of 2016. The increase is driven by the addition of provisions
relating to the new Catcher field.
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, Free Cash
Flow, DD&A per barrel, Net Debt and Liquidity and are defined
in the glossary.
Financial risk management
Commodity prices
At 31 December 2017, the Group had 3.6 mmbbls of open oil swaps
at an average price of US$55.9/bbl. The fair value of these oil
swaps at 31 December 2017 was a liability of US$31.7 million (2016:
liability of US$18.3 million), which is expected to be released to
the income statement during 2018 as the related barrels are lifted.
Furthermore, during the year, the Group paid total premiums of
US$6.3 million to enter into oil option agreements for 2.9 mmbls at
an average price of US$53.5/bbl. Out of these options, 1.1 mmbls
expired in 2017 and 1.8 mmbls will mature during 2018 and are an
asset on the Group's balance sheet with a fair value at 31 December
2017 of US$0.2 million (2016: asset of US$3.5 million). Included
within physically delivered oil sales contracts are a further 1.8
mmbls of oil that will be sold for an average fixed price of
US$54.6/bbl during 2018 as these barrels are delivered.
During 2017, forward oil swaps of 1.5 mmbbls expired resulting
in a net charge of US$11.4 million (2016: US$104.9 million credit)
which has been included in sales revenue for the year.
Foreign exchange
Premier's functional and reporting currency is US dollars.
Exchange rate exposures relate only to local currency receipts, and
expenditures within individual business units. Local currency needs
are acquired on a short-term basis. At the year-end, the Group
recorded a mark-to-market gain of US$28.2 million on its
outstanding foreign exchange contracts (2016: loss of US$58.6
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. As at year-end, 51 per cent of total
borrowings are fixed or has been fixed using the interest rate swap
markets. On average, the cost of drawn funds for the year was 7.3
per cent. Mark-to-market credits on interest rate swaps amounted to
US$4.6 million (2016: credit of US$1.0 million).
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
2017, US$7.2 million of cash proceeds were received (net to
Premier) in relation to settled insurance claims.
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.
As part of the refinancing completed in 2017, the Group amended
its financial covenants. These progressively tighten over the next
12 months with the Net Debt/EBITDA and EBITDA/Interest covenants
returning to 3.0x for the twelve months ended 31 March 2019. At
year-end, the Group continued to have significant liquidity and
headroom on the financial covenants within its borrowing
facilities. The Group's forecasts show that, at currently observed
oil and gas prices and prevailing production, the Group will have
sufficient financial headroom for the 12 months from the date of
approval of the 2017 Annual Report and Financial Statements. In
downside scenarios, where oil and gas prices were to fall and
remain significantly below those currently being realised or
production levels were to be significantly below current
performance then in the absence of any mitigating actions, a breach
of one or more of the financial covenants might arise outside of
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 existing assets.
-- Failure of new Catcher asset to fully deliver to expectations.
-- Execution of planned corporate actions.
-- Ability to fund existing and planned growth projects.
-- Breach of new banking covenants if oil prices fall or assets underperform.
-- Ability to maintain core competencies.
-- Timing and uncertainty of decommissioning liabilities.
-- 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 2017
2017 2016
$ million $ million
--------------------------------------- ------------ ------------
Restated
(1)
Continuing operations
Sales revenues 1,043.1 937.0
Other operating income/costs 18.8 (6.1)
Costs of operation (455.4) (412.7)
Depreciation, depletion, amortisation
and impairment (667.8) (888.3)
Reduction in decommissioning
estimates - 75.7
Exploration expense and pre-licence
costs (17.1) (58.5)
Excess of fair value over costs
of acquisition - 228.5
Costs related to the acquisition
of subsidiaries - (21.6)
Profit on disposal of non-current 129.0 -
assets
General and administration
costs (16.8) (24.1)
--------------------------------------- ------------ ------------
Operating profit/(loss) 33.8 (170.1)
Interest revenue, finance and
other gains 12.6 15.0
Finance costs, other finance
expenses and losses (329.0) (258.8)
Loss on substantial modification (83.7) -
Loss before tax from continuing
operations (366.3) (413.9)
Tax 96.1 522.6
--------------------------------------- ------------ ------------
(Loss)/profit for the year
from continuing operations (270.2) 108.7
--------------------------------------- ------------ ------------
Discontinued operations
Profit for the year from discontinued
operations 16.4 13.9
--------------------------------------- ------------ ------------
(Loss)/profit after tax (253.8) 122.6
--------------------------------------- ------------ ------------
(Loss)/earnings per share (cents):
From continuing operations
Basic (52.6) 21.3
Diluted (52.6) 20.8
--------------------------------------- ------------ ------------
From continuing and discontinued
operations
Basic (49.4) 24.0
Diluted (49.4) 23.5
--------------------------------------- ------------ ------------
(1) Restated for the classification of the Pakistan business
unit as a discontinued operation and certain line items to match
current year classification
Consolidated Statement of Comprehensive Income
For the year ended 31 December 2017
2017 2016
$ million $ million
-------------------------------------- ------------ ------------
Restated
(1)
(Loss)/profit for the year (253.8) 122.6
Cash flow hedges on commodity
swaps:
Losses arising during the year (25.6) (38.3)
Less: reclassification adjustments
for losses (gains) in the year 11.4 (92.4)
-------------------------------------- ------------ ------------
(14.2) (130.7)
Cash flow hedges on interest
rate and foreign exchange swaps:
(Losses)/gains arising during
the year (33.9) 60.9
Less: reclassification adjustments
for losses / (gains) in the
year 23.1 (57.6)
-------------------------------------- ------------ ------------
(10.8) 3.3
Tax relating to components
of other comprehensive income 7.5 56.1
Exchange differences on translation
of foreign operations (4.9) 3.0
Gains on long-term employee
benefit plans(2) - 0.2
-------------------------------------- ------------ ------------
Other comprehensive expense (22.4) (68.1)
-------------------------------------- ------------ ------------
Total comprehensive (expense)/income
for the year (276.2) 54.5
-------------------------------------- ------------ ------------
(1) Restated for the classification of the Pakistan business
unit as a discontinued operation
(2) Only item above not expected to be reclassified subsequently
to profit and loss account
All comprehensive income is attributable to the equity holders
of the parent.
Consolidated Balance Sheet
As at 31 December 2017
2017 2016
$ million $ million
---------------------------------- ------------ ------------
Non-current assets:
Intangible exploration and
evaluation assets 1,061.9 1,011.4
Property, plant and equipment 2,381.0 2,726.2
Goodwill 240.8 240.8
Long-term receivables 160.8 149.6
Deferred tax assets 1,461.5 1,304.0
---------------------------------- ------------ ------------
5,306.0 5,432.0
---------------------------------- ------------ ------------
Current assets:
Inventories 13.5 22.3
Trade and other receivables 340.6 315.1
Derivative financial instruments 14.5 34.9
Cash and cash equivalents 365.4 255.9
Assets held for sale 96.6 -
---------------------------------- ------------ ------------
830.6 628.2
---------------------------------- ------------ ------------
Total assets 6,136.6 6,060.2
---------------------------------- ------------ ------------
Current liabilities:
Trade and other payables (572.9) (412.6)
Short-term provisions (91.2) (56.1)
Derivative financial instruments (99.8) (57.2)
Short-term debt - (273.0)
Deferred income (13.1) (27.3)
Liabilities directly associated
with assets held for sale (46.6) -
---------------------------------- ------------ ------------
(823.6) (826.2)
---------------------------------- ------------ ------------
Net current assets/(liabilities) 7.0 (198.0)
---------------------------------- ------------ ------------
Non-current liabilities:
Long-term debt (2,972.6) (2,730.5)
Deferred tax liabilities (164.0) (192.6)
Deferred income (80.3) (88.1)
Derivative financial instruments (108.3) (101.6)
Long-term provisions (1,370.9) (1,312.1)
---------------------------------- ------------ ------------
(4,696.1) (4,424.9)
---------------------------------- ------------ ------------
Total liabilities (5,519.7) (5,251.1)
---------------------------------- ------------ ------------
Net assets 616.9 809.1
---------------------------------- ------------ ------------
Equity and reserves:
Share capital 109.0 106.7
Share premium account 284.5 275.4
Other reserves 223.4 427.0
---------------------------------- ------------ ------------
616.9 809.1
---------------------------------- ------------ ------------
Consolidated Statement of Changes in Equity
For the year ended 31 December 2017
Share
Share premium Other
capital account reserves Total
$ million $ million $ million $ million
-------------------------- ---------- ---------- ---------- ----------
At 1 January 2016 106.7 275.4 352.6 734.7
Purchase of ESOP
Trust shares - - 0.2 0.2
Provision for share-based
payments - - 19.7 19.7
Profit for the year - - 122.6 122.6
Other comprehensive
expense - - (68.1) (68.1)
-------------------------- ---------- ---------- ---------- ----------
At 1 January 2017 106.7 275.4 427.0 809.1
Issue of Ordinary
Shares 2.3 9.1 1.1 12.5
Net release 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
-------------------------- ---------- ---------- ---------- ----------
Consolidated Cash Flow Statement
For the year ended 31 December 2017
2017 2016
$ million $ million
------------------------------------------- ----------- -----------
Restated
(1)
Net cash from operating activities 496.0 431.4
------------------------------------------- ----------- -----------
Investing activities:
Capital expenditure (275.6) (662.6)
Acquisition of subsidiaries - (135.0)
Cash balance acquired in the period - 24.9
Decommissioning pre-funding (16.7) (62.3)
Decommissioning expenditure (25.7) (15.5)
Proceeds from disposal of oil and gas
properties 202.3 (8.8)
Net cash used in investing activities (115.7) (859.3)
------------------------------------------- ----------- -----------
Financing activities:
Issuance of Ordinary shares 0.8 -
Net (release) / purchase of ESOP Trust
shares (0.2) 0.2
Proceeds from drawdown of long-term bank
loans 45.0 435.0
Debt arrangement fees (86.0) (26.3)
Interest paid (223.7) (126.3)
------------------------------------------- ----------- -----------
Net cash from financing activities (264.1) 282.6
------------------------------------------- ----------- -----------
Currency translation differences relating
to cash and cash equivalents (6.7) (0.1)
------------------------------------------- ----------- -----------
Net increase / (decrease) in cash and
cash equivalents 109.5 (145.4)
------------------------------------------- ----------- -----------
Cash and cash equivalents at the beginning
of the year 255.9 401.3
------------------------------------------- ----------- -----------
Cash and cash equivalents at the end
of the year 365.4 255.9
------------------------------------------- ----------- -----------
(1) Restated for certain line items to match current year
classification
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the year ended 31 December 2017
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 7 March 2018.
The financial information for the year ended 31 December 2017
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 2016 were
approved by the Board of Directors on 8 March 2017 and delivered to
the Registrar of Companies and those for 2017 will be delivered
following the company's Annual General Meeting ('AGM'). The auditor
has reported on the 2017 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 2017.
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 this announcement are
consistent with those of the annual financial statements for the
year ended 31 December 2016, as described in those annual financial
statements. A number of amendments to existing standards and
interpretations were applicable from 1 January 2017. The adoption
of these amendments did not have a material impact on the Group's
financial statements for the year ended 31 December 2017.
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. The results for Mauritania
have been reclassified into the Rest of the World business
unit.
Some of the business units currently do not generate revenue or
have any material operating income.
The Group is engaged in one business of upstream oil and gas
exploration and production.
2017 2016
$ million $ million
----------------------------------------------- ----------- -------------
Restated
Revenue:
Indonesia 171.8 141.1
Vietnam 210.7 192.0
United Kingdom 655.9 598.0
Rest of the World 4.7 5.9
Total Group sales revenue 1,043.1 937.0
Other operating income - United Kingdom 18.8 -
Interest and other finance revenue 1.7 0.7
----------------------------------------------- ----------- -------------
Total Group revenue from continuing operations 1,063.6 937.7
----------------------------------------------- ----------- -------------
Group operating profit/(loss):
Indonesia 65.3 35.6
Vietnam 82.6 86.3
United Kingdom (86.4) (225.0)
Rest of the World (5.0) (32.2)
Unallocated (2) (22.7) (34.8)
----------------------------------------------- ----------- -------------
Group operating profit/(loss) 33.8 (170.1)
Interest revenue, finance and other gains 12.6 15.0
Finance costs and other finance expenses (329.0) (258.8)
Loss on substantial modification (83.7) -
----------------------------------------------- ----------- -------------
Loss before tax from continuing operations (366.3) (413.9)
Tax 96.1 522.6
----------------------------------------------- ----------- -------------
(Loss)/profit after tax from continuing
operations (270.2) 108.7
----------------------------------------------- ----------- -------------
Profit from discontinued operations 16.4 13.9
----------------------------------------------- ----------- -------------
Balance sheet
Segment assets:
Falkland Islands 633.1 642.9
Indonesia 440.4 480.2
Pakistan (including Mauritania) - 44.8
Vietnam 374.4 399.0
United Kingdom 4,116.2 4,136.5
Rest of the World 96.0 66.0
Assets held for sale 96.6 -
Unallocated(2) 379.9 290.8
Total assets 6,136.6 6,060.2
----------------------------------------------- ----------- -------------
Liabilities:
Falkland Islands (8.2) (45.6)
Indonesia (223.9) (244.5)
Pakistan (including Mauritania) - (76.3)
Vietnam (203.4) (202.1)
United Kingdom (1,802.1) (1,516.8)
Rest of the World (54.8) (3.5)
Liabilities directly associated with assets
held for sale (46.6) -
Unallocated(2) (3,180.7) (3,162.3)
----------------------------------------------- ----------- -----------
Total liabilities (5,519.7) (5,251.1)
----------------------------------------------- ----------- -----------
Other information
Capital additions and acquisitions:
Falkland Islands 12.9 59.2
Indonesia 7.4 (2.7)
Pakistan (including Mauritania) 10.5 0.9
Vietnam 20.2 (7.4)
United Kingdom 444.3 1,247.7
Rest of the World 25.3 26.4
----------------------------------------------- ----------- -----------
Total capital additions and acquisitions 520.6 1,324.1
----------------------------------------------- ----------- -----------
Depreciation, depletion, amortisation
and impairment:
Indonesia 57.2 52.7
Vietnam 64.5 45.0
United Kingdom 542.9 790.4
Rest of the World 3.2 0.2
----------------------------------------------- ----------- -----------
Total DD&A and impairment (continuing
operations) 667.8 888.3
----------------------------------------------- ----------- -----------
Total DD&A and impairment (discontinued
operations) 7.3 8.2
----------------------------------------------- ----------- -----------
1 Segmental income, assets, liabilities and capital addition as
for Mauritania have been included within the Rest of the World for
the current year.
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, convertible bonds, warrants and other
short-term and long-term debt.
3 DD&A for the Pakistan business unit was charged until 30
June 2017, which was the date of reclassification of an asset held
for sale.
Out of the total Group worldwide sales revenues of US$1,043.1
million (2016: US$937.0 million restated), revenues of US$655.9
million (2016: US$598.0 million) arose from sales of oil and gas to
customers located in the UK.
Included in assets arising from the United Kingdom segment are
non-current assets (excluding deferred tax assets) of US$2,455.7
million (2016: US$2,640.6 million) located in the UK. Included in
depreciation, depletion, amortisation and impairment are net
impairment charges in relation to the UK of US$252.2 million (2016:
US$587.9 million).
Revenue from three customers (2016: three customers) each
exceeded 10 per cent of the Group's consolidated revenue and
amounted to US$240.3 million arising from sales of crude oil (2016:
two customers amounting to US$155.4 million and US$157.4 million)
and US$121.4 million and US$168.3 million arising from sales of gas
(2016: one customer US$112.0 million).
3. Cost of operation
2017 2016
$ million $ million
---------------------------------- ----------- -----------
Restated(1)
Operating costs 438.4 402.7
Gas purchases 5.5 12.4
Stock overlift/underlift movement 1.3 (12.1)
Royalties 10.2 9.7
455.4 412.7
---------------------------------- ----------- -----------
(1 Restated for the classification of the Pakistan business unit
as a discontinued operation)
4. Tax
The tax credit for the year can be reconciled to the profit per
the consolidated income statement as follows:
2017 2016
$ million $ million
------------------------------------------------ ----------- -----------
Restated(1)
Current tax:
UK corporation tax on profits (0.8) (3.0)
UK petroleum revenue tax (8.2) (0.8)
Overseas tax 75.6 44.6
Adjustments in respect of prior years 8.2 0.7
------------------------------------------------ ----------- -----------
Total current tax 74.8 41.5
------------------------------------------------ ----------- -----------
Deferred tax:
UK corporation tax (146.2) (544.4)
UK petroleum revenue tax - (14.4)
Overseas tax (24.7) (5.3)
------------------------------------------------ ----------- -----------
Total deferred tax (170.9) (564.1)
------------------------------------------------ ----------- -----------
Tax on (loss) on ordinary activities (96.1) (522.6)
------------------------------------------------ ----------- -----------
Group loss on ordinary activities before
tax (366.3) (413.9)
------------------------------------------------ ----------- -----------
Group loss on ordinary activities before
tax at 29.1 per cent weighted average
rate (2016: 58.1 per cent) (106.6) (240.6)
Tax effects of:
Income/expenses that are not taxable/deductible
in determining taxable profit 40.6 9.4
Financing costs disallowed for UK supplementary
charge 16.4 14.4
Non-deductible field expenditure 36.1 63.2
Tax and tax credits not related to profit
before tax (mainly Ring Fenced Expenditure
Supplement) (69.9) (60.7)
Unrecognised tax losses 6.1 2.8
Adjustments in respect of prior years (3.2) 8.6
Utilisation and recognition of tax losses
not previously recognised (0.8) (392.5)
Effect of change in tax rates (0.5) 161.5
Recognition that decommissioning provision
will unwind at 50% (14.3) (27.1)
Recognition of investment allowances not
previously recognised - (61.6)
Tax credit for the year (96.1) (522.6)
------------------------------------------------ ----------- -----------
Effective tax rate for the year 26.2% 126.3%
------------------------------------------------ ----------- -----------
1 Restated for the classification of the Pakistan business unit
as a discontinued operation
The deferred tax credit primarily arises due to UK specific
deferred tax items. This includes the deferred tax credit
associated with the UK impairment charge for the period (US$101.8
million), which is partially offset by an element of the UK
impairment charge for the year that does not attract a deferred tax
offset (US$19.6 million). This also includes the deferred tax
credit which arises on the generation of new UK ring fence tax
losses, allowances and ring fence expenditure supplement which are
recognised in full for deferred tax purposes.
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 20 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
2017 2016
$ million $ million
------------------------------------------ ----------- -----------
Net profit for the year attributable
to Pakistan business unit 16.4 22.7
Completion of disposal of Norway
business unit - (8.8)
------------------------------------------ ----------- -----------
Net profit for the year from discontinued
operations 16.4 13.9
------------------------------------------ ----------- -----------
The disposal of the Norway business unit completed in December
2015
2017
$ million
----------------------------------------- ----------
Assets held for:
- Pakistan business unit 52.2
- Esmond Transportation System ('ETS') 27.0
- Kakap field 17.4
----------------------------------------- ----------
Total assets classified as held for sale 96.6
----------------------------------------- ----------
Liabilities held for:
- Pakistan business unit (25.4)
- Esmond Transportation System ('ETS') (7.0)
- Kakap field (14.2)
----------------------------------------- ----------
Total liabilities classified as held for
sale (46.6)
----------------------------------------- ----------
Disposals - Wytch Farm interests
The disposal completed in December 2017, with Premier receiving
final cash consideration, after working capital adjustments, of
US$177.1 million. This resulted in a gain on disposal of US$133.0
million.
Assets held for sale
ETS
In December 2017, Premier signed an SPA to sell its entire
equity interest in the ETS pipeline to CATS Management Limited and
the disposal is expected to be completed within the next 12 months.
Therefore, the assets and liabilities for Premier's ETS interest
have been classified as assets held for sale in the balance sheet
at 31 December 2017, as the disposal is expected to complete within
the next 12 months. An impairment charge has not been recognised at
the time of this reclassification, as the initial upfront
consideration of US$28.1 million is greater than the carrying value
of the ETS assets and liabilities held on Premier's Group balance
sheet.
Kakap
In December 2017, Premier signed an SPA with Batavia Oil to sell
its entire 18.75 per cent non-operated interest in the Kakap field
for a consideration of US$3.2 million. Completion is subject to
receiving approval from the Government of Indonesia. Completion is
expected to be achieved within the next 12 months, therefore, the
assets and liabilities for Kakap have been classified as assets
held for sale in the balance sheet at 31 December 2017. On
reclassification an impairment charge of US$4.2 million has been
recognised so that the carrying value of Premier's interest in the
Kakap field is equal to the agreed consideration. This charge has
been recognised in the income statement against the gain on
disposal recognised for Wytch Farm.
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. In 2017, Al-Haj paid a deposit to Premier of US$25.0
million.
The disposal of the Pakistan business unit is expected to
complete in 2018 and, as this is within 12 months of the balance
sheet date, the business unit was classified as a disposal group
held for sale on 30 June 2017 and presented separately in the
balance sheet.
The results of the disposal group which have been included as
discontinued operations in the consolidated income statement were
as follows:
2017 2016
$ million $ million
------------------------------- ----------- -----------
Revenue 40.8 46.4
Expenses (22.4) (23.1)
------------------------------- ----------- -----------
Profit before tax 18.4 23.3
------------------------------- ----------- -----------
Attributable tax (charge) (2.0) (0.6)
------------------------------- ----------- -----------
Net profit for the period from
assets held for sale 16.4 22.7
------------------------------- ----------- -----------
During the year to 31 December 2017, the Pakistan disposal group
contributed US$16.8 million (2016 US$29.4 million) to the Group's
net operating cash flows and paid US$6.8 million (2016 US$8.5
million in respect of investing activities). There were no
financing cash flows in either the current or the prior years. The
major classes of assets and liabilities comprising the disposal
group classified as held for sale are as follows:
2017
$ million
----------------------------------- ----------
Property, plant and equipment 23.3
Long-term receivables 0.4
Deferred tax asset 0.8
Inventory 9.0
Trade and other receivables 17.8
Cash 0.9
----------------------------------- ----------
Pakistan assets classified as held
for sale 52.2
----------------------------------- ----------
Trade and other payables (7.8)
Long-term provisions (17.6)
----------------------------------- ----------
Pakistan liabilities classified
as held for sale (25.4)
----------------------------------- ----------
Net assets of disposal group 26.8
----------------------------------- ----------
Following completion of the disposal, Premier have retained a
provision of US$16.4 million in relation to 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. (Loss)/earnings per share
The calculation of basic (loss)/earnings per share is based on
the (loss) / profit after tax and on the weighted average number of
Ordinary Shares in issue during the year. Basic and diluted (loss)
/ earnings per share are calculated as follows:
2017 2016
$ million $ million
---------------------------------------------- ----------- -----------
Restated(1)
Loss/(earnings)
Loss/earnings from continuing operations (270.2) 108.7
Effect of dilutive potential Ordinary
Shares:
Interest on convertible bonds - anti-dilutive - -
----------- -----------
(Loss)/earnings for the purpose of diluted
(loss)/earnings per share on continuing
operations (270.2) 108.7
Profit from discontinued operations 16.4 13.9
(Loss)/earnings for the purposes of diluted
(loss)/earnings per share on continuing
and discontinued operations (253.8) 122.6
---------------------------------------------- ----------- -----------
Number of shares (millions)
Weighted average number of Ordinary Shares
for the purposes of basic earnings per
share 513.7 510.8
Effects of dilutive potential Ordinary
Shares:
Contingently issuable shares - anti-dilutive - -
---------------------------------------------- ----------- -----------
Weighted average number of Ordinary Shares
for the purposes of diluted earnings
per share 612.0 523.5
---------------------------------------------- ----------- -----------
(Loss)/earnings per share from continuing
operations (cents)
Basic (52.6) 21.3
Diluted (52.6) 20.8
---------------------------------------------- ----------- -----------
Earnings per share from discontinued
operations (cents)
Basic 3.2 2.7
Diluted 3.2 2.7
---------------------------------------------- ----------- -----------
(1 Restated for the classification of the Pakistan business unit
as a discontinued operation)
There are 98.3 million potentially dilutive contingently
issuable shares related to unexercised Equity warrants and Share
Options and the inclusion of these contingently issuable shares
gives rise to an anti-dilutive loss and earnings per share for both
continuing and discontinued operations. Furthermore, there are
259.3 million potentially dilutive shares related to the
convertible bonds at 31 December 2017. The inclusion of the
convertible bond interest and shares to be issued on conversion of
convertible bonds, also produces an anti-dilutive loss and earnings
per share for both continuing and discontinued operations.
7. Intangible exploration and evaluation ('E&E') assets
Total
Oil and Gas Properties $ million
----------------------------------------------- ----------
At 1 January 2016 749.7
Exchange movements 6.1
Additions during the year 103.8
Acquisition of subsidiaries 199.8
Exploration expense (1) (48.0)
----------------------------------------------- ----------
At 31 December 2016 1,011.4
Exchange movements (0.9)
Additions during the year 63.1
Assets classified as held for sale in the year (0.5)
Exploration expense (1) (11.2)
----------------------------------------------- ----------
At 31 December 2017 1,061.9
----------------------------------------------- ----------
1 Expensed in the income statement with pre-licence expenses of
US$5.9 million in 2017 (2016: US$10.5 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 on the Ekland
licence in the UK.
The outcome of ongoing exploration, and therefore whether the
carrying value of E&E assets will ultimately be recovered, is
inherently uncertain. To the extent that we have an active licence
to continue to explore for resources and have an intention to
continue exploration activity, the exploration cost associated with
the licence will remain capitalised as an E&E asset on the
balance sheet. Once exploration activity has completed and we have
no further intention to explore the licence for resources, costs
capitalised until that point will be expensed and no further costs
associated with the licence will be capitalised.
The balance carried forward is predominantly in relation to the
Group's prospects in the Falkland Islands and the Tolmount project
in the UK. We continue to progress both Sea Lion and Tolmount
projects and are aiming to reach an investment decision on Sea Lion
and to sanction Tolmount during 2018.
E&E assets transferred to held for sale in the year related
to the Kakap entity in Indonesia.
8. Property, plant and equipment
Oil and Other fixed
gas properties assets Total
$ million $ million $ million
=============================== =============== =========== ==========
Cost:
At 1 January 2016 7,025.7 61.4 7,087.1
Exchange movements (8.5) (4.8) (13.3)
Acquisition of subsidiaries 600.0 7.1 607.1
Additions during the year 411.4 2.0 413.4
Disposals - (1.4) (1.4)
=============================== =============== =========== ==========
At 31 December 2016 8,028.6 64.3 8,092.9
Exchange movements 4.6 2.4 7.0
Additions during the year 445.4 2.3 447.7
Asset acquisition 9.8 - 9.8
Assets transferred 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
=============================== =============== =========== ==========
Amortisation and depreciation:
At 1 January 2016 4,430.9 44.5 4,475.4
Exchange movements (0.4) (3.4) (3.8)
Charge for the year 332.2 8.1 340.3
Net impairment charge 556.2 - 556.2
Disposals - (1.4) (1.4)
=============================== =============== =========== ==========
At 31 December 2016 5,318.9 47.8 5,366.7
Exchange movements (0.3) 1.8 1.5
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 54.8 5,275.1
=============================== =============== =========== ==========
Net book value:
At 31 December 2016 2,709.7 16.5 2,726.2
=============================== =============== =========== ==========
At 31 December 2017 2,369.1 11.9 2,381.0
=============================== =============== =========== ==========
Finance costs that have been capitalised within oil and gas
properties during the year total US$41.3 million (2016: US$34.0
million), at a weighted average interest rate of 7.3 per cent
(2016: 4.6 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 UK
fields and predominantly comprises of Solan (US$268.1 million), the
Balmoral Area (US$20.7 million) and Glenelg (US$7.4 million). The
impairment charge of US$296.6 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 an oil price assumption equal to the Dated Brent
forward curve in 2018 and 2019, US$70/bbl in 2020 and US$75/bbl in
'real' terms thereafter (2016: two years at forward curve, year
three at US$65/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 (2016: 8 per cent) and 12.5 per cent for the
non-UK assets (2016: 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 is a reduction in the 2P reserves expected to be recovered
from Solan over its economic life, a reduction in the expected
residual value of the Balmoral Area FPV and a delayed workover for
Glenelg. The recoverable amount of the impaired assets based on the
value-in-use assumptions set out above is US$246.1 million (Solan),
US$18.6 million (Balmoral) and US$35.0 million (Glenelg). The
recoverable amount for Glenelg assumes that a workover of the G10
well is performed in 2019 which is management's current
expectations based on discussions with the operator. If the
workover is delayed or not performed, it is likely to reduce the
recoverable amount of the asset, which would have the effect of
increasing the impairment charge.
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$44.4 million has been credited to
the income statement for the year, which has partially offset the
impairment charge recognised. The reversal of impairment relates
entirely to Huntington in the UK. An increase in the short term oil
price assumption and an increase in the life of the field have
driven the increase in the value-in-use. The recoverable amount of
Huntington at 31 December 2017 was US$78.8 million.
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 further impairment charge of approximately US$8.3
million. A US$5/bbl reduction in the long-term oil price (to
US$70/bbl (real)) would increase the impairment charge by
approximately US$41.2 million. The value of the reversal of
impairment recognised in the year would be unaffected by either an
increase in the discount rate by 1 per cent or a reduction in the
long-term oil price assumption to US$70/bbl (real).
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
(2016: 8 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 2025. 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$305.7 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 the 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$22.0 million during the year reflecting barrels
delivered to FlowStream and a credit to finance costs of US$6.8
million. The finance credit is due to a revision in the settlement
profile of the deferred income balance following the revision to
Solan reserves. 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:
2017 2016
$ million $ million
============================= ============================
Carrying Fees Total Carrying Fees Total
value value
=================== ========= ======== ======== ========= ======= ========
Bank loans 2,165.0 (106.9) 2,058.1 2,108.0 (12.1) 2,095.9
Senior loan notes 541.6 - 541.6 491.1 (3.7) 487.4
Retail bonds 202.5 (10.1) 192.4 184.5 (1.7) 182.8
Convertible bonds 180.5 - 180.5 237.5 (0.1) 237.4
=================== ========= ======== ======== ========= ======= ========
Total borrowings 3,089.6 (117.0) 2,972.6 3,021.1 (17.6) 3,003.5
=================== ========= ======== ======== ========= ======= ========
Due within one
year - 273.0
Due after more
than one year 2,972.6 2,730.5
=================== ========= ======== ======== ========= ======= ========
Total borrowings 2,972.6 3,003.5
=================== ========= ======== ======== ========= ======= ========
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 Schuldschein
('SSL');
-- GBP150 million of retail bonds; and,
-- US$237.9 million of convertible bonds.
All of the above facilities mature in May 2021, except for the
convertible bonds which, for those not already converted, mature in
May 2022.
Refinancing
In July 2017, Premier completed a comprehensive refinancing of
its lending facilities with all the lenders under each
facility.
Under the requirements of IAS 39, if an existing financial
liability is replaced by another from the same lender, on
substantially different terms, or the terms of an existing
liability are substantially modified, such an exchange or
modification is treated as a de-recognition of the original
liability and the recognition of a new liability, measured at its
fair value, such that the difference in the respective carrying
amounts together with any costs or fees incurred are recognised in
profit or loss. IAS 39 regards the terms of exchanged or modified
debt as 'substantially different' if the net present value of the
cash flows under the new terms (including any fees paid net of fees
received) discounted at the original effective interest rate is at
least 10 per cent different from the discounted present value of
the remaining cash flows of the original debt instrument. Where an
exchange or modification of financial liabilities is not considered
substantial, no gain or loss is recognised, the fees are
capitalised against the carrying value of the liability and any
changes
to the cash flows are recognised as interest over the remaining
term.
After applying the 10 per cent test, as required by IAS 39, it
was determined that the refinancing amendments represented a
substantial modification of the USPP notes, the SSL and the
convertible bonds. However, the refinancing amendments did not
represent a substantial modification of the RCF, Term Loans or the
retail bond notes.
Costs and third-party fees, which include the USPP make-whole
adjustment, amendment fee and adviser fees paid and recognition of
the warrants at fair value, have been allocated to each facility as
follows:
2017
$ million
================================ ===========
Bank Loans 111.8
================================ ===========
Senior loan notes 70.2
================================ ===========
Retail bonds 9.8
================================ ===========
Convertible bonds 13.5
================================ ===========
Total costs in relation to the
refinancing 205.3
================================ ===========
Of the total fees above, US$83.7 million in relation to the
senior loan notes and convertible bonds have been expensed to the
income statement in the year. The fees in relation to the bank
loans and retail bonds of US$121.6 million have been capitalised
against the carrying value of the debt and are being amortised over
the revised maturity of the facility.
11. Notes to the cash flow statement
Analysis of changes in net debt:
2017 2016
$ million $ million
------------------------------------------------ ---------- -----------
Restated(1)
Loss before tax for the year (366.3) (413.9)
Adjustments for:
Depreciation, depletion, amortisation
and impairment 667.8 888.3
Other operating (income) / costs (18.8) 6.1
Exploration expense 11.2 48.0
Excess of fair value over consideration - (228.5)
Provision for share-based payments 8.6 8.7
Reduction in decommissioning estimates - (75.7)
Interest revenue and finance gains (12.6) (15.0)
Finance costs and other finance expenses 412.7 258.8
Profit on disposal of non-current assets (129.0) -
Operating cash flows before movements
in working capital 573.6 476.8
(Increase)/decrease in inventories (1.2) 1.3
(Increase)/decrease in receivables (161.3) 25.1
Increase/(decrease) in payables 136.6 (40.9)
------------------------------------------------ ---------- -----------
Cash generated by operations 547.7 462.3
Income taxes paid (69.6) (60.9)
Interest income received 1.1 0.6
------------------------------------------------ ---------- -----------
Net cash from operating activities 479.2 402.0
------------------------------------------------ ---------- -----------
Net cash from discontinued operating
activities 16.8 29.4
------------------------------------------------ ---------- -----------
Total net cash from operating activities 496.0 431.4
------------------------------------------------ ---------- -----------
a) Reconciliation of net cash flow to
movement in net debt:
Movement in cash and cash equivalents 109.5 (145.4)
Proceeds from drawdown of long-term bank
loans (45.0) (435.0)
USPP make-whole adjustment (41.3) -
Adjustment to revised fair value of convertible
bonds 58.6 -
Partial conversion of convertible bonds 5.5 -
Non-cash movements on debt and cash balances
(predominantly FX) (46.3) 57.4
------------------------------------------------ ---------- -----------
Decrease/(Increase) in net debt in the
year 41.0 (523.0)
Opening net debt (2,765.2) (2,242.2)
------------------------------------------------ ---------- -----------
Closing net debt (2,724.2) (2,765.2)
------------------------------------------------ ---------- -----------
b) Analysis of net debt:
Cash and cash equivalents 365.4 255.9
Borrowings (3,089.6) (3,021.1)
------------------------------------------------ ---------- -----------
Total net debt (2,724.2) (2,765.2)
------------------------------------------------ ---------- -----------
(1 Restated for the classification of the Pakistan business unit
as a discontinued operation)
The carrying amounts of the borrowings on the balance sheet are
stated net of the unamortised portion of the refinancing fees of
US$117.0 million (2016: US$17.6 million).
12. Subsequent Events
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 bonds outstanding were
accepted for early exchange with an incentive amount of US$50 per
US1,000 in principal of bonds. The exchange resulted in the issue
of 231,882,091 Ordinary Shares, including 7,578,343 of incentive
shares. It is expected that the value of the incentive shares will
be expensed in the 2018 income statement.
Equity Warrants
Subsequent to the year-end until the date of this report,
8,117,546 equity warrants have been exercised into 7,951,992
Ordinary Shares.
Debt Reduction
Net cash proceeds received for the Wytch Farm disposal of US$176
million in December 2017 were used to pay down and cancel the RCF
debt facility in January 2018. This reduced the total available RCF
facility from US$2,050 million to US$1,874 million. As a result of
this disposal US$75 million of letters of credit were released. In
addition the US$16.4 million letters of credit held for the Zama
exploration well in Mexico, which was included within the covenant
Net Debt at 31 December 2017, was also released in January
2018.
13. External audit
This preliminary announcement is consistent with the audited
financial statements of the Group for the year-ended 31 December
2017.
14. Publication of financial statements
It is anticipated that the full Annual Report and Financial
Statements will be published in April 2018. 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 2018 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, Free cash flow, 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.
-- Free cash flow: Positive cash flow generation from operating,
investing and financing activities excluding drawdowns from
borrowing facilities.
-- 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 2017
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 gas
------------------- ------ ---- ------ ------ ------ ------ ------ ------ ------ ----- ------ ------ ------
mmbbls bcf mmbbls bcf mmbbls bcf mmbbls bcf mmbbls bcf mmbbls bcf mmboe
------------------- ------ ---- ------ ------ ------ ------ ------ ------ ------ ----- ------ ------ ------
Group proved plus probable reserves:
------------------------------------------------------------------------------------------------------------------------
At 1 January
2017 126.5 43.8 1.7 243.5 0.1 74.3 103.1 136.0 23.8 35.6 255.2 533.2 353.3
------------------- ------ ---- ------ ------ ------ ------ ------ ------ ------ ----- ------ ------ ------
Revisions(1) - - 0.1 (18.1) - (8.7) (13.0) 33.7 (0.3) (3.7) (13.2) 3.3 (12.4)
------------------- ------ ---- ------ ------ ------ ------ ------ ------ ------ ----- ------ ------ ------
Discoveries
and extensions(2) - - - - - - - - - - - - -
------------------- ------ ---- ------ ------ ------ ------ ------ ------ ------ ----- ------ ------ ------
Acquisitions
and divestments(3) - - - - - - (11.2) (1.3) - - (11.3) (1.4) (11.7)
------------------- ------ ---- ------ ------ ------ ------ ------ ------ ------ ----- ------ ------ ------
Production - - (0.3) (26.0) - (14.4) (9.9) (24.0) (4.3) (5.4) (14.5) (69.7) (27.4)
------------------- ------ ---- ------ ------ ------ ------ ------ ------ ------ ----- ------ ------ ------
At 31 December
2017 126.5 43.8 1.5 199.4 0.1 51.2 69.0 144.4 19.2 26.5 216.2 465.4 301.8
------------------- ------ ---- ------ ------ ------ ------ ------ ------ ------ ----- ------ ------ ------
Total Group developed and undeveloped reserves
------------------------------------------------------------------------------------------------------------------------
Proved
on production - - 0.8 121.1 0.1 34.9 20.0 80.2 15.8 18.2 36.6 254.5 83.3
------------------- ------ ---- ------ ------ ------ ------ ------ ------ ------ ----- ------ ------ ------
Proved
approved/justified
for development 102.8 28.5 0.4 36.5 - - 21.2 26.5 0.5 6.2 124.7 97.7 143.3
------------------- ------ ---- ------ ------ ------ ------ ------ ------ ------ ----- ------ ------ ------
Probable
on production - - 0.1 9.9 - 16.3 5.6 32.4 2.8 1.7 8.6 60.3 19.1
------------------- ------ ---- ------ ------ ------ ------ ------ ------ ------ ----- ------ ------ ------
Probable
approved/justified
for development 23.7 15.3 0.2 31.9 - - 22.2 5.3 0.1 0.4 46.3 52.9 56.1
------------------- ------ ---- ------ ------ ------ ------ ------ ------ ------ ----- ------ ------ ------
At 31 December
2017 126.5 43.8 1.5 199.4 0.1 51.2 69.0 144.4 19.2 26.5 216.2 465.4 301.8
------------------- ------ ---- ------ ------ ------ ------ ------ ------ ------ ----- ------ ------ ------
Notes:
1 Revisions to reserves are based on re-evaluation of production
performance, drilling results and future plans in Dua (Vietnam);
Anoa and Gajah-Baru (Indonesia); Solan, Babbage and Huntington
(UK); Qadirpur (Pakistan)
2 The Zama discovery in Mexico is classified as contingent
resource and does not appear in this table
3 Divestment of Wytch Farm (UK)
4 Proved plus probable gas includes 95 bcf of fuel gas reserves
Premier Oil plc categorises petroleum resources in accordance
with the 2007 SPE/WPC/AAPG/SPEE 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 284.9 mmboe as at 31
December 2017 (2016: 332.3 mmboe). This was calculated at year-end
2017, using an oil price assumption equal to US$65/bbl in 2018,
US$61.5/bbl in 2019, US$70/bbl in 2020 and US$75/bbl in 'real'
terms thereafter (2016: Dated Brent, 2017 US$58/bbl, 2018
US$58/bbl, US$65/bbl in 2019 and US$75/bbl in 'real' terms
thereafter).
In 2018, it is anticipated that there will be changes to the SPE
Petroleum Resource Management System standards which are likely to
include revised commercial requirements for reserve classification.
If the Sea Lion development, which is currently booked with 2P
reserves of 134 mmboe does not pass through the Sanction Gate
currently planned during 2018, there would be potential for these
resources to be recategorised as contingent at the end of 2018.
This information is provided by RNS
The company news service from the London Stock Exchange
END
FR FKFDQDBKKNNK
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