TIDMPMO
RNS Number : 9381Y
Premier Oil PLC
09 March 2017
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Annual Results for the year ended 31 December 2016
Press Release
Tony Durrant, Chief Executive, commented:
"Premier has a robust business which continues to deliver
excellent operational performance. In 2016 we achieved record
production, maintained a low operating cost base and completed the
highly value adding acquisition of E.ON's UK upstream portfolio.
Significant progress was made on our operated Catcher project which
will deliver a further step change in our production levels once
on-stream later this year. Our complex refinancing has created
uncertainty and volatility but is now nearing completion. Looking
forward, our strong and growing cash flows will reduce our debt and
in due course allow us to invest in new projects to deliver value
for all our stakeholders."
Operational highlights
-- Record production of 71.4 kboepd, an increase of 24% on the prior
year (2015: 57.6 kboepd)
-- High operating efficiency of 91%
-- E.ON's UK upstream portfolio outperforming; payback now anticipated
in 2017 1H
-- Cost base reset; opex of $15.8/boe; Catcher capex reduced by 29%
-- 2P reserves and 2C resources increased to 835 mmboe (2015: 758 mmboe)
Financial highlights
-- Profit after tax of US$122.6 million (2015: loss after tax US$1.1
billion), including a tax credit of US$522.0 million
-- Cash flows from operations of US$431.4 million (2015: US$809.5 million)
-- Capex of US$678.1 million, significantly below budget
-- Net debt of $2.8 billion as at year-end (2015: $2.2 billion); reduced
since peak in Q3 2016
-- Cash and undrawn facilities of US$593 million
Refinancing
-- Total debt facilities preserved and maturities extended to 2021 and
beyond
-- Completion of refinancing expected by end of May, as previously guided
-- As separately announced today, RCF, Term Loan, USPP and convertible
bondholders have locked up to refinancing terms
Outlook
-- 2017 production guidance maintained at 75 kboepd, before any contribution
from Catcher
-- 2017 opex and capex guidance of <$16/boe and US$390 million, respectively
-- Catcher on schedule for 2017 first oil; improved field production
profile now anticipated
-- Greater Tolmount Area value significantly enhanced; offshore FEED
commenced
-- High impact Zama exploration prospect in Mexico to spud in Q2 2017
-- Net cash flow positive at the forward curve in 2017; debt reduction
accelerating once Catcher on-stream
ENQUIRIES
Premier Oil plc Tel: + 44 (0)20 7730 1111
Tony Durrant
Richard Rose
Bell Pottinger Tel: + 44 (0)20 3772 2500
Lorna Cobbett
Henry Lerwill
A presentation to analysts will be held at 9am 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
Against what has been a challenging backdrop, Premier delivered
a strong operational performance in 2016, resulting in record
production of 71.4 kboepd, up 24 per cent on 2015, with production
in the fourth quarter averaging over 80 kboepd. This was driven by
contributions from the E.ON UK E&P (E.ON) portfolio and its
successful integration into our UK business unit and new production
from the Solan field. It was also helped by outperformance from our
operated assets in Asia and high operating efficiency of 91 per
cent across the portfolio.
UK production doubled during the year to 33.0 kboepd,
underpinned by the new contributions from the E.ON portfolio and
the Solan field. Production from the E.ON assets exceeded our
acquisition case, contributing 17.1 kboepd to Group production over
the eight months from 28 April to 31 December 2016. This was driven
by outperformance from both the Huntington field and the long life
Elgin-Franklin field where there is an ongoing infill drilling
programme. Babbage and Wytch Farm also delivered a strong
performance in 2016, underpinned by high operating efficiency of
over 90 per cent. Profits from UK production continue to be
sheltered by Premier's brought forward tax loss and allowance
position.
First oil from the Solan field was achieved in April, marking a
significant milestone for the Group. The second producer was
brought on-stream in August. Production from the field has been
lower than anticipated due to poor reservoir performance from the
eastern area of the field. Most recently, a decision has been taken
to contract a drilling rig to carry out the first planned workover
of the first production well (P1) during the summer of 2017. The
field is currently producing at around 9 kbopd with the P1 well on
free-flow. This will be supplemented by ESP (pump) support
following the summer workover.
Singapore demand for our Indonesian gas was strong during 2016.
Our operated Natuna Sea Block A again captured a market share
within its principal gas sales contract (GSA1) considerably ahead
of its contractual share, while there was record demand for our gas
under our second gas sales contract (GSA2). Across the border in
Vietnam, performance from the Premier-operated Chim Sáo field
exceeded expectations, both in terms of reservoir deliverability
and operating efficiency, with a successful well intervention
programme also helping to mitigate natural decline from the field.
Significant upside remains at Chim Sáo and we look forward to
executing an infill drilling programme in 2017 to help maximise
production levels from the field. Chim Sáo reserves have again been
revised upwards.
In 2017, we expect Group production to be higher at 75 kboepd,
unchanged from previous guidance and before any contribution from
Catcher which we expect to come on-stream later this year. The
increase in production from our existing producing assets reflects
a full year contribution from the E.ON portfolio and the Solan
field, partially offset by natural decline in the Group's Pakistan
fields and in certain of our UK fields.
2016 saw us increase our proven and probable (2P) reserves, on a
working interest basis, to 353 mmboe (2015: 332 mmboe) and our
total 2P reserves and 2C resources to 835 mmboe (2015: 758 mmboe).
The increase in our 2P reserves was driven by our acquisition of
the E.ON portfolio and an upward revision in our estimate of 2P
reserves at Chim Sáo following better than anticipated reservoir
performance and an extension to forecast field life. These
additions more than offset the impact of 2016 production and a
downward revision to our Solan 2P reserve estimates due to poorer
than anticipated reservoir performance. The increase in our 2C
resources of 56 mmboe was principally as a result of the 50 per
cent interest in the Tolmount field acquired with the E.ON
portfolio.
Premier's operating costs were US$15.8 boe (2015: US$15.5/boe),
significantly below budget as a result of ongoing cost reduction
initiatives, successful contract renegotiations and strict
management of discretionary spend. With a large portion of our
costs Sterling denominated, we also benefitted from the weaker
Sterling Dollar exchange rate. Significant reductions in operating
costs have been achieved over the last two years. While it is
likely to be difficult to push through further contractor rate
reductions given current service sector margins, additional cost
reductions will come from other approaches such as collaboration
and efficiency savings. Premier instigated such initiatives in 2016
and expects to build on these during 2017.
The progress that has been made on the Catcher project during
2016 and the 29 per cent capex reduction secured to date is
testament to the hard work, skill and capability of the project
team and our contractors. All nine wells drilled to date have come
in at or above prognosis and we now expect to deliver an improved
production profile from a reduced well count. All of the key
elements of the subsea equipment have been installed, ready for the
arrival of the FPSO. The construction of the FPSO is largely
complete and the focus is now on completing the yard-based
pre-commissioning and commissioning work scopes ahead of a mid-year
sailaway. Premier continues to target production start-up for later
this year. Once on-stream the Catcher field, with an expected
plateau rate of over 50 kboepd, will provide another step change in
our production levels, generating enhanced, tax-free cash flows for
the Group.
With rising production and over 700 mmboe of discovered but
undeveloped 2P reserves and 2C resources, we have significant
optionality within our portfolio to maintain and grow production
and deliver value for our stakeholders. In a depressed commodity
price environment, the lower cost projects with a rapid pay-back
have been prioritised. For 2017, this includes an infill drilling
programme in Vietnam, which has a payback of less than six months,
as well as incremental projects in Indonesia, which were sanctioned
post period end by Premier's Board, to backfill our existing gas
sales contracts.
The Tolmount field is looking increasingly attractive and is
likely to provide our next phase of growth. It meets our economic
thresholds even at low gas prices, accelerates the use of our UK
tax losses and allowances and fits well with our financial profile.
There is also significant upside, currently estimated at over 400
Bcf, beyond the main development in the Greater Tolmount Area. The
development concept was selected post period end with a nine month
front end engineering design (FEED) programme now underway.
Premier's largest pre-development project is Sea Lion Phase 1 in
the Falkland Islands. The Sea Lion project as a whole has the
potential to be transformational for the Group with around 400
mmboe (net to Premier) to be developed over several phases. FEED on
Sea Lion Phase 1 was largely completed in 2016 and saw the
breakeven cost of the project lowered significantly from US$55/bbl
to less than US$45/bbl, while the capex to first oil was reduced
from US$1.8 billion to US$1.5 billion. With the economics of the
project considerably improved, Premier is now working to secure a
funding solution for the development. Commercial and fiscal
discussions with the Falkland Islands Government are also
progressing.
In light of current capital allocation priorities, Premier's
exploration activities have reduced considerably and our portfolio
has become more concentrated on a few key proven but under-explored
plays or basins. In particular, we exercised our option to increase
our equity stake to 25 per cent in Block 7 in Mexico at the end of
2016 and expect to drill the large amplitude-supported Zama
prospect there in Q2 2017. We also exited our 35 per cent interest
in Block FZA-M-90 in the Foz do Amazonas Basin in December (subject
to ANP approval) enabling us to focus our Brazilian exploration
efforts on our core area position in the Ceará basin, where we have
acquired 4,000 square kilometres (km(2) ) of fast track seismic
data.
One of the key achievements of the year was our successful
acquisition and integration of the E.ON portfolio which builds on
our track record of acquiring assets at low points in commodity
cycles. The acquisition significantly enhanced the Group's UK North
Sea asset base and creates considerable operating, cost and tax
synergies within our existing UK business. At a price of US$120
million, the acquisition is expected to reach pay-back in 2017 1H,
earlier than anticipated, and we now value the E.ON portfolio at
very substantially more than the acquisition cost. This is partly
as a result of higher commodity prices but also as a result of
improving asset profiles, due to production outperformance or, as
in the case of Tolmount, following further work on the project.
We continue to look to dispose of non-core assets, such as our
Pakistan business or certain assets from the E.ON portfolio where
formal sales processes are ongoing. In addition, we will look to
reduce our equity interests in certain projects where we can
realise upfront cash to accelerate debt reduction.
The acquisition of the E.ON portfolio, via debt funding, and the
prolonged period of depressed commodity prices saw us enter
discussions with our various lending groups in 2016 to undertake a
full refinancing of our existing facilities. The number of parties
involved and the fact that most of our lenders rank pari passu
(which gave rise to complex inter-creditor issues) meant that those
negotiations took longer than anticipated. Nonetheless, we are
close to locking up all of our lending groups to the amended terms.
The lock up of the creditors to the terms of the refinancing marks
a major milestone for Premier with the refinancing defining future
reduction of debt but also allowing us to plan for future
investment in selective new projects. Final completion of the
refinancing is targeted for the end of May 2017.
As at year end, we retained cash and undrawn facilities of
US$593 million. This was as a result of record production together
with the benefit of our hedging programme, low operating costs
secured by ongoing cost reduction initiatives and delivery of a
capital investment programme below budget. Net debt stood at $2.8
billion at the end of 2016, down from its peak reached in Q3 2016,
and we expect to continue to be net cash flow positive (after capex
and planned disposals) at current oil prices. This debt reduction
will accelerate once the Catcher field is on-stream.
As we enter 2017 with improving commodity prices, our focus is
on maintaining our strong production performance and competitive
cost base while delivering our operated Catcher project on schedule
and below budget. In order to plan and protect our cash flows, we
will continue to hedge our oil and gas production with the aim of
locking in oil prices at levels at which we will be free cash flow
positive. Our positive cash flow will be prioritised towards
reducing our debt so as to enable the Group to achieve a leverage
ratio of 3x EBITDA by the end of 2018 and, where future cash flows
allow, to selectively invest in new projects to deliver future
value for all stakeholders.
Tony Durrant
Chief Executive Officer
BUSINESS UNIT REVIEWS
UNITED KINGDOM
The UK delivered a step change in production in 2016, achieving
a year-end exit rate of over 45 kboepd, more than double that of
2015. This was driven by high operating efficiency, a contribution
from the E.ON assets (which continue to exceed expectations) and
new Solan production. Looking ahead, the Catcher project remains on
schedule for first oil in 2017 with total capex now estimated at
$1.6 billion, 29 per cent lower than at sanction, while the
development scheme for the Tolmount gas project was selected post
period end.
Production
Production from Premier's UK fields averaged 33.0 kboepd (2015:
16.7 kboepd), double that of 2015. Production from the E.ON assets
exceeded the Group's acquisition case of 15 kboepd, averaging 17.1
kboepd for the eight months from 28 April 2016 to 31 December 2016.
Production from the operated Huntington field averaged 10.8 kboepd
(2015: 6.2 kboepd) during 2016. The step up in production reflects
Premier's increased equity position to 100 per cent (due to the
acquisition of the E.ON assets at the end of April 2016 and the
default of the minority partners in 2015), high operating
efficiency of over 90 per cent and strong reservoir performance.
Premier is currently in discussions with Teekay, the owner of the
FPSO, to extend the firm charter period beyond April 2018 with a
revised rate structure.
Production from the non-operated Elgin-Franklin fields, which
was acquired as part of the acquisition of the E.ON assets,
increased during the year, benefitting from an ongoing infill
drilling campaign and strong winter gas demand, averaging 5.5
kboepd for the eight months from 28 April to 31 December 2016 and
6.5 kboepd in Q4 2016. This strong performance was tempered by
periodic oil export restrictions placed on the field over the
summer as a result of ongoing maintenance on the Forties Production
System (FPS). The non-operated Glenelg field (Premier 18.57 per
cent), a satellite field within the Elgin-Franklin area, came back
on-stream at the end of May following a successful well workover of
the G10 well. The field was producing over 20 kboepd (gross) when
not impacted by export restrictions but was subsequently shut in in
late September as a result of a blocked scale inhibitor line. A
remediation programme is being implemented by the operator to
reinstate production. The Premier-operated Babbage field, acquired
as part of the acquisition of the E.ON portfolio, also
outperformed, producing consistently at rates of above 3 kboepd
driven by high uptime of more than 90 per cent and continued good
reservoir performance. The platform is in the process of moving to
normally unmanned operations which is expected to reduce field
operating costs in 2017. Post period end, a successful well
intervention campaign was undertaken to maximise production from
the Babbage field.
First oil from the Solan field was achieved on 12 April 2016 and
the second producer was brought on-stream on 18 August 2016.
Average production for 2016 was impacted by poorer than expected
reservoir performance in the eastern part of the field which is
limiting water injection and production rates from the second
producer (P2). A decision has been taken to contract the Transocean
Spitzbergen, which has been working in the area close to Solan, to
install two ESPs in P1 following the failure of the existing single
ESP during February. The planned work programme will restore P1
production to at least 10 kbopd from mid-year. The field is
currently producing around 9 kbopd with P1 on free flow. Meanwhile,
a number of options continue to be studied to increase water
injection into the reservoir with the aim of supporting higher
production levels. Premier has already implemented some of the more
short-term, lower capex projects, such as increases to platform
pump capacity. While incremental production increases can be gained
from such remedial work, it is possible that another well or a
side-track would be required in order to gain a more material
uplift in production rates and improve recovery. The Solan team are
monitoring production behaviour to better delineate recovery from
the existing wells and to define the scope of a potential drilling
programme for 2018. Operating efficiency of the facilities was good
during 2016 and, to date, eight tanker liftings have been
successfully completed.
Production from the Premier-operated Balmoral area averaged 2.1
kboepd (2015: 3.1 kboepd), impacted by a commercial disagreement
between partners at the start of 2016 (subsequently resolved) and
intermittent oil export restrictions due to FPS maintenance.
Operating costs were US$49 million (2015: US$64 million), down 23
per cent on the prior period, benefitting from a weaker Sterling
Dollar exchange rate and as a result of a focused cost reduction
programme, offshore and onshore.
Production from the non-operated Wytch Farm field averaged 5.1
kboepd (2015: 5.2 kboepd), benefitting from the well maintenance
work carried out in the second half of 2015 which partially offset
modest reservoir decline. The field operator delivered significant
cost savings during 2016 which resulted in operating costs of
US$26m net (2015: US$32m), down 19 per cent on the prior year.
Production from the non-operated Kyle field was maintained at 2.0
kboepd (2015: 2.0 kboepd), slightly ahead of expectations.
UK unit operating costs for the year were US$24/boe (2015: US$
30/boe), driven by start-up and acquisition of lower opex fields
such as Solan, Elgin-Franklin and Babbage and further cost
reductions across Premier's existing UK portfolio, particularly at
Wytch Farm and Balmoral. This figure includes certain one-off costs
following on from the acquisition of the E.ON portfolio. Going
forward, UK unit operating costs are expected to trend downwards
towards US$20/boe as Premier benefits from a full annual
contribution from the lower opex Elgin-Franklin and Solan fields
and as higher opex fields are decommissioned.
Development
Catcher
Good progress was made on the Premier-operated Catcher project
during 2016 which remains on schedule to deliver first oil in 2017
2H. 2016 saw the total capex estimate for the project reduce to
$1.6 billion, a 29 per cent reduction on the original sanctioned
estimate. Savings were secured across subsea and drilling
activities and as a result of the lower Sterling Dollar exchange
rate. Premier's forward cost exposure has reduced significantly
with remaining capex to first oil of around $100 million (net to
Premier), the majority of which relates to the ongoing drilling
programme.
The 2016 subsea installation campaign commenced in April and saw
the successful installation of the risers, bundles, towheads,
manifolds, midwater arches along with the buoy and mooring system.
Hook-up of all of the risers and umbilicals was also completed
during 2016. 14 different construction vessels were deployed on the
field over several phases while, at the peak of activities in May,
there were seven vessels present in the field. Final spool tie-ins
were completed in November, concluding the planned 2016 subsea
campaign under budget. The major elements of the subsea campaign
are now complete with only short campaigns required in 2017 to
tie-in wells as they become available from the drilling programme
and to support commissioning operations once the FPSO has been
installed.
Drilling activities using the Ensco 100 rig have continued to
yield positive results. During 2016, CCP3 and CTP1 on the Catcher
template, BP3 and BP5 on the Burgman template and VP2 and VP3 on
the Varadero template were completed, validating Premier's expected
reservoir interpretation from the three drill centres. VP4 on the
Varadero template was completed post period end. Based on test
results to date, the length of net pay encountered by the seven
production wells has been overall 30 per cent longer than forecast
while the anticipated initial production delivery rate of each well
is on average 40 per cent higher than predicted. As a result of
these positive well results, Premier remains encouraged about the
overall recovery from the Catcher fields and also forecasts a
reduced well count from that envisaged at sanction.
Fabrication of the Catcher FPSO hull and topsides was completed
in Asia with the Stern Terra Block and Forward Terra Block
successfully delivered to the Keppel Benoi yard in Singapore in
June and July respectively. The hull mating operation was carried
out and the welding of the two blocks completed in August.
Fabrication of all of the topside modules has been completed with
the final topside unit lifted onto the vessel in November. The
construction phase of the FPSO is now largely complete and the
focus is now on final integration and the completion of yard-based
pre-commissioning and commissioning work scopes. Sailaway is
expected mid-year with Premier continuing to target oil production
start-up for later this year.
Pre-development
Premier acquired a 50 per cent operated interest in the Greater
Tolmount Area where the Group sees the potential for the
development of up to 1 Tcf, including the fully appraised Tolmount
main structure of 540 Bcf and upside at Tolmount East and Tolmount
Far East, estimated to hold 220 Bcf and 150 Bcf of gas resource
respectively. Tolmount will provide the next phase of growth for
Premier in the UK, with significantly improved economics
benefitting from a higher gas price than the E.ON acquisition
case.
During 2016, Premier carried out conceptual studies and
engineering work on a number of development options for the
Tolmount main structure. This included optimisation of the project
from a subsurface, facilities, pipeline, host terminal and
commercial perspective. In February 2017, the development concept,
comprising a standalone normally unmanned installation (NUI) and a
new gas export pipeline to shore, was selected. It is envisaged
that the initial phase, which will target the Tolmount main
structure, will recover 540 Bcf (P50 estimate) of gas from four
producing wells. The offshore FEED contracts were awarded post
period end and FEED is expected to take 9 months with project
sanction targeted for Q1 2018. It is estimated that capex to first
gas will be around US$550 million, although Premier is currently
engaging with the contractor market with a view to enhancing
returns and reducing further upfront capex on the project. In
addition, following unsolicited offers of interest from a number of
parties, Premier has instigated a process to identify possible
investors for a 20 per cent interest in the Tolmount project.
Exploration
The Laverda/Slough prospect, near the Catcher area was drilled
in April 2016. The commitment well encountered 13 feet of net oil
bearing Tay sands at Laverda, in line with pre-drill expectations,
but did not encounter any indications of hydrocarbons in the
deeper, high risk Slough prospect.
In July, the Ocean Valiant rig spudded the Bagpuss prospect in
the Outer Moray Firth. The well encountered 41 feet of
hydrocarbon-bearing sand within a 68 feet hydrocarbon column. The
well was plugged and abandoned. Premier subsequently sold its
interest in the licence to Reach Halibut Limited.
In December 2016, the Rowan Gorilla VII jack-up rig spudded the
Ravenspurn North Deep well, which is testing the deep Carboniferous
play underlying the Ravenspurn North field in the Southern Gas
Basin; if successful, it could provide material follow-on
opportunities for Premier within its Southern Gas Basin portfolio,
in addition to helping to prolong the life of the Ravenspurn area
fields. Premier is fully carried on its 5 per cent interest in the
well.
Premier continues to actively manage its UK exploration
portfolio with nine UK licences relinquished or sold in 2016 and
associated cost savings realised. While Premier has relinquished
much of E.ON's exploration acreage, some of its Southern North Sea
prospects are attractive. Premier plans to mature the work
programmes on these select licences during 2017, along with further
exploration prospects on its current production licences.
INDONESIA
The Premier-operated Natuna Sea Block A fields outperformed in
2016 delivering a robust production performance of 13.0 kboepd, up
6 per cent on 2015, underpinned by an increased market share of 44
per cent within GSA1 and strong Singapore demand for gas deliveries
under GSA2. This, together with low operating costs of US$8/boe,
resulted in the Indonesian business unit generating strong positive
net cash flows for the Group.
Production and development
Net production from Indonesia in 2016 on a working interest
basis increased to 14.3 kboepd (2015: 13.9 kboepd), with higher
production from the Premier-operated Natuna Sea Block A fields
offset, in part, by lower production from the non-operated Kakap
fields. Operating efficiency remained high at over 90 per cent.
Gas supply by contract
---------------------------------------------------------
GSA1 GSA2 GSA2
--------------- ------------ ------------ ------------
BBtud (gross) 2016 2015 2016 2015 2016 2015
--------------- ----- ----- ----- ----- ----- -----
Anoa(1) 132 133 - - - -
--------------- ----- ----- ----- ----- ----- -----
Gajah Baru(2) - - 94 77 11 13
--------------- ----- ----- ----- ----- ----- -----
Total Block
A 132 133 94 77 11 13
--------------- ----- ----- ----- ----- ----- -----
Kakap 17 23 - - - -
--------------- ----- ----- ----- ----- ----- -----
Total 149 23 94 77 11 13
--------------- ----- ----- ----- ----- ----- -----
(1) Includes production from the Pelikan field.
(2) Includes production from the Naga field.
Premier sold an average of 237 BBtud (gross) (2015: 223 BBtud)
from its operated Natuna Sea Block A fields during 2016. Singapore
demand for gas sold under GSA1 remained robust, averaging 297 BBtud
(2015: 311 BBtud) during 2016. Premier's Anoa and Pelikan fields
delivered 132 BBtud, capturing 44 per cent (2015: 43 per cent) of
GSA1 deliveries, above Natuna Sea Block A's contractual share of 41
per cent. Natuna Sea Block A's contractual share for 2017 has been
increased to 47 per cent.
Gajah Baru and Naga delivered record production of 94 BBtud
under GSA2, up 22 per cent on the prior year, representing 100 per
cent nomination delivery by Premier. Gas deliveries from Gajah Baru
and Naga under the Domestic Swap Agreement (DSA), which resumed in
September following an extension of the DSA to end December 2016,
averaged 11 BBtud (2015: 13 BBtud). The Gajah Baru compressor
reconfiguration project, aimed at maximising deliverability from
the Gajah Baru, Pelikan and Naga fields, was successfully completed
in December 2016 and will extend plateau production from these
fields.
Gas sales from the non-operated Kakap field averaged 17 BBtud
(2015: 23 BBtud) while gross liquids production was 2.7 kbopd
(2015: 3.5 kbopd), reflecting natural decline from existing wells.
Gross liquids production from the Anoa field was stable at 1.4
kbopd (2015: 1.4 kbopd), underpinned by successful well
intervention work.
Premier continues to benefit from a low cost base in Indonesia,
as a result of an on-going cost reduction campaign. Based on
current production levels, Natuna Sea Block A is well placed to
deliver operating costs of around US$8/boe into the medium
term.
During 2016, FEED was completed on the Bison, Iguana and Gajah
Puteri (BIGP) fields which marks the next generation of Natuna Sea
Block A projects to support Premier's long-term gas contracts into
Singapore. Premier's Board sanctioned BIGP post period end. An
invitation to tender for long lead items has been issued and
delivery of first gas is targeted for Q3 2019.
Premier has identified several infill drilling candidates at
Gajah Baru with drilling currently modelled to commence in 2018
while preparations are underway to recomplete the WL-5x well which
made the Lama discovery under Anoa in 2012 and to tie it into
production in Q3 2017.
Evaluation of potential development scenarios for the 2014 Kuda
Laut and Singa Laut discoveries on the Premier operated Tuna Block
is ongoing. These include gas offtakes via the West Natuna
Transportation System to Singapore and Indonesia or through
existing infrastructure in Vietnam. Post period end, Premier was
granted a three-year extension to the exploration period of the
licence. This will allow time for Premier to undertake further
appraisal drilling and also to establish a commercial development
concept for the field, ahead of submitting a Plan of
Development.
Exploration and appraisal
Premier continues to mature a number of Lama Play leads and
prospects to a drillable status on its operated Natuna Sea Block A
acreage and seismic reprocessing is currently scheduled for 2017 to
enhance the seismic imaging over the Lama Play area.
VIETNAM
A robust production performance, combined with continued low
operating costs, resulted in the Vietnam business generating net
positive operating cash flows during 2016. Further, Chim Sáo's
remaining 2P reserves were materially increased at the end of the
year as a result of better than expected reservoir performance and
the lower lease rate secured for the Chim Sáo vessel resulting in
an extended field life.
Production
Production from the Premier-operated Block 12W, which contains
the Chim Sáo and Dua fields, averaged 16.2 kboepd (2015: 16.9
kboepd) with high uptime, better than expected reservoir
performance and a successful well intervention programme helping to
mitigate natural decline from the fields.
Since taking over direct management of production operations in
2015, Premier has prioritised root-cause analysis of all events
that lead to loss of production. This knowledge has improved the
efficiency of planned maintenance programmes, enhanced the
availability of key systems and enabled competency development for
the crew. The outcome is that Chim Sáo operating efficiency
exceeded 90 per cent in 2016.
The 2016 well intervention programme included bringing a deep
reservoir on to production in the Chim Sáo North West area and the
reservoir stimulation of three oil wells and a water injector well
in the main field area. Planning is underway for a programme of
further well stimulations in 2017. In addition, a two-well infill
drilling programme, scheduled to commence in August 2017, will
further help to maximise the field's production levels.
During 2016, Premier has continued to review all of its
contracts with the aim of securing cost reductions and efficiencies
throughout its Vietnam operation. Notably, in December 2016,
Premier in its capacity as operator of Block 12W completed a
revised FPSO charter party agreement securing a reduction in the
Chim Sáo FPSO lease rate effective from 1 November 2015 and an
extension to the firm charter period.
Strong production performance, low operating costs and the
continuing premiums to the Brent oil price commanded by Chim Sáo
crude contributed to a positive net operating cash flow from the
Vietnam business unit in 2016. In addition, as a result of the
strong reservoir performance from the field to date and the
anticipated extended field life facilitated by a lower FPSO lease
rate, Premier has revised upwards its estimates of Chim Sáo's
remaining net 2P reserves by 13 mmboe to 31 mmboe.
PAKISTAN
Premier's Pakistan business has performed significantly ahead of
forecast in 2016 with net cash flow more than twice the budgeted
level. The average realised price was $2.8/mscf while operating
costs remained low at around $0.6/mscf.
Production and development
Production in Pakistan averaged 7.5 kboepd (47.4 mmscfd) (2015:
9.7 kboepd (60.2 mmscfd)), from Premier's six non-operated
producing gas fields. The fall in production reflects natural
decline in all of the gas fields. This was partially offset by a
successful well intervention campaign at the Zamzama field which
significantly arrested the decline rate of this field. As a result,
production from the Zamzama field was significantly ahead of
expectations for the period and underpinned the outperformance of
the Pakistan business unit.
Mmscfd 2016 2015
----------- ----- -----
Bhit 8.4 11.4
----------- ----- -----
Badhra 5.8 7.7
----------- ----- -----
Qadirpur 16.1 17.8
----------- ----- -----
Kadanwari 5.4 9.8
----------- ----- -----
Zamzama 11.3 13.0
----------- ----- -----
Zarghun
South 0.4 0.5
----------- ----- -----
Total 47.4 60.2
----------- ----- -----
Further work is planned for 2017 to offset the natural decline
at the Badhra and Kadanwari fields. A well intervention programme,
consisting of three wells, is planned for the Badhra field while a
well intervention programme as well as two development wells are
planned for the Kadanwari field.
Portfolio management
During 2016, Premier agreed terms with a preferred bidder for
the sale of its Pakistan business. However, the bidder was unable
to put in place the necessary funding arrangements and the
exclusivity period ended. Premier reopened the process to a limited
group of potential buyers. The economic date of the transaction is
now expected to be 1 January 2017 with Premier retaining 2016 net
cash flows.
MAURITANIA
Production and development
Production from the Chinguetti field averaged 368 bopd (2015:
415 bopd) net to Premier. The fall in production was driven by
natural decline from the existing wells. In view of the low oil
price and resulting marginal cash flows, the joint venture partners
are targeting cessation of production from the field in 2017. To
this end, the operator submitted an abandonment and decommissioning
plan to the Government of Mauritania in June 2016.
THE FALKLAND ISLANDS
FEED for the Premier-operated Sea Lion Phase 1 project
progressed well during 2016. The estimated breakeven price of the
project is now less than $45/bbl, down from $55/bbl at the end of
2015. The focus is now on progressing funding alternatives for the
project.
Development
During 2016, Premier undertook FEED on the Sea Lion Phase 1
development. Phase 1 is expected to recover 220 mmbbls from the
north-east and north-west sections of the field located in the
PL032 licence area. FEED contracts were awarded to SBM Offshore for
the FPSO, Subsea 7 for the subsea installation, NOV for the
flexible flowlines and One Subsea for the subsea production
system.
Over the course of 2016, the four main contractors worked
collaboratively with Premier and also with candidate well services
and logistics contractors to optimise the facilities design and
installation methodology. This included the optimisation of the
single drill centre subsea layout to reduce installation costs. As
a result of this work, Premier has reduced its pre-first oil capex
estimate from $1.8 billion to $1.5 billion.
Premier has also seen significant reductions in its estimates of
field support services, including supply boats, helicopters and
shuttle tankers. Consequently, field operating costs for Sea Lion
are now estimated at $15/bbl, down from over $20/bbl, while the
total project breakeven cost has reduced to just below $45/bbl from
$55/bbl.
Premier has assembled bid packages for drilling, subsea
production systems and certain logistics items, which are ready to
be issued to the market when appropriate in order to convert
current proposals, derived through extensive market engagement,
into binding agreements.
In 2016, Premier secured approval from the Falkland Islands
Government for an extension to the Sea Lion Discovery Area licence
to April 2020. The focus is now on securing an appropriate funding
solution for Phase 1 of the project.
The overall strategy to develop the North Falklands Basin
remains a phased development solution, starting with Sea Lion Phase
1 which will develop 220 mmbbls in PL032. A subsequent Phase 2
development will recover a further 300 mmbbls from the remaining
reserves in PL032 and the satellite accumulations in the north of
the adjacent PL004. There is also a further 250 mmbbls of low risk,
near field exploration potential which could be included in either
the Phase 1 or Phase 2 developments. Phase 3 will entail the
development of the Isobel/Elaine fan complex in the south of PL004,
subject to further appraisal drilling.
Exploration
In January 2016, Premier completed its exploration programme in
the North Falklands Basin with the successful re-drill of the
Isobel Deep well. The well confirmed the oil discovery encountered
in the original Isobel Deep well and, in addition, discovered new
hydrocarbons in additional sandstones.
EXPLORATION
Premier has continued to reshape and focus its exploration
portfolio on under-explored but proven hydrocarbon basins with the
potential to develop into new business units in 2018 and beyond.
Priority is being given to lower cost operating environments whilst
reducing exposure elsewhere. Premier plans to drill the large Zama
structure in Mexico in Q2 2017.
MEXICO
During 2016, the Mexico Joint Venture reprocessed the existing
3D seismic data and matured a number of prospects across its Blocks
2 and 7 in the Sureste Basin as candidates to be drilled in 2017
and 2018. In particular, Premier and its partners completed the
technical evaluation of their Block 7 acreage including the
amplitude-supported Zama prospect which has a well-defined flat
spot, an indicator of potential hydrocarbons. A rig has been
contracted to drill the low-risk Zama Prospect in the second
quarter of 2017 with the overall Zama structure estimated to have a
P90-P10 gross unrisked resource range of 100-500 mmboe (the
majority of which is on Block 7).
Premier currently holds a carried 10 per cent interest in Block
2, whilst on Block 7 Premier elected to exercise its option to
increase its equity to a 25 per cent paying interest in December
2016, subject to the Mexican government (CNH) approval. Premier
continues to evaluate opportunities for growth in Mexico.
BRAZIL
Premier received 4,000km(2) of fast-track seismic data across
all three of its Ceará Basin blocks in 2016. This data is being
interpreted to map promising plays and prospects for future
drilling locations on the blocks. Final processed broadband seismic
data is due to be delivered in April 2017 and well locations will
be selected from this during the course of 2017.
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 2016,
the installation of offshore buoys and moorings for a collaborative
meteorological and oceanographic data campaign was completed to
gather the data required for obtaining drilling licences in the
basin. This data gathering operation is one of many joint operator
initiatives that Premier is either participating in or leading in
the Ceara basin, helping to reduce costs.
In August 2016, Premier obtained a licence extension from the
Brazilian Government (ANP) to July 2019 on its operated licences
CE-M-717 and 665. A similar extension was also obtained by Total,
Operator of licence CE-M-661. The extensions will enable Premier to
realise further cost synergies with other operators in the
Equatorial Margin with drilling operations planned for the first
half of 2019.
In the Foz do Amazonas basin, Premier completed its evaluation
of new 3D seismic data across block FZA-M-90 and decided to exit.
Premier's 35 per cent interest in the block was transferred to
operating partner Quieroz Galvão E&P. The farm-out agreement
for this block was completed in December 2016 and is awaiting the
final approval of the ANP.
Portfolio management
Premier has continued to focus its exploration efforts on
under-explored but proven hydrocarbon basins. In light of current
capital allocations, Premier's exploration portfolio has become
increasingly concentrated. Over the course of 2016, Premier
successfully relinquished or sold 16 licences, including a number
of licences acquired as part of the acquisition of the E.ON
portfolio. A further 11 licences are scheduled for relinquishment
subject to government approvals. In particular, Premier exited its
35 per cent interest in Block FZA-M-90 in the Foz do Amazonas Basin
in December (subject to ANP approval) enabling the Group to focus
its Brazilian exploration efforts on its core licences in the Ceará
basin.
Premier has also successfully exited its position in Iraq
(subject to final government approval) and the Saharawi Arab
Democratic Republic.
Financial Review
Context
Consistent with the last two years, 2016 continued to provide a
challenging macro-economic environment. Against this backdrop,
however, operational performance remained strong with production
for the full year averaging 71.4 kboepd and averaging more than
80kboepd during Q4 2016. This increase was driven by the successful
completion of the acquisition of the E.ON portfolio and first oil
from the Solan field. We continue to actively manage operating
costs which, at $15.8/bbl, are below what had been budgeted for the
year, benefitting from tight cost control, a weakened GBP exchange
rate and high operating efficiency of over 90 per cent across the
portfolio.
In addition, during 2016 we commenced discussions with our
lending groups on the terms of our existing finance facilities. In
February 2017 we reached an agreement in principle with our lender
groups on revised terms. The revised terms include amendments to
our financial covenants, deferral of final maturity dates to May
2021 and beyond and a margin uplift on interest payable to the
lenders. The process of finalising the revised refinancing and
implementation documents is ongoing and completion of the
refinancing is expected by the end of May 2017. Once finalised, the
agreed terms will give Premier sufficient liquidity to operate in
the current oil price environment, deliver our sanctioned projects
and to continue to invest in the wider business at appropriate
levels of equity interests.
Business Performance
Business performance (US$ million) 2016 2015
--------
Operating loss (145.9) (707.8)
Amortisation and depreciation 340.3 326.7
Impairment charge on oil and
gas properties 556.2 1,023.7
Exploration expense and pre-licence
costs 58.4 109.0
Reduction in decommissioning (75.7) -
estimates
Acquisition of subsidiaries:
Excess of fair value over consideration (228.5) -
Costs related to the acquisition 21.6 -
-------- --------
EBITDAX 526.4 751.6
-------- --------
EBITDAX for the year was US$526.4 million compared to US$751.6
million for 2015. The lower EBITDAX is mainly due to lower realised
oil prices, including a reduction in the value of our oil hedges
settled in the year, partially offset by an increase in volumes
lifted following the acquisition of the E.ON assets and first oil
from Solan.
Acquisition of the E.ON assets
In April 2016, Premier completed the acquisition of the E.ON
assets for cash consideration of US$135.0 million, including
working capital adjustments. The acquisition was accounted for as a
business combination under the requirements of IFRS 3 Business
Combinations and the assets and liabilities acquired have been fair
valued on the date of completion utilising Premier's corporate
assumptions for oil and gas prices, reserves estimates and discount
rates. The fair value of the net assets acquired was US$363.5
million resulting in an excess of fair value over consideration of
US$228.5 million. The excess of fair value over consideration has
arisen primarily due to E.ON's strategic decision to exit the UK
and Norway E&P sectors and Premier's willingness to take over
the entire UK upstream operation. Separately, costs related to the
acquisition of US$21.6 million have been recognised in the period.
This is made up of acquisition costs of US$5.6 million and the
recognition of a post-acquisition settlement of US$16.0 million
related to redundancy costs.
Income statement
Production and commodity prices
Group production on a working interest basis averaged 71.4
kboepd compared to 57.6 kboepd in 2015. Higher production
year-on-year is a result of first oil from the Solan asset and the
uplift in production from the E.ON assets acquired in the year.
Entitlement production for the period was 66.1 kboepd (2015: 53.4
kboepd).
Premier realised an average oil price for the year of
US$44.1/bbl (2015: US$52.6/bbl). Post hedging, realised oil prices
increased to US$52.2/bbl (2015: US$79.0/bbl).
In the UK, average prices achieved for National Balancing Point
gas ("NBP") were 41.5 pence/therm pre-hedging and 47.6 pence/therm
post-hedging. Average gas prices for the Group's non-UK assets were
US$4.6 per thousand standard cubic feet (mscf) (2015: US$5.9/mscf).
Gas prices in Singapore, linked to high sulphur fuel oil (HSFO)
pricing and in turn, therefore, linked to crude oil pricing,
averaged US$7.8/mscf (2015: US$8.0/mscf) pre-hedging, and increased
to US$8.6mscf post-hedging. The average price for Pakistan gas
(where only a portion of the contract formulae is linked to energy
prices) was US$2.8/mscf (2015: US$3.9/mscf).
Total sales revenue from all operations fell to US$983.4 million
(2015: US$1,067.2 million), due to the fall in average realised
prices post-hedging, offsetting higher year-on-year production.
Operating costs
Cost of sales comprises cost of operations, change in lifting
position, inventory movement, royalties and amortisation and
depreciation of property, plant and equipment ('PP&E'). Cost of
sales for the Group was US$767.1 million for 2016, compared to
US$661.0 million for 2015.
Operating costs 2016 2015
------
Cost of operations (US$ million) 412.8 323.6
Unit cost of operations ($ per barrel) 15.8 15.5
Amortisation of oil and gas properties
(US $million) 332.2 315.9
Unit amortisation rate ($ per barrel) 12.7 14.8
------ ------
As a result of the weaker sterling exchange rate and continued
cost savings across the business, operating costs of $15.8/bbl are
10 per cent below budget. We have maintained costs at these low
levels due to improved operating efficiency across several of the
Group's assets and continued reductions in underlying cost from
further contract reductions with suppliers, including our revised
FPSO arrangements on Chim Sáo.
Impairment of oil and gas properties
An impairment charge of US$652.2 million (pre-tax) has been
recognised in the income statement relating to the Solan field in
the UK North Sea (US$443.7 million post-tax). The impairment charge
is driven by a reduction in the 2P reserves expected to be
recovered from the asset over its economic life and a US$5/bbl
reduction in the Group's long term oil price assumption to US$75
(real)/bbl. The impairment charge is partially offset by the
recognition of a reversal of impairment credit of US$96.0 million,
pre-tax (US$60.0 million post-tax). The reversal has been
recognised on the Huntington and Kyle assets in the UK, the Chim
Sáo asset in Vietnam and the Kadanwari asset in Pakistan. The
reversal of impairment is principally caused by an increase in the
short term oil price assumption, based off the forward curve as at
the balance sheet date, and an increase in Chim Sáo 2P reserves.
After recognition of a net impairment charge of US$556.2 million
(US$383.7 on a post-tax basis) there is US$2,726.2 million
capitalised in relation to PP&E assets and US$240.8 million for
goodwill.
Revision in decommissioning estimates
The weakness in sterling dollar exchange rate at 31 December has
been the principal cause of a US$75.7 million gain being credited
to the income statement in respect of revised decommissioning
estimates. Whilst any positive foreign exchange revision would
generally have been credited to the decommissioning asset in the
balance sheet, the majority relates in this case to late life UK
assets which have been fully depreciated. As such, a significant
portion of this revision has been taken as a credit to the income
statement in the period.
Exploration expenditure and pre-licence costs
Exploration expense and pre-licence expenditure costs amounted
to US$58.4 million (2015: US$109.0 million). This includes the
write-offs relating to the Laverda, Slough and Bagpuss prospects
drilled in 2016 and costs that had been capitalised in relation to
the Foz licence interest in Brazil. After recognition of these
expenditures, the exploration and evaluation asset remaining on the
balance sheet at 31 December 2016 is US$1,011.4 million,
principally for the Sea Lion and Tolmount assets.
General and administrative expenses
Net G&A costs to the Group of US$24.1 million (2015: US$14.4
million) increased year on year due to the inclusion of E.ON's
unallocated G&A for the period since the completion of the
acquisition. Underlying G&A, without the acquisition, would
have fallen year on year and total net G&A costs to the group
in 2017 are expected to return to 2015 levels.
Finance gains and charges
Interest revenue and finance gains reduced to US$13.2 million
from US$40.7 million in 2015. The principal reason for this
reduction is that, following the acquisition of the remaining share
of Solan in 2015, interest receivable is no longer being recognised
on the loan to JV partner. Gross finance costs, before interest
capitalisation, have increased from US$219.4 million to US$293.7
million. Interest costs capitalised decreased from US$58.8 million
to US$34.0 million reflecting the finalisation of the Solan
development.
Taxation
The Group's total tax credit for 2016 is US$522.0 million (2015:
US$241.1 million charge) which comprises a current tax charge for
the period of US$42.0 million and a non-cash deferred tax credit
for the period of US$564.0 million. The high effective tax rate for
the year is significantly impacted by a number of UK specific
items. The most significant of these is a tax credit of US$455.8
million due to recognition of UK tax losses and allowances in the
period, driven by an anticipated increase in future profitability
from the acquisition of the E.ON assets. This has been partially
offset by a charge of US$161.2 million in relation to the
supplementary charge rate from 20 per cent to 10 per cent during
the year, with the adverse impact of this change mitigated by
US$27.1 million as the rate applicable to the reversal of certain
temporary differences on decommissioning remained unchanged. A
credit of US$61.0m has also been recognised for a ring fence
expenditure supplement claim made during the year in the UK.
Finally, an element of the Group's UK impairment charge for the
year does not attract a deferred tax offset which reduces the
associated credit by approximately US$63.2 million. After adjusting
for the net impact of the above items of US$319.1 million, the
underlying Group tax charge for the period is a credit of US$202.9
million and an effective tax rate of 52 per cent.
The Group has a net deferred tax asset of US$1,111.4 million at
31 December 2016 (2015: US$678.3 million).
Profit after tax
Profit after tax is US$122.6 million (2015: loss of US$1,103.8
million) resulting in a basic earnings per share of 24.0 cents from
continuing and discontinued operations (2015: loss of 216.1
cents).
Cash flows
Cash flow from operating activities was US$431.4 million (2015:
US$809.5 million) after accounting for tax payments of US$60.9
million (2015: US$94.0 million).
Capital expenditure in 2016 totalled US$678.1 million (2015:
US$1,070.1 million).
Capital expenditure (US$ million) 2016 2015
------
Fields/development projects 548.6 847.4
Exploration and evaluation 126.6 216.8
Other 2.9 5.9
------ --------
Total 678.1 1,070.1
------ --------
The principal development projects were the Solan and Catcher
fields in the UK. Exploration expenditure mainly related to our
exploration campaign in the Falkland Islands, which concluded in Q1
2016, and Brazil. In addition, payments related to decommissioning
in the period were US$62.3 million and included a one off US$53
million catch up payment into escrow for future decommissioning of
Chim Sáo, the balance of which is held within non-current other
receivables.
Balance sheet position
Net debt
Net debt at 31 December 2016, excluding Letters of Credit,
amounted to US$2,765.2 million (2015: US$2,242.2 million), with
cash resources of US$255.9 million (2015: US$401.3 million).
Net debt (US$ million) 2016 2015
=========
Cash and cash equivalents(1) 255.9 401.3
Convertible bonds(2) (237.4) (232.9)
Other debt(2) (2,783.7) (2,410.6)
========= =========
Total net debt (2,765.2) (2,242.2)
========= =========
(1) Includes JV partners share of cash of US$46.4 million and
cash collateral for Mexico exploration of US$6.6 million.
(2) The carrying amounts of the convertible bonds and the other
long-term debt on the balance sheet are stated net of the
unamortised portion of the issue costs of US$0.1 million (2015:
US$0.3 million) and debt arrangement fees of US$17.5 million (2015:
US$28.1 million) respectively.
Long-term borrowings consist of convertible bonds, UK retail
bonds, senior loan notes and bank debt. The GBP100.0 million and
US$150.0 million term loans maturing in November 2017 have been
classified as short term on the balance sheet. Once the Group's
refinancing is completed, maturity of both of these loans will be
extended out to May 2021.
Premier retains significant cash, at 31 December 2016, of
US$255.9 million and undrawn facilities of US$390.0 million, giving
Liquidity of US$592.9 million (31 December 2015: US$1,251.3
million), once cash of US$53.0 million held on behalf of our JV
partners is removed from the calculation of Liquidity.
Decommissioning Funding
As part of the E.ON acquisition, Premier entered into a separate
Decommissioning Liability Agreement with E.ON, whereby E.ON agreed
to part fund Premier's share of decommissioning the Johnston and
Ravenspurn North assets. Under the terms of the agreement, E.ON
will reimburse 70 per cent of the decommissioning costs between a
range of the net decommissioning costs of the two assets above
GBP40 million up to a ceiling of GBP130 million. This results in a
maximum possible funding of GBP63.0 million from E.ON. At 31
December 2016, a long-term decommissioning funding asset of US$66.7
million has, therefore, been recognised based on the year end
sterling dollar exchange rate.
Provisions
The Group's decommissioning provision increased to US$1,325.4
million at 31 December 2016, up from US$1,062.6 million at the end
of 2015. The increase is driven by the recognition of a long term
provision for decommissioning related to the E.ON assets of
US$427.9 million, which has been partially offset by a reduction
for the UK assets driven by the weakening of the GBP:USD exchange
rate at 31 December 2016.
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, Net Debt
and Liquidity and are defined in the glossary.
Financial risk management
Commodity prices
At 31 December 2016, the Group had 1.5 mmbbls of open oil swaps
at an average price of $45.8/bbl. The fair value of these oil swaps
at 31 December 2016 was a liability of US$18.3 million (2015: asset
of US$98.0 million), which is expected to be released to the income
statement during 2017 as the related barrels are lifted.
Furthermore, in December 2016, the Group paid total premiums of
US$4.6 million to enter into oil option agreements for 1.8 mmbls at
an average price of $50.7/bbl. These options will be settled during
2017 and are an asset on the Group's balance sheet with a fair
value at 31 December 2016 of US$3.5 million. Included within
physically delivered oil sales contracts are a further 1.7 mmbls of
oil that will be sold for an average fixed price of $55.3/bbl
during 2017 as these barrels are delivered.
In addition, the Group has forward UK gas sales for 132 mm
therms at an average price of 48 pence/therm at 31 December 2016
that will be physically settled during 2017 and into H1 2018. The
fair value of this asset at 31 December 2016 was US$10.0
million.
During 2016, forward oil sales of 5.3 mmbbls, forward gas sales
of 36 mm therms and forward fuel oil sales of 72,000 mt expired
resulting in a net credit of US$117.0 million (2015: US$278.9
million) which has been included in sales revenue for the year.
Foreign exchange
Premier's functional and reporting currency is US dollars.
Exchange rate exposures relate only to local currency receipts, and
expenditures within individual business units. Local currency needs
are acquired on a short-term basis. At the year end, the Group
recorded a mark-to-market loss of US$57.4 million on its
outstanding foreign exchange contracts (2015: loss of US$19.1
million). The Group currently has GBP150.0 million retail bonds,
EUR60.0 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$1.39: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, 52 per cent of total
borrowings is fixed or has been fixed using the interest rate swap
markets. On average, the cost of drawn funds for the year was 4.6
per cent. Mark-to-market credits on interest rate swaps amounted to
US$1.0 million (2015: credit of US$7.7 million), which are recorded
as movements in other comprehensive income.
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
2016, claims amounting to US$91.0 million (gross) were agreed and
settled in relation to exploration drilling in the Falkland
Islands.
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.
At year-end, the Group continued to have significant headroom on
its borrowing facilities. However, whilst the Group continues to
have sufficient liquidity available under these existing
facilities, the Group's projections currently indicate that without
an amendment to the covenant limits a breach of one of the
financial covenants applicable to the Group's borrowing facilities
is likely to arise in respect of the next covenant testing period
which, as part of the lender discussions outlined below, has been
deferred on a rolling one month basis and is due to be tested for
the 12 month period ending 31 March 2017. If there is a breach of a
financial covenant, under the existing terms of the Group's
financing facilities the Group's debt holders on all of the Group's
facilities will have the right to request repayment of the
outstanding debt and to cancel the relevant facilities.
Discussions with Premier's lending groups on the terms of a
refinancing are substantially progressed and a long form term sheet
has been agreed with advisers to the principal lending groups and
the Coordinating Committee of the Revolving Credit Facility ("RCF")
banks. The terms of the expected refinancing are summarised in note
12 to the financial statements. The process to finalise a lock-up
agreement with the lenders in respect of the refinancing is also
well advanced. Once this has been agreed the process of a Court
Scheme of Arrangement will commence alongside an investment
circular process to obtain shareholder approval.
The risk that the expected refinancing will not be approved by
Premier's lending groups and shareholders or that the covenant test
will not continue to be deferred until approval is received
constitutes a material uncertainty that may cast significant doubt
upon the use of the going concern basis of accounting. However, the
Directors have a reasonable expectation that the refinancing will
be completed on the terms that have been negotiated and also that
the covenant testing period under the Group's existing facilities
will continue to be deferred on a rolling one month basis until the
refinancing is finalised. On the assumption that the refinancing of
the Group's facilities is finalised as expected, the Group's
projections indicate that, unless there are significant falls in
prevailing oil prices or forecast production levels, the Group will
have sufficient liquidity and will be able to operate within the
revised financial covenants for a period of at least 12 months from
the date of finalising the 2016 Annual Report and Accounts.
Accordingly, after making enquiries and considering the risks
and uncertainties described above, the Directors have a reasonable
expectation that the Group and Company will have adequate resources
to continue in operational existence for the foreseeable future,
being at least the next 12 months and, therefore, 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 significant risks for the next 12
months as being:
-- Continued oil price weakness
-- Cash generation and ability to fund existing and planned projects
-- Loss of value if projects are deferred
-- Continued underperformance from the Solan field
-- Failure to deliver Catcher to schedule
-- Political and security instability in countries of current and planned
activity
-- Failure to engage constructively with the Oil and Gas Authority
and other relevant bodies
-- Timing and uncertainty of decommissioning liabilities
-- Financial viability of key suppliers and partners
-- Ability to maintain core competencies
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 2016
2016 2015
$ million $ million
---------------------------------------------------
Continuing operations
Sales revenues 983.4 1,067.2
Other operating (costs) / income (6.1) 31.9
Cost of sales (767.1) (661.0)
Impairment charge on oil and gas properties (556.2) (1,023.7)
Reduction in decommissioning estimates 75.7 -
Exploration expense (48.0) (95.4)
Pre-licence exploration costs (10.4) (13.6)
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 assets - 1.2
General and administration costs (24.1) (14.4)
------------ ------------
Operating loss (145.9) (707.8)
------------ ------------
Share of profit/(loss) in associate 1.8 (1.9)
Interest revenue, finance and other gains 13.2 40.7
Finance costs, other finance expenses
and losses (259.7) (160.6)
Loss before tax (390.6) (829.6)
Tax 522.0 (241.1)
------------ ------------
Profit/(loss) for the year from continuing
operations 131.4 (1,070.7)
------------ ------------
Discontinued operations
Loss for the year from discontinued operations(1) (8.8) (33.1)
------------ ------------
Profit/(loss) after tax 122.6 (1,103.8)
------------ ------------
Earnings/(loss) per share (cents):
From continuing operations
Basic 25.7 (209.6)
Diluted 25.4 (209.6)
------------ ------------
From continuing and discontinued operations
Basic 24.0 (216.1)
Diluted 23.7 (216.1)
------------ ------------
(1) Discontinued operations relate to the disposal of the Norway
business unit which completed in December 2015
Consolidated Statement of Comprehensive Income
For the year ended 31 December 2016
2016 2015
$ million $ million
---------------------------------------------------
Profit / (loss) for the year 122.6 (1,103.8)
----------- ------------
Cash flow hedges on commodity swaps:
(Losses) / gains arising during the year (38.3) 164.4
Less: reclassification adjustments for
gains in the year (92.4) (278.9)
----------- ------------
(130.7) (114.5)
----------- ------------
Tax relating to components of other comprehensive
income 56.1 76.0
Cash flow hedges on interest rate and
foreign exchange swaps 3.3 19.8
Exchange differences on translation of
foreign operations 3.0 (37.0)
Gains/(losses) on long-term employee
benefit plans(1) 0.2 (0.1)
----------- ------------
Other comprehensive expense (68.1) (55.8)
----------- ------------
Total comprehensive income/(expense)
for the year 54.5 (1,159.6)
----------- ------------
(1) 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 2016
2016 2015
$ million $ million
--------------------------------------
Non-current assets:
Intangible exploration and evaluation
assets 1,011.4 749.7
Property, plant and equipment 2,726.2 2,611.7
Goodwill 240.8 240.8
Investment in associate 6.2 5.3
Long-term receivables 143.4 12.0
Deferred tax assets 1,304.0 871.6
----------- -----------
5,432.0 4,491.1
----------- -----------
Current assets:
Inventories 22.3 20.8
Trade and other receivables 315.1 274.4
Derivative financial instruments 34.9 118.3
Cash and cash equivalents 255.9 401.3
628.2 814.8
Total assets 6,060.2 5,305.9
----------- -----------
Current liabilities:
Trade and other payables (412.6) (472.0)
Short-term provisions (56.1) (24.8)
Derivative financial instruments * (57.2) (2.2)
Short-term debt (273.0) -
Deferred income (27.3) (20.9)
(826.2) (519.9)
Net current (liabilities) / assets (198.0) 294.9
----------- -----------
2016 2015
$ million $ million
-----------------------------------
Non-current liabilities:
Long-term debt (2,730.5) (2,615.1)
Deferred tax liabilities (192.6) (193.3)
Deferred income (88.1) (87.6)
Derivative financial instruments * (101.6) (74.3)
Long-term provisions (1,312.1) (1,080.9)
(4,424.9) (4,051.2)
Total liabilities (5,251.1) (4,571.1)
----------- -----------
Net assets 809.1 734.8
----------- -----------
Equity and reserves:
Share capital 106.7 106.7
Share premium account 275.4 275.4
Merger reserve 374.3 374.3
Retained earnings 122.3 46.3
Other reserves (69.6) (67.9)
----------- -----------
809.1 734.8
----------- -----------
* Includes prior year derivative financial instruments of
US$74.3 million which have been reclassified as long-term in the
prior year to reflect the maturity of these instruments
Consolidated Statement of Changes in Equity
For the year ended 31 December 2016
Other reserves
-------------- -------------------------------------
Share Share Retained Merger Capital Translation Equity Total
capital premium earnings(2) reserve redemption reserves reserve
account reserve
$ million $ million $ million $ million $ million $ million $ million $ million
-------------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- -----------
At 1 January
2015 106.7 275.4 1,142.3 374.3 8.1 (48.7) 14.1 1,872.2
Purchase of
ESOP
Trust shares - - (0.9) - - - - (0.9)
Provision for
share-based
payments - - 23.0 - - - - 23.0
Transfer
between
reserves(1) - - 4.5 - - - (4.5) -
Loss for the
year - - (1,103.8) - - - - (1,103.8)
Other
comprehensive
expense - - (18.8) - - (37.0) - (55.8)
----------- ----------- ----------- ----------- ----------- ----------- ----------- -----------
At 1 January
2016 106.7 275.4 46.3 374.3 8.1 (85.7) 9.6 734.7
Purchase of
ESOP
Trust shares - - 0.2 - - - - 0.2
Provision for
share-based
payments - - 19.7 - - - - 19.7
Transfer
between
reserves(1) - - 4.6 - - - (4.6) -
Profit for the
year - - 122.6 - - - - 122.6
Other
comprehensive
expense - - (71.1) - - 3.0 - (68.1)
----------- ----------- ----------- ----------- ----------- ----------- ----------- -----------
At 31 December
2016 106.7 275.4 122.3 374.3 8.1 (82.7) 5.0 809.1
----------- ----------- ----------- ----------- ----------- ----------- ----------- -----------
(1) The transfer between reserves relates to the non-cash
interest on the convertible bonds, less the amortisation of the
issue costs that were charged directly against equity.
Consolidated Cash Flow Statement
For the year ended 31 December 2016
2016 2015
$ million $ million
-------------------------------------------------------
Net cash from operating activities 431.4 809.5
----------- -----------
Investing activities:
Capital expenditure (678.1) (992.2)
Acquisition of subsidiaries (135.0) -
Cash balance acquired in the period 24.9 -
Decommissioning funding (62.3) -
Disposal of oil and gas properties (8.8) 219.6
Loan to joint venture partner - (77.9)
----------- -----------
Net cash used in investing activities (859.3) (850.5)
----------- -----------
Financing activities:
Purchase of ESOP Trust shares 0.2 (0.9)
Proceeds from drawdown of bank loans 435.0 775.0
Debt arrangement fees (26.3) (9.6)
Repayment of long-term bank loans - (300.0)
Repayment of senior loan notes - (209.4)
Interest paid (126.3) (91.6)
----------- -----------
Net cash from financing activities 282.6 163.5
----------- -----------
Currency translation differences relating to cash
and cash equivalents (0.1) (13.0)
----------- -----------
Net (decrease) / increase in cash and cash equivalents (145.4) 109.5
----------- -----------
Cash and cash equivalents at the beginning of the
year 401.3 291.8
----------- -----------
Cash and cash equivalents at the end of the year 255.9 401.3
----------- -----------
NOTES TO THE PRELIMINARY FINANCIAL STATEMENTS
For the year ended 31 December 2016
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 8 March 2017.
The financial information for the year ended 31 December 2016
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 2015 were
approved by the Board of Directors on 24 February 2016 and
delivered to the Registrar of Companies and those for 2016 will be
delivered following the company's Annual General Meeting (AGM). The
auditor has reported on the 2016 accounts; the report was
unqualified, but did include a reference to a matter to which the
auditor drew attention by way of emphasis of matter around going
concern.
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. Further information relating to the use of the going concern
assumption, including details of a related material uncertainty due
to the risk of a covenant breach prior to finalisation of the
refinancing process, is provided in the "Going Concern" section of
the Financial Review.
Accounting policies
The accounting policies applied in this announcement are
consistent with those of the annual financial statements for the
year ended 31 December 2015, as described in those annual financial
statements. A number of amendments to existing standards and
interpretations were applicable from 1 January 2016. The adoption
of these amendments did not have a material impact on the group's
financial statements for the year ended 31 December 2016.
2. Operating segments
The Group's operations are located and managed in six business
units; namely the Falkland Islands, Indonesia, Pakistan (including
Mauritania), the United Kingdom, Vietnam and the Rest of the World.
The results for Norway, which was sold in 2015 are reported as a
discontinued operation in the prior year balances. 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.
2016 2015
$ million $ million
---------------------------------------------------
Revenue:
Indonesia 141.1 215.4
Pakistan (including Mauritania) 52.3 88.9
Vietnam 192.0 227.8
United Kingdom 598.0 535.1
----------- -----------
Total Group sales revenue 983.4 1,067.2
Other operating income - United Kingdom - 31.9
Interest and other finance revenue 0.7 29.3
----------- -----------
Total Group revenue from continuing operations 984.1 1,128.4
----------- -----------
Group operating loss:
Indonesia 35.6 62.0
Pakistan (including Mauritania) 26.7 12.2
Vietnam 86.3 27.0
United Kingdom (225.0) (721.9)
Rest of the World (35.0) (59.1)
Unallocated(1) (34.5) (28.0)
----------- -----------
Group operating loss (145.9) (707.8)
Share of profit / (loss) in associate 1.8 (1.9)
Interest revenue, finance and other gains 13.2 40.7
Finance costs and other finance expenses (259.7) (160.6)
----------- -----------
Loss before tax from continuing operations (390.6) (829.6)
Tax 522.0 (241.1)
----------- -----------
Profit/(loss) after tax from continuing operations 131.4 (1,070.7)
----------- -----------
Loss from discontinued operations (8.8) (33.1)
----------- -----------
2016 2015
$ million $ million
-----------------------------------------------------------
Balance sheet
Segment assets:
Falkland Islands 642.9 591.4
Indonesia 480.2 560.3
Pakistan (including Mauritania) 44.8 59.3
Vietnam 399.0 388.2
United Kingdom 4,136.5 3,122.5
Rest of the World 66.0 64.6
Unallocated(1) 290.8 519.6
Total assets 6,060.2 5,305.9
Liabilities:
Falkland Islands (45.6) (69.1)
Indonesia (244.5) (261.0)
Pakistan (including Mauritania) (76.3) (95.8)
Vietnam (202.1) (218.4)
United Kingdom (1,516.8) (1,137.2)
Rest of the World (3.5) (10.5)
Unallocated(1) (3,162.3) (2,779.1)
----------- -----------
Total liabilities (5,251.1) (4,571.1)
----------- -----------
Other information
Capital additions and acquisitions:
Falkland Islands 59.2 149.9
Indonesia (2.7) 39.6
Norway - 17.0
Pakistan (including Mauritania) 0.9 24.0
Vietnam (7.4) (23.9)
United Kingdom 1,247.7 1,505.5
Rest of the World 26.4 38.8
----------- -----------
Total capital additions and acquisitions 1,324.1 1,750.9
----------- -----------
Depreciation, depletion, amortisation and impairment:
Indonesia 52.7 92.6
Pakistan (including Mauritania) 7.8 42.9
Vietnam 45.0 106.2
United Kingdom 790.4 1,107.1
Rest of the World 0.6 1.6
----------- -----------
Total depreciation, depletion, amortisation and impairment 896.5 1,350.4
----------- -----------
(1) Unallocated expenditure, assets and liabilities include
amounts of a corporate nature and not specifically attributable to
a geographical segment. These items include corporate general and
administration costs, pre-licence exploration costs, cash and cash
equivalents, mark-to-market valuations of commodity contracts and
interest rate swaps, convertible bonds and other short-term and
long-term debt.
Out of the total Group worldwide sales revenues of US$983.4
million (2015: US$1,067.2 million), revenues of US$598.0 million
(2015: US$535.1 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$2,640.6
million (2015: US$2,137.5 million) located in the UK. Included in
depreciation, depletion, amortisation and impairment are impairment
charges in relation to the UK (net US$587.8 million) and impairment
reversals for Vietnam (US$25.9 million) and Pakistan (US$5.7
million).
Revenue from three customers (2015: two customers) each exceeded
10 per cent of the Group's consolidated revenue and amounted to
US$155.4 million and US$157.4 million, arising from sales of crude
oil (2015: US$132.5 million) and US$112.0 million arising from
sales of gas (2015: US$166.7 million) across all operating
segments.
3. Cost of sales
2016 2015
$ million $ million
-----------------------------------------------------
Operating costs 412.8 323.6
Gas purchases 12.4 -
Stock underlift movement (12.1) (11.4)
Royalties 13.7 22.1
Amortisation and depreciation of property, plant and
equipment:
- Oil and gas properties 332.2 315.9
- Other fixed assets 8.1 10.8
----------- -----------
767.1 661.0
----------- -----------
4. Tax
2016 2015
$ million $ million
--------------------------------------
Current tax:
UK corporation tax on profits(1) (3.0) (2.3)
UK petroleum revenue tax (0.8) 19.4
Overseas tax 53.5 80.1
Adjustments in respect of prior years (7.7) 1.4
----------- -----------
Total current tax 42.0 98.6
----------- -----------
Deferred tax:
UK corporation tax (544.3) 187.4
UK petroleum revenue tax (14.4) (10.6)
Overseas tax (5.3) (34.3)
----------- -----------
Total deferred tax (564.0) 142.5
----------- -----------
Tax on profit on ordinary activities (522.0) 241.1
----------- -----------
* The UK corporation tax current tax credit of US$3.0 million
includes a US$3.3 million UK tax refund relating to decommissioning
costs incurred in 2016 and carried back to prior periods.
The tax credit for the year can be reconciled to the loss per
the consolidated income statement as follows:
2016 2015
$ million $ million
---------------------------------------------------------
Group loss on ordinary activities before tax (390.6) (829.6)
Group loss on ordinary activities before tax at 58.4%
weighted average rate (2015: 47.4%) (228.3) (393.2)
----------- -----------
Tax effects of:
Income/expenses that are not taxable/deductible in
determining taxable profit 7.3 8.0
Financing costs disallowed for UK supplementary charge 14.4 20.1
Non-deductible field expenditure 63.2 71.0
Tax and tax credits not related to profit before tax
(mainly RFES) (61.2) (144.3)
Unrecognised tax losses 2.8 406.2
Adjustments in respect of prior years 0.7 10.6
Utilisation and recognition of tax losses not previously
recognised (392.5) (2.5)
Effect of change in tax rates 161.2 168.1
Recognition that decommissioning provision will unwind
at 50% (27.1) -
Write down of deferred tax asset previously recognised - 97.1
Recognition of investment allowances not previously
recognised (62.5) -
----------- -----------
Tax (credit) / charge for the year (522.0) 241.1
----------- -----------
Effective tax rate for the year 133.6% (29.0%)
----------- -----------
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 tax credit not related to profit before tax
includes the impact of a UK ring fence expenditure supplement claim
in the UK (US$61 million).
The deferred tax credit arises largely as a result of the
recognition of UK tax losses and investment allowances (US$455.8
million) after an increase in the estimated future profitability of
the group's UK assets following the acquisition of the E.ON North
Sea business. This has been partially offset by a charge of
US$161.2 million in relation to the supplementary charge rate
change from 20 per cent to 10 per cent during the year, with the
adverse impact of this change mitigated by US$27.1 million as the
rate applicable to the reversal of certain temporary differences on
decommissioning remained unchanged.
The future effective tax rate for the Group is impacted by the
mix of jurisdictions in which Premier 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. Deferred tax
2016 2015
$ million $ million
-------------------------
Deferred tax assets 1,304.0 871.6
Deferred tax liabilities (192.6) (193.3)
----------- -----------
1,111.4 678.3
----------- -----------
At 1 January Exchange Acquisition (Charged)/ Credited At 31 December
2016 movements Accounting credited to retained 2016
29 April to income earnings
2016 statement
$ million $ million $ million $ million $ million $ million
----------------------------
UK deferred corporation
tax:
Fixed assets and allowances (581.0) - (371.2) 232.6 - (719.6)
Decommissioning 378.8 - 172.3 (156.6) - 394.5
Deferred petroleum
revenue tax 7.2 - - (7.2) - -
Tax losses and allowances 1,129.4 - 33.5 397.2 - 1,560.1
Other - - (0.7) 65.1 - 64.4
Derivative financial
instruments (49.1) 0.3 (21.2) 13.2 56.1 (0.7)
------------ ---------- ----------- ---------- ------------ --------------
Total UK deferred
corporation tax 885.3 0.3 (187.3) 544.3 56.1 1,298.7
------------ ---------- ----------- ---------- ------------ --------------
UK deferred petroleum
revenue tax(1) (14.4) - - 14.4 - -
------------ ---------- ----------- ---------- ------------ --------------
Overseas deferred
tax(2) (192.6) - - 5.3 - (187.3)
------------ ---------- ----------- ---------- ------------ --------------
Total 678.3 0.3 (187.3) 564.0 56.1 1,111.4
------------ ---------- ----------- ---------- ------------ --------------
At 1 January Exchange Disposal (Charged)/ Credited At 31
movements to retained December
earnings 2015
2015 $ million of asset credited $ million $ million
to income
statement
$ million $ million $ million
------------------------------
UK deferred corporation
tax:
Fixed assets and allowances (756.0) - - 175.0 - (581.0)
Decommissioning 329.8 - - 49.0 - 378.8
Deferred petroleum revenue
tax 15.5 - - (8.3) - 7.2
Tax losses and allowances 1,375.3 - - (245.9) - 1,129.4
Investment allowance 157.2 - - (157.2) - -
Derivative financial
instruments (125.1) - - - 76.0 (49.1)
------------ ---------- ---------- ----------- ------------ ----------
Total UK deferred corporation
tax 996.7 - - (187.4) 76.0 885.3
------------ ---------- ---------- ----------- ------------ ----------
UK deferred petroleum
revenue tax(1) (25.0) - - 10.6 - (14.4)
------------ ---------- ---------- ----------- ------------ ----------
Overseas deferred tax(2) (254.2) 4.3 23.0 34.3 - (192.6)
------------ ---------- ---------- ----------- ------------ ----------
Total 717.5 4.3 23.0 (142.5) 76.0 678.3
------------ ---------- ---------- ----------- ------------ ----------
(1) The UK deferred petroleum revenue tax credit reflects the
reduction in PRT rate to 0 per cent during the period.
(2) The overseas deferred tax relates mainly to temporary
differences associated with fixed asset balances.
The Group's UK deferred tax assets at 31 December 2016 are
recognised to the extent that taxable profits are expected to arise
in the future against which the ring fence tax losses and
allowances can be utilised. In accordance with paragraph 37 of IAS
12 - 'Income Taxes' the group re-assessed its deferred tax assets
at 31 December 2016 with respect to ring fence tax losses and
allowances. The corporate model used to assess whether it is
appropriate to recognise all of the Group's deferred tax assets was
re-run, using an oil price assumption of Dated Brent forward curve
for two years, followed by US$65/bbl in 2019 and US$75/bbl in
'real' terms therafter. The results of the corporate model
demonstrated that as a result of an increase in the Group's
estimated future UK profitability arising from the acquisition of
assets in the period an additional net amount of US$455.8 million
in respect of the Group's UK ring fence deferred tax losses and
investment allowances could be recognised, representing full
recognition of the associated deferred tax credit.
In addition to the above, there are carried forward non-ring
fence UK tax losses of approximately US$363.8 million (2015:
US$303.5 million) for which a deferred tax asset has not been
recognised on the basis there are insufficient future profits
forecast to utilise the losses against.
None of the UK tax losses (ring fence and non-ring fence) have a
fixed expiry date for tax purposes.
No deferred tax has been provided on unremitted earnings of
overseas subsidiaries, following a change in UK tax legislation in
2009 which exempted foreign dividends from the scope of UK
corporation tax, where certain conditions are satisfied.
During the period it was announced that the rate of
supplementary charge to tax on UK ring fence profits is to be
further reduced from 20 per cent to 10 per cent with effect from 1
January 2016. The Group's deferred UK tax balances at 31 December
2016 are recognised at the reduced rate which gave rise to a
deferred tax charge of US$161.2 million in the income statement to
reflect the decrease in the opening deferred tax assets at 1
January 2016.
6. Acquisition of subsidiaries
On 28 April 2016, the Group acquired 100 per cent of the share
capital of E.ON E&P UK Ltd ("EPUK"), a wholly owned subsidiary
of E.ON SE, a German listed utility. The acquisition of EPUK brings
additional high quality assets to Premier's UK North Sea business,
the opportunity for cost and operating synergies in the North Sea,
more balanced production portfolio and adds significant immediate
production and cash flow.
The Group reached agreement on the acquisition on 13 January
2016 and was approved by Premier shareholders on 25 April 2016.
Premier paid total cash consideration of US$135.0 million,
including working capital adjustments. The acquisition has been
accounted for as a business combination. The fair values of the
identifiable assets and liabilities acquired were reported as
provisional in our half-year report and have now been finalised for
the purposes of full year 2016 financial statements.
The fair values of the oil and gas properties and intangible
exploration and evaluation assets acquired have been determined
using valuation techniques based on discounted cash flows using
forward curve commodity prices at the acquisition date, a discount
rate based on market observable data and cost and production
profiles consistent with the proved and probable reserves acquired
with each asset. The financial instruments acquired have been
valued using our forward curve oil and gas price assumptions at the
date of the acquisition. The decommissioning provisions recognised
are based on Premier's internal estimates.
The fair value of the identifiable assets and liabilities of
EPUK as at the date of acquisition were:
Provisional Adjustment Final fair
fair value $ million value
as included $ million
in the half-year
report
$ million
Assets
Intangible exploration and evaluation assets 105.7 94.1 199.8
Oil and gas properties 600.0 - 600.0
Other fixed assets 7.1 - 7.1
Long-term decommissioning funding asset 85.9 (2.6) 83.3
Inventory 2.7 - 2.7
Trade and other receivables 51.4 - 51.4
Derivative financial instruments 59.4 - 59.4
Cash and cash equivalents 24.9 - 24.9
================= ========== ==========
937.1 91.5 1,028.6
================= ========== ==========
Liabilities
Trade and other payables (50.0) - (50.0)
Decommissioning obligations - current (13.7) - (13.7)
Decommissioning obligations - non-current (565.9) 151.7 (414.2)
Deferred tax liabilities (65.6) (121.6) (187.2)
================= ========== ==========
(695.2) 30.1 (665.1)
================= ========== ==========
Total identifiable net assets acquired at
fair value 241.9 121.6 363.5
Total consideration (135.0) - (135.0)
================= ========== ==========
Excess of fair value over cost (negative
goodwill) 106.9 121.6 228.5
================= ========== ==========
The adjustments to the provisional half-year value predominantly
relate to an increase in the fair value of the Tolmount field
recognised within exploration and evaluation assets and a reduction
in the decommissioning estimates for several of the fields acquired
to align Premier's estimates either with those of the field
operator or E.ON's underlying decommissioning cost estimate. The
reduction in the decommissioning estimate for the Ravenspurn North
and Johnston fields has resulted in an adjustment to the fair value
of the long-term decommissioning funding receivable from E.ON.
Deferred tax has been recognised on the above adjustments.
The excess of the fair value of the net assets acquired over the
purchase consideration has arisen primarily due to E.ON's strategic
decision to exit the UK and Norway E&P sectors, and Premier's
willingness to acquire the entire UK business. This been recognised
immediately in the consolidated income statement.
From the date of acquisition to 31 December 2016, EPUK
contributed US$201.9 million to Group revenue and increased the
Group's loss before tax by US$40.9 million. If the acquisition of
EPUK had taken place at the beginning of the year, EPUK's
contribution to Group revenue for the year ended 31 December 2016
would have been US$336.1 million and it would have increased the
Group's loss before tax by US$43.9 million.
Costs related to the acquisition represent transaction costs of
US$5.6 million and the recognition of a settlement provision of
US$16.0 million in respect of employee costs. This settlement was
fully utilised in the second half of 2016.
7. Earnings / (loss) per share
The calculation of basic earnings / (loss) per share is based on
the profit / (loss) after tax and on the weighted average number of
Ordinary Shares in issue during the year. Basic and diluted
earnings / (loss) per share are calculated as follows:
2016 2015
$ million $ million
------------------------------------------------------------
Earnings/(loss)
Earnings/(loss) from continuing operations 131.4 (1,070.7)
Effect of dilutive potential Ordinary Shares:
Interest on convertible bonds 10.9 -
----------- -----------
Earnings/(loss) for the purpose of diluted earnings/(loss)
per share on continuing operations 142.3 (1,070.7)
Loss from discontinued operations (8.8) (33.1)
Earnings/(loss) for the purposes of diluted earnings/(loss)
per share on continuing and discontinued operations 133.5 (1,103.8)
----------- -----------
Number of shares (millions)
----------- -----------
Weighted average number of Ordinary Shares for
the purposes of basic earnings per share 510.8 510.8
Effects of dilutive potential Ordinary Shares:
Contingently issuable shares 48.8 -
----------- -----------
Weighted average number of Ordinary Shares for
the purposes of diluted earnings per share 559.6 510.8
----------- -----------
Earnings/(loss) per share from continuing operations
(cents)
Basic 25.7 (209.6)
Diluted 25.4 (209.6)
----------- -----------
Loss per share from discontinued operations (cents)
Basic (1.7) (6.5)
Diluted (1.7) (6.5)
----------- -----------
The inclusion of the contingently issuable shares in 2016
produces diluted earnings per share. In 2015 there were 40.7
million anti-dilutive Ordinary Shares mainly comprising shares to
be issued on conversion of convertible bonds.
8. Intangible exploration and evaluation ('E&E') assets
Total
$ million
Cost:
At 1 January 2015 825.7
Exchange movements (37.2)
Additions during the year 217.9
Disposals (161.3)
Exploration expense (95.4)
At 31 December 2015 749.7
Exchange movements 6.1
Additions during the year 103.8
Acquisition of subsidiaries 199.8
Exploration expense (48.0)
At 31 December 2016 1,011.4
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 for drilling the
Laverda/Slough and Bagpuss prospects in the North Sea and Foz in
Brazil.
The outcome of ongoing exploration, and therefore whether the
carrying value of E&E assets will ultimately be recovered, is
inherently uncertain. The balance carried forward is predominantly
in relation to the Group's prospects in the Falkland Islands and
the Tolmount project in the UK.
The disposal in 2015 is for E&E costs that were held in
relation to the Group's Norway business unit.
9. Property, plant and equipment
Oil and gas Other fixed Total
properties assets $ million
$ million $ million
Cost:
At 1 January 2015 5,498.6 59.9 5,558.5
Exchange movements - (2.0) (2.0)
Asset acquisition 614.8 - 614.8
Additions during the year 912.3 5.9 918.2
Disposals - (2.4) (2.4)
At 31 December 2015 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
=========== =========== ==========
Amortisation and depreciation:
At 1 January 2015 3,091.3 37.2 3,128.5
Exchange movements - (1.3) (1.3)
Charge for the year 315.9 10.8 326.7
Impairment charge 1,023.7 - 1,023.7
Disposals - (2.2) (2.2)
=========== =========== ==========
At 31 December 2015 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
Impairment charge 556.2 - 556.2
Disposals - (1.4) (1.4)
At 31 December 2016 5,318.9 47.8 5,366.7
Net book value:
At 31 December 2015 2,594.8 16.9 2,611.7
=========== =========== ==========
At 31 December 2016 2,709.7 16.5 2,726.2
=========== =========== ==========
* Finance costs that have been capitalised within oil and gas
properties during the year total US$34.0 million (2015: US$58.8
million), at a weighted average interest rate of 4.6 per cent
(2015: 4.4 per cent).
Other fixed assets include items such as leasehold improvements,
motor vehicles and office equipment. In April 2016, Premier
completed the acquisition of E.ON E&P UK Limited.
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 reserves estimates are based on a number
of underlying assumptions including oil and gas prices, future
costs, oil and gas in place and reservoir performance, which are
inherently uncertain. Management uses established industry
techniques to generate its estimates and regularly references its
estimates against those of joint venture partners or external
consultants. However, the amount of reserves that will ultimately
be recovered from any field cannot be known with certainty until
the end of the field's life.
Impairment charge
The impairment charge in the current year relates to the Solan
asset in the UK. The impairment charge of US$652.2 million was
calculated by comparing the future discounted pre-tax cash flows
expected to be derived from production of commercial reserves (the
value-in-use) against the carrying value of the asset. The future
cash flows were estimated using an oil price assumption equal to
the Dated Brent forward curve in 2017 and 2018, and US$65/bbl in
2019 and US$75/bbl in 'real' terms thereafter (2015: long-term
price of US$80 real/bbl) and were discounted using a pre-tax
discount rate of 8 per cent for the UK assets (2015: 8 per cent)
and 12.5 per cent for the non-UK assets (2015: 12.5 per cent).
Assumptions involved in impairment measurement include estimates of
commercial reserves and production volumes, future oil and gas
prices, discount rate 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 the asset over its economic life and the reduction in the long
term oil price assumption to US$75/bbl (real). The recoverable
amount of the Solan asset based on its estimated value-in-use
assumption set out above is US$570.4 million.
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$96.0 million has been credited to
the income statement for the year, which has partially offset the
impairment charge recognised. The reversal of impairment relates to
Huntington (UK, US$50.0 million), Chim Sáo (Vietnam, US$25.9
million), Kyle (UK, US$14.4 million) and Kadanwari (Pakistan,
US$5.7 million). An increase in the short term oil price assumption
and an increase in the 2P reserves on Chim Sáo have driven the
reversal of impairment recognised. The recoverable amounts of the
assets at 31 December 2016 were Huntington, US$61.8 million; Chim
Sáo, US$583.1 million; Kyle, US$31.9 million; and, Kadanwari,
US$9.1 million.
Goodwill
Goodwill of US$240.8 million has been specifically assigned to
the Catcher field in the UK, which is considered the
cash-generating unit for the purposes of any impairment testing of
this goodwill. The Group tests goodwill annually for impairment, or
more frequently if there are indications that goodwill might be
impaired. The recoverable amounts are determined from value-in-use
calculations with the same key assumptions as noted above for the
impairment calculations. The discount rate used is 8 per cent
(2015: 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 2030. This period exceeds five years but is believed to be
appropriate as it is underpinned by estimates of commercial
reserves provided by 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$143.2 million. If the discount rate was 1% higher or if the
long term oil price assumption was US$5/bbl lower, being reasonably
possible changes in key assumptions, no impairment charge would
arise.
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$28.3
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$58.0 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).
10. 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$7.9 million during the year reflecting barrels
delivered to FlowStream in the period since first oil from Solan.
This has been offset by the finance charge for the year of US$14.9
million.
The portion of the deferred income that is expected to be
delivered to FlowStream within the next 12 months has been
classified as a current liability.
11. Notes to the cash flow statement
2016 2015
$ million $ million
-----------------------------------------------------
Loss before tax for the year (390.6) (829.6)
Adjustments for:
Depreciation, depletion, amortisation and impairment 896.5 1,350.4
Other operating costs / (income) 3.1 (31.9)
Exploration expense 48.0 95.4
Excess of fair value over consideration (228.5) -
Provision for share-based payments 8.7 7.2
Reduction in decommissioning estimates (75.7) -
Share of profit / loss in associate (1.8) 1.9
Interest revenue and finance gains (13.2) (40.7)
Finance costs and other finance expenses 259.7 160.6
Other gains and losses - (1.2)
Deferred income (repaid) / received (7.9) 100.0
Operating cash flows before movements in working
capital 498.3 812.1
Decrease in inventories 1.3 5.3
Decrease in receivables 25.1 382.1
Decrease in payables (33.0) (297.6)
---------- ----------
Cash generated by operations 491.7 901.9
Income taxes paid (60.9) (94.0)
Interest income received 0.6 1.6
---------- ----------
Net cash from operating activities 431.4 809.5
---------- ----------
Analysis of changes in net debt:
2016 2015
$ million $ million
a) Reconciliation of net cash flow to movement in
net debt:
Movement in cash and cash equivalents (145.4) 109.5
Proceeds from drawdown of long-term bank loans (435.0) (775.0)
Repayment of long-term bank loans - 300.0
Repayment of senior loan notes - 209.4
Non-cash movements on debt and cash balances (predominantly
FX) 57.4 36.1
---------- ----------
Increase in net debt in the year (523.0) (120.0)
Opening net debt (2,242.2) (2,122.2)
---------- ----------
Closing net debt (2,765.2) (2,242.2)
---------- ----------
b) Analysis of net debt:
Cash and cash equivalents 255.9 401.3
Borrowings (3,021.1) (2,643.5)
---------- ----------
Total net debt (2,765.2) (2,242.2)
---------- ----------
12. Subsequent Events
Refinancing
In February 2017, Premier announced the following:
-- Agreement of representatives of its Private Lenders to a long form
term sheet, subject to credit approvals
-- Agreement of revised key terms between Premier and representatives
of its convertible bond holders, subject to agreement by the Private
Lenders
-- Proposed amended terms to its retail bonds
In return the lenders will receive a revised security and
covenant package, benefits from enhanced economics and exercise
certain governance controls.
The long form term sheet has been circulated to the lenders
under the Company's Revolving Credit Facility ("RCF"), term loan,
Schuldschein and US Private Placement notes ("USPP") (together the
"Private Lenders") for formal credit committee approval with
lock-up agreements expected to be received during March 2017.
Revised financing documentation will now be finalised with
completion of the refinancing currently anticipated by the end of
May 2017.
Key terms of the refinancing
The RCF, term loan, US Private Placement notes (USPP) and
Schuldschein notes.
Proposed amendments have been largely agreed with the
Co-ordinating Committee of the RCF Group and representatives of the
other Private Lenders as follows:
-- Confirmation of total existing facilities of US$3.9 billion with drawn capacity preserved
-- Alignment of final maturity dates to 31 May 2021
-- Amendment of Premier's financial covenants, currently anticipated to be net debt to EBITDA
cover ratio test to 9.5x until end 2017 reducing to 5.0x at the end of 2018, before returning
to 3.0x from the beginning of 2019
-- Interest cover ratio reduced to 1.50x before increasing to 3.0x in 2019
-- Covenant net debt (which includes issued letters of credit) to be less than US$2.95 billion
by end 2018
Enhanced economics for lenders, including:
-- A margin uplift of 1.5 per cent over existing pricing with an additional 1 per cent for the
Schuldschein lenders for conversion of their existing bilateral facilities into an English
law-based syndicated facility
-- Amendment fees of 1 per cent with an additional 0.5 per cent for the Schuldschein lenders
-- Equity warrants representing up to 90 million new shares, being 15 per cent of Premier's issued
shares (enlarged for the potential new issue) at a price of 42.75 pence per share, equivalent
to 7.6 per cent dilution based on the latest closing share price. The warrants will have a
five year term. Alternatively, lenders will have the option to take up synthetic warrants
in the form of a deferred fee of comparable value to the equity warrants. Take-up of the synthetic
warrants will reduce the number of new shares to be issued under the equity warrants
-- Crystallisation of the make-whole on the USPP to be calculated at the completion date of the
refinancing
A security package which provides priority over unsecured
creditors, in addition a portion of the RCF and certain other debt
obligations of up to US$800 million will receive super-senior
status.
Certain governance controls including:
-- Annual approval of Premier's overall capex and exploration budgets
-- Final sanction of significant new projects
-- Certain approval rights in respect of acquisitions and disposals
The retail bonds
Substantially the same economic terms are being offered to the
retail bondholders as to the Private Lenders. The key terms
proposed are:
-- Maturity date extended by six months to 31 May 2021
-- Enhanced economics comprising an interest rate uplift of 1.5 per cent, amendment fees of 1
per cent and pro-rata participation in the warrant offering as above
-- Participation in the security package which gives priority over unsecured creditors, ranking
alongside the private debt facilities (with senior status)
Positive feedback has been received from a number of significant
retail bondholders who have been consulted on these terms. A
prospectus will be issued to retail bondholders to elect between
equity warrants and synthetic warrants
Convertible bonds
On 1 March 2017 Premier announced that amended terms to its
US$245m convertible bonds had been agreed with all members of an ad
hoc committee of convertible bondholders.
The key amended terms are:
-- Maturity date extended to 31 May 2022
-- Interest rate to remain at 2.5 per cent, to be paid, at the election of the company, either
in new shares, or from the proceeds of sale of new shares or (subject to the terms of an
inter-creditor
agreement between the Company and its other lenders) in cash
-- Conversion price to be reset at a premium of 20 per cent to the higher of the volume weighted
average price of Premier's shares over the period from 1 March 2017 to 22 March 2017 (inclusive)
or 62 pence
-- Equity warrants representing 3 per cent of Premier's issued share capital (enlarged for the
issue of equity warrants under the terms of the overall refinancing) at a price of 42.75 pence/share
-- No cash amendment fee
-- Issuer right to require conversion at the conversion price at any time after one year if the
value of Premier's shares is at least 140 per cent of the conversion price for 25 consecutive
dealing days
Implementation of the proposed refinancing
The proposed RCF, term loan, USPP and Retail Bond amendments
will be effected through a Scottish scheme of arrangement of each
of Premier and Premier Oil UK Limited (the Schemes), which must be
approved by a majority in number and 75 per cent in value of the
Scheme creditors attending and voting at meetings arranged for this
purpose.
Schuldschein lenders and the convertible bondholders will each
consider and, if they so decide, consent to the terms of the
refinancing outside of the Scheme process.
The refinancing will require shareholder approval in respect of
the potential issue of the warrant shares and shares that could be
issued as a result of the change to the convertible bond conversion
price. The approval will be sought at a general meeting.
13. External audit
This preliminary announcement is consistent with the audited
financial statements of the group for the year-ended 31 December
2016.
14. Publication of financial statements
It is anticipated that the full Annual Report and Financial
Statements will be published in April 2017. 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 17 May 2017 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, Net Debt and Liquidity and are defined
below.
-- EBITDAX: Earnings before interest, tax, depreciation, amortisation,
impairment, exploration spend and reduction in decommissioning estimates.
In the current year it also excludes negative goodwill that arose
on the E.ON acquisition. Determined by adjusting operating profit
/ (loss) for the year. This is a useful indicator of underlying
business performance and is a key metric in the calculation of one
of our financial covenants.
-- 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.
-- Net Debt: The net of cash and cash equivalents and short and long
term debt recognised on the balance sheet. This is an indicator
of the Group's indebtedness, capital structure and a key metric
used in the calculation of one of our financial covenants.
-- 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 letter 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 2016
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
2016 128.0 43.8 2.0 250.4 0.3 79.8 104.1 33.5 17.9 29.4 252.3 436.9 331.9
------ ---- ------ ------ ------ ------ ------ ------ ------ ----- ------ ------ ------
Revisions(1) (1.5) - (0.1) 19.1 (0.1) 11.9 (5.9) (7.6) 10.3 13.4 2.7 36.8 9.7
------ ---- ------ ------ ------ ------ ------ ------ ------ ----- ------ ------ ------
Discoveries
and extensions - - - - - - - - - - - - -
------ ---- ------ ------ ------ ------ ------ ------ ------ ----- ------ ------ ------
Acquisitions
and divestments(1) - - - - - - 14.0 126.7 - - 14.0 126.7 37.8
------ ---- ------ ------ ------ ------ ------ ------ ------ ----- ------ ------ ------
Production - - (0.3) (26.1) (0.1) (17.4) (9.0) (16.6) (4.4) (7.2) (13.8) (67.3) (26.1)
------ ---- ------ ------ ------ ------ ------ ------ ------ ----- ------ ------ ------
At 31 December
2016 126.5 43.8 1.6 243.4 0.1 74.3 103.2 136.0 23.8 35.6 255.2 533.1 353.3
------ ---- ------ ------ ------ ------ ------ ------ ------ ----- ------ ------ ------
Total Group developed and undeveloped reserves
Proved on
production - - 0.9 127.7 0.1 46.8 33.7 54.4 17.2 23.1 51.9 252.0 98.3
------ ---- ------ ------ ------ ------ ------ ------ ------ ----- ------ ------ ------
Proved
approved/justified
for development 102.8 28.5 0.4 47.3 - - 24.0 33.2 2.3 5.9 129.5 114.9 151.1
------ ---- ------ ------ ------ ------ ------ ------ ------ ----- ------ ------ ------
Probable on
production - - 0.1 23.7 - 27.5 20.3 37.3 3.0 2.5 23.4 91.0 39.4
------ ---- ------ ------ ------ ------ ------ ------ ------ ----- ------ ------ ------
Probable
approved/justified
for development 23.7 15.3 0.2 44.7 - - 25.2 11.1 1.3 4.1 50.4 75.2 64.5
------ ---- ------ ------ ------ ------ ------ ------ ------ ----- ------ ------ ------
At 31 December
2016 126.5 43.8 1.6 243.4 0.1 74.3 103.2 136.0 23.8 35.6 255.2 533.1 353.3
------ ---- ------ ------ ------ ------ ------ ------ ------ ----- ------ ------ ------
Notes:
1 Revisions to reserves are based on re-evaluation of production
performance, drilling results and future plans in Chim Sáo and Dua
(Vietnam); Anoa, Gajah Baru, Pelikan, Naga & Kakap (Indonesia);
Catcher Area, Solan, B-Block, Kyle & Wytch Farm (UK), Bhit and
Qadirpur (Pakistan)
2 Discoveries in Laverda are not classified as reserves and do not appear in this table
3 Acquisition of E.ON assets in the UK account for the entire acquisition reserve addition
4 Proved plus portable 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 direct interests
on an entitlement basis, which incorporates the terms of the PSCs
in Indonesia, Vietnam and Mauritania. On an entitlement basis
reserves were 332.3 mmboe as at 31 December 2016 (2015: 315.5
mmboe). This was calculated at year-end 2016, using an oil price
assumption equal to US$58bbl in 2017, US$58/bbl in 2018, US$65/bbl
in 2019 and US$75/bbl in 'real' terms thereafter.
This information is provided by RNS
The company news service from the London Stock Exchange
END
FR UGURGWUPMUCB
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March 09, 2017 02:02 ET (07:02 GMT)
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