TIDMPMO
RNS Number : 5615W
Premier Oil PLC
20 August 2015
Half-Yearly Results for the six months to 30 June 2015
Tony Durrant, Chief Executive, commented:
"First half operating cash flows increased year-on-year driven
by reliable production, our hedging programme and operating cost
savings of 30 per cent. With Solan on-stream later this year and
Catcher in 2017, we expect both growing production and reduced debt
levels. Amended financial covenants announced today provide balance
sheet flexibility and demonstrate the on-going support of our
capital providers. With the optionality in our portfolio, we are
well placed for growth in a stronger oil price environment."
Operational highlights
-- Production averaged 60.4 kboepd (2014 H1: 64.9 kboepd),
despite recent disposals of non-core assets; full year guidance is
maintained at 55 kboepd
-- Increased momentum across sanctioned developments; Solan
first oil is still targeted for Q4 2015 and Catcher first oil on
track for 2017
-- Progressing Vette and Sea Lion for 2016 investment decisions;
ongoing engagement with the supply chain indicates significant
potential for reduced costs
-- Discoveries at Zebedee and Isobel Deep, Falkland Islands and
incremental resource added at Anoa Deep, Indonesia; ongoing
programmes in Norway, Falklands
-- New venture focus on building portfolio in Ceará Basin,
Brazil and Sureste Basin, Mexico
-- Formal sales process for Pakistan assets initiated
Financial highlights
-- Strong operating cash flow of US$513.0 million (2014 H1: US$499.4 million)
-- Profit before tax and impairments of US$170.6 million (2014
H1: US$194.4 million); non-cash post-tax impairments of US$225.7
million result in loss after tax of US$375.2 million (2014 H1:
profit after tax of US$172.7 million)
-- Operating cost and gross G&A savings of 30 per cent and 20 per cent
-- Amendments to Premier's debt covenants secured out to mid-2017
-- c.60 per cent of 2015 H2 liquid volumes hedged at US$92/bbl;
c.25 per cent of 2016 liquids hedged at US$69/bbl
-- 2015 full year capex guidance unchanged at US$900 million (development) and US$240 million (exploration); US$500 million of total capex expected for 2016
-- Net debt marginally lower at US$2,093 million; cash and
undrawn facilities of US$1.5 billion
ENQUIRIES
Premier Oil plc Tel: + 44 (0)20 7730 1111
Tony Durrant
Richard Rose
Bell Pottinger Tel: + 44 (0)20 3772 2500
Gavin Davis
Henry Lerwill
There will be a presentation to analysts at the company's
Falkland Islands Business Unit Office on Buckingham Palace Road at
09.30am today which 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 and hard copies can be requested by
contacting the company (e-mail: premier@premier-oil.com or
telephone: +44 (0)20 7730 1111).
A video interview with Tony Durrant, CEO, discussing the 2015
Half Year Results is available to watch here
https://vimeo.com/136759897
CHAIRMAN'S STATEMENT
Industry context
Considerable volatility in the oil markets persisted in the
first half. This has been driven by a number of factors, including
US unconventional and OPEC production holding firm, the anticipated
return of Iran to the global oil market and concerns around Chinese
economic growth. While it is generally agreed that the oil price
will eventually recover from current levels, as supply is impacted
by the significant reduction in capital investment today, a longer
period of lower oil prices is now forecast by most. Consequently,
the first half has seen the industry focus on re-setting its cost
base and adjusting its expenditure plans in order to withstand such
an environment.
For our part, we have continued to capture sustainable savings
in our operating costs, to defer discretionary capex and to
actively manage our portfolio. The weakness in the oil price post
period-end serves as an important reminder that we must sustain
these efforts. We remain focused on managing our balance sheet
while achieving the highest level of operational and safety
performance and maintaining optionality in the portfolio for future
growth.
Premier's performance
Premier delivered a robust production performance in the first
half averaging 60.4 kboepd (2014 H1: 64.9 kboepd). This was driven
by high operating efficiency across our portfolio and
outperformance from our operated Chim Sáo field in Vietnam, where
our team have adeptly managed reservoir performance and maintained
asset integrity while controlling costs.
We continue to progress our sanctioned projects which,
once-on-stream, will generate important cash flows for the group.
Offshore productivity has improved markedly on our operated Solan
project and we now have increased confidence around our targeted
fourth quarter first oil date. Development drilling and subsea
installation work has commenced on schedule for our Catcher
project. While progress in the construction of the FPSO hull has
been slower than planned, our team, together with our FPSO
contractor BW Offshore, are putting in place the appropriate
mitigating actions. The project remains on track to come on-stream
in 2017.
The weak order backlog in many segments of the service sector
provides an opportunity to reduce costs on our unsanctioned
projects, notably Vette in Norway and Sea Lion in the Falkland
Islands. In this respect, re-engagement with the supply chain on
both projects has been encouraging and the teams continue to
progress the projects towards investment decisions in 2016. These
decisions will depend upon the oil price outlook at the time, cost
reductions secured as well as our ability to fund the projects
without putting our balance sheet at risk.
In the first half, important discoveries were made at Zebedee
and Isobel Deep in the Falkland Islands and additional resource
potential confirmed at Anoa Deep, Indonesia. Competition for high
quality exploration acreage is less intense in the current
environment and this presents an opportunity for our Exploration
New Ventures team to replenish our portfolio at low cost. We are
pleased to have been awarded two blocks in the under-explored but
proven Sureste basin in Mexico's Round 1 post period-end. At the
same time, we have continued to divest and relinquish our more
mature exploration acreage in our legacy areas.
Potential acquisition opportunities that enhance our asset base
and create synergies with our existing core businesses continue to
be evaluated. We also look to dispose of non-core assets where we
can realise appropriate value. We successfully reduced our balance
sheet exposure to the Solan project via an agreement with
FlowStream in May. Discussions are also on-going with interested
parties about the sale of our Pakistan business with conclusion of
the process targeted by year-end. We plan to initiate partnership
discussions with potential co-investors in our Sea Lion development
once the current round of negotiations with contractors is complete
and the four-well exploration campaign in the North Falklands Basin
has been executed.
I noted in February that, while our long-term unsecured debt
structure and supporting banking relationships leave us well
placed, we would need to manage our covenant headroom if lower oil
prices persisted. I believe that we have reacted quickly in terms
of taking costs out of our business, as evidenced by the
significant drop in our operating costs and G&A costs. This,
together with a strong production performance, the benefit of our
hedging programme and proceeds from disposals, resulted in over
US$400 million of covenant headroom at period-end. However, like
the rest of the industry, we need to be prepared for a period of
sustained commodity price weakness. Consequently, post period-end,
we have successfully agreed with our banks and bondholders to amend
our financial covenants out to mid-2017. This should ensure
sufficient debt headroom in the period prior to first oil from
Catcher, even if weak oil prices persist.
Health, safety and environmental matters continue to be of
paramount importance to us. We will not compromise on the integrity
and safety of our operations, ring-fencing expenditure associated
with asset integrity and safety from the on-going cost reduction
programmes across the business. We are very pleased to be able to
report that our trend of improved safety performance has continued
into 2015. Our Total Recordable Injury Rate in the first half fell
further to stand at 1.05 per million man-hours. Process safety
performance was also above expectations with only one Loss of
Primary Containment reported from our operated assets over the
period. Environmentally, performance was also good with greenhouse
gas intensity at our operated assets showing a reduction compared
to 2014. Our production operations management systems at Balmoral
in the UK, and at Anoa and Gajah Baru in Indonesia, retained their
OHSAS 18001 and ISO 14001 certifications, as did our worldwide
drilling management systems.
Outlook
Our strong operational performance together with the benefit of
our hedging programme and extensive cost savings, have enabled us
to deliver strong cash flows in the first half. In the second half,
we will remain focused on managing our balance sheet as we continue
to invest in our approved projects. In particular, we look forward
to first oil from Solan later this year.
(MORE TO FOLLOW) Dow Jones Newswires
August 20, 2015 02:01 ET (06:01 GMT)
With new, untaxed production from Solan, our aim is to manage
the business such that we are able to deleverage the balance sheet
while continuing to ensure the integrity of our production assets
and to invest in our Catcher project, even in a conservative oil
price environment. These two projects will provide some underlying
growth. Beyond that, the extent to which we can invest in new
projects for further growth and consider other forms of shareholder
return will be determined by the oil price and the level to which
we can capture further cost savings.
Mike Welton
Chairman
OPERATIONAL REVIEW
FALKLAND ISLANDS
Pre-FEED activities and contractor discussions have
significantly de-risked the Premier-operated Sea Lion project and
confirmed an attractive Phase 1a development. The capex profile for
this fits well with Premier's expected cash flows, and exploration
successes at Zebedee and Isobel Deep have highlighted the potential
for high value follow-on developments.
Development
In November 2014, pre-FEED work commenced on the Sea Lion Phase
1a development, which targets 160 mmbbls of reserves in the
north-east of PL032 using a single subsea drill centre and a leased
FPSO. Dynamic modelling studies have shown that the development
plan for this fully appraised reservoir is robust and, in
particular, the location of the drill centre provides access to
reserves in the north west of PL032 should the opportunity
arise.
After extensive work with leading FPSO and SURF contractors, the
surface facilities plan has been simplified and is now well
developed. Key project contractors will be selected ahead of FEED
(rather than at the end of FEED) and, to this end, commercial and
technical proposals have been received and are being evaluated. The
FPSO will be financed by the FPSO provider and Premier is exploring
the use of a similar leasing scheme for the subsea system. Of the
remaining project capex, approximately 75 per cent is anticipated
to occur in 2018 and 2019 after Catcher is on-stream.
Conceptual studies have commenced to examine potential
development schemes for the remaining reserves in PL032 (Phase 1b),
the satellite accumulations in the north of PL004 (Phase 2) and for
the Isobel/Elaine fan complex in the south of PL004 (Phase 3).
Discussions are continuing with other stakeholders to finalise the
necessary arrangements to progress the project and, as with all oil
projects in attractive tax regimes, the project remains very
sensitive to the long term oil price.
Exploration
Premier's four-well North Falklands Basin campaign, which is
targeting multiple stacked fans in PL004 and PL032, commenced in
March. To date, two discoveries have been made from the first two
wells. The Zebedee well in PL004 has added around 50 mmbbls of
resource to a potential Phase 2 development. The Isobel Deep well,
which was the first test of the Isobel/Elaine fan complex,
encountered oil-bearing sandstone at the prognosed depth and has
opened up a new play in the previously unexplored southern part of
PL004. The unrisked Pmean resource estimate of the Isobel/Elaine
fan complex is 400 mmbbls.
Following the suspension of the Isobel Deep well due to
unexpected overpressure, the Eirik Raude rig was transferred to
another operator in the South Falklands Basin. The rig is expected
to return to the North Falklands Basin later this quarter to drill
the Jayne East and Chatham wells. Consideration is being given to
performing more drilling at Isobel Deep as part of the programme,
possibly replacing the Jayne East well.
Portfolio management
Premier anticipates initiating discussions with potential
co-investors in its Sea Lion development once the current round of
negotiations with contractors is complete and the four-well
exploration campaign in the North Falklands Basin has been
executed.
INDONESIA
The Premier-operated Natuna Sea Block A delivered stable
production from an operating cost base of around US$7/boe over the
period. Premier also successfully appraised the Anoa Deep
discovery, adding incremental resource.
Production & Development
Net production from Indonesia in the first six months was 13.2
kboepd (2014 H1: 14.0 kboepd), while there remained a continued
focus on optimising the cost base.
Premier sold 208 BBtud (gross) (2014 H1: 228 BBtud) from its
operated Natuna Sea Block A in the first half. Singapore demand for
gas sold under GSA1 remained robust, averaging 312 BBtud (2014 H1:
300 BBtud). Premier's Anoa and Pelikan fields delivered 133 BBtud
(2014 H1: 144 BBtud) and accounted for 43 per cent of GSA1
deliveries (2014 H1: 48 per cent), against a contractual share of
39.9 percent. Sales of Gajah Baru and Naga gas dedicated to GSA2
averaged 70 BBtud (2014 H1: 81 BBtud). Deliveries from Gajah Baru
and Naga under the Domestic Swap Agreement (DSA) were less than
expected due to competition with low price diesel fuel. However,
end-users have been making take or pay payments in full as per the
terms of the DSA/GSA.
Gas sales from the non-operated Kakap field averaged 26 BBtud
(gross) (2014 H1: 29 BBtud) over the period. Gross liquids
production from the Kakap field averaged 3.7 kbopd (2014 H1: 3.8
kbopd) and 1.4 kbopd from the Anoa field (2014 H1: 1.6 kbopd).
The Pelikan field was successfully brought on-stream in March
within budget, following first gas from the Naga field in November
2014. This increased deliverability from Natuna Sea Block A allows
Premier increased operational flexibility, the ability to fill any
shortfall from other suppliers within the existing contracts and
the potential to respond to any future increase in Singapore or
domestic gas demand.
Elsewhere on Natuna Sea Block A, the next generation of
developments to backfill our existing Singapore and domestic market
contracts continue to progress. FEED has been completed on the
Bison and Iguana projects and is nearing completion on the Gajah
Puteri field. An investment decision on these projects will be made
in 2016.
Evaluation of the potential development scenarios for the 2014
Kuda/Singa Laut discoveries on the Tuna Block remains on-going.
Premier is conducting a farm-out process with a view to reducing
its 65 per equity interest in the block in order to manage its
exposure going forward.
Exploration & Appraisal
The Anoa West-1 well successfully appraised the Anoa Deep
discovery made by the West Lobe-5X well in 2012, encountering the
same fractured gas bearing sandstones. The well was deepened to
explore for additional reservoir sections and encountered further
fractured gas-bearing sands. A drill stem test produced gas to
surface but sustained flow was not achieved due to completion
issues. Nonetheless, the well has successfully confirmed the P50
pre-drill estimate of 13 mmboe associated with the Anoa Deep
discovery and has added a further 18 bcf of resource to the Lama
play. Further potential remains to be tested beneath the depth
reached in both this well and beneath the West Lobe-5X well.
Premier continues to mature a number of other leads and prospects
elsewhere in the Lama play to drillable status.
Portfolio management
In January, Premier successfully completed the sale of its 41.67
per cent non-operated interest in Block A Aceh onshore Indonesia
for an after-tax consideration of US$40 million.
NORWAY
The development focus in Norway is to push forward the
Premier-operated Vette project to an investment decision in 2016.
The exploration team have been preparing for the drilling of the
Myrhauk well, which spudded post period-end.
Development
In early 2015, Premier elected to defer the submission of the
development plan (PDO) for the Vette project following the sharp
fall in the oil price. Since then, Premier has taken the
opportunity to re-engage with the supply chain with the aim of
securing lower-cost development options.
The low oil price environment has resulted in several
alternative lower-cost production facilities to the originally
envisaged new build FPSO becoming available, which are now being
evaluated. These have the potential to significantly enhance the
economics of the Vette project. A decision on project sanction is
expected in 2016. FEED engineering work on the Sevan 650 new build
solution has been completed and this option remains viable as a
fall back development concept.
Work has also progressed to mature the interpretation of the
Herring prospect in the neighbouring PL406 licence. Herring and the
adjacent Mackerel discovery are possible future tie-back
developments to a Vette facility.
Exploration
Premier's immediate exploration focus in Norway is on the
Myrhauk well on the south east flank of the Mandal High. The
potentially play opening well spudded in July and is targeting
Jurassic sands within a robust four-way dip closure. The results of
this well are expected in September.
Premier was successful in the APA 2014 Licensing Round with the
award of a 20 per cent interest in PL782S which is located in the
Norwegian North Sea and will be operated by ConocoPhillips. Work
has commenced in the partnership to define the details of the
seismic reprocessing and interpretation work programme. There is no
well commitment with the award.
PAKISTAN
Premier's Pakistan business continues to generate positive and
stable net cash flows for the group. The group's interests are in
well-established gas producing fields with proven operational
performance. During the first half, the average realised gas price
was above US$4/mmscf while operating costs remained low at around
US$3/boe. Following receipt of an indicative offer for the Pakistan
assets, Premier has initiated a formal sales process.
Production and Development
Production in Pakistan averaged 10.3 kboepd (2014 H1: 12.4
kboepd), from Premier's six non-operated producing gas fields.
These are world-class gas fields which in total produce some 25 per
cent of Pakistan's domestic gas production.
(MORE TO FOLLOW) Dow Jones Newswires
August 20, 2015 02:01 ET (06:01 GMT)
Production from the Qadirpur and Zamzama fields continues in
line with expectation, averaging 2.8 kboepd (2014 H1: 3.3 kboepd)
and 2.2 kboepd (2014 H1: 3.5 kboepd) respectively. Similarly,
average production from the Bhit/Badhra fields was 3.3 kboepd
(2014: 3.1 boepd), and production from the Kadanwari gas field
averaged 2.0 kboepd (2014 H1: 3.5 kboepd). Increased production
from the Bhit/Badhra fields was driven by the successful
reconfiguration of the Bhit compressors as well as new production
from three Badhra wells.
The Zarghun South gas field, which came on-stream in August
2014, produced 86 boepd (net to Premier) over the period. All costs
pertaining to Premier's 3.75 per cent working interest in the field
are carried by the Operator.
Exploration
Premier drilled one exploration well - Bhit South-1 - in
Pakistan during the first six months of the year. Bhit South-1
spudded in November 2014 and reached target depth in January 2015.
While gas was encountered, the sands were of poor reservoir
quality, and the well was subsequently plugged and abandoned.
In addition to existing identified conventional targets, Premier
continues to evaluate the shale gas potential in its Kadanwari and
Qadirpur gas fields.
Portfolio management
During the period, Premier received an indicative offer for its
Pakistan business. Consequently, Premier has initiated a formal
sales process and initial marketing documents have been issued to a
number of prospective purchasers.
MAURITANIA
Production and development
Production from the Chinguetti field averaged 400 barrels of oil
per day (bopd) (2014 H1: 500 bopd) net to Premier during the first
six months of the year. The fall in production was driven by
natural decline from the existing wells.
UNITED KINGDOM
The UK delivered a strong production performance while at the
same time operating costs have been reduced significantly, helped
by the disposal of the high-cost Scott area in 2014. Development
activity is focussed on delivering the Solan project in the fourth
quarter and delivery of the Catcher project in 2017. Once
on-stream, production from these new projects will more than offset
natural decline within the group's portfolio underpinning a rising
production profile.
Production
Production from Premier's UK fields averaged 16.9 kboepd (2014
H1: 19.4 kboepd). The decrease can be attributed to the sale of the
high cost Scott area which averaged 3.9 kboepd in 2014 H1.
Production from the Premier-operated Balmoral area averaged 3.4
kboepd (2014 H1: 3.7 kboepd) and was broadly in line with
expectations. The non-operated Kyle field, which was reinstated in
July 2014, also performed as anticipated delivering 1.8 kboepd.
Production from the non-operated Wytch Farm averaged 5.4 kboepd
(2014 H1: 5.8 kboepd), lower than forecast due to several key wells
requiring work overs and integrity issues with the water injection
line during the second quarter, which have now been rectified.
Production from the non-operated Huntington field averaged 6.2
kboepd (2014 H1: 7.8 kboepd). Huntington production was restricted
during the first quarter as a result of constraints on the gas
export route. This was largely compensated for by higher than
forecast production in the second quarter due to the minimal impact
of the CATS pipeline summer maintenance period on the field's
performance. Amendments to the gas transportation agreement were
executed on 12 June providing improved certainty of Huntington gas
export volumes going forward. Field facilities production uptime in
the last four months has exceeded 90 per cent.
UK unit operating costs were US$29/boe in the first half (2014
H1: US$35/boe). This reduction reflects the disposal of the
high-cost Scott area assets at end 2014 but also cost management
work across all remaining assets. UK G&A costs have been
reduced, reflecting a lower headcount in the business unit. A
particular area of focus has been on the allocation of resources to
priority areas and optimisation of activities such as efficiency of
vessels and helicopter movements, with increasing co-operation with
neighbouring operators.
Developments
Commissioning of the Solan infrastructure continued over the
period with increased productivity realised from May, due to
improved weather and organisational changes in the project
execution team. On 10 August, the Regalia flotel was successfully
bridge-linked to the Solan facilities, replacing the Siem Spearfish
walk-to-work vessel, which provided continuity of people and
workflow on the platform following the departure of the Victory
flotel in May. The Regalia flotel will facilitate habitation of the
platform and completion of the commissioning of the production
systems to allow first oil, still targeted for the fourth
quarter.
The first pair of producer-injector wells to the Solan platform
was successfully tied-in during March. Commissioning of the subsea
infrastructure commenced in June and remains on-track for
completion in September. In parallel, drilling of the second pair
of producer-injector wells commenced in July. The second producer
is nearing completion with the second injector expected to spud in
September. With both pairs of wells on-stream, the field is
expected to ramp up to plateau production rates of 20-25 kboepd.
Cash spend to end July stood at US$1.65 billion.
On the Catcher project, subsea installation work commenced with
the successful installation of the pipeline end manifold and two
templates at Burgman and Varadero. In addition, the 60 kilometre
gas export pipeline was successfully laid during July with minimal
weather downtime. The Ensco 100 rig came on hire in July and batch
drilling of the first four development wells has commenced.
Operations are running to plan, within schedule and budget.
Fabrication of the FPSO hull and topsides is on-going in Asia.
While there have been some scheduling issues associated with the
construction of the hull, Premier, together with FPSO contractor BW
Offshore, is putting in place mitigating actions to safeguard the
sail-away date of the FPSO. The Premier-operated Catcher project
remains and on schedule for first oil in 2017.
Exploration
Preparations to drill two exploration wells in the UK North Sea
in 2016 are underway. Specifically, Premier plans to drill an
exploration commitment well at the Laverda/Slough prospect to the
north of the Catcher area and an exploration well targeting the
Bagpuss prospect on the Halibut Horst in the first half of 2016.
During the period, Premier continued to high grade and rationalise
its UK North Sea exploration portfolio with several licences
relinquished or sold.
Portfolio management
In May, Premier successfully acquired Chrysaor's 40 per cent
interest in the Solan field for nil upfront cash consideration and
entered into an agreement with FlowStream whereby a US$100 million
payment was received in return for granting FlowStream 15 per cent
of production from the field for a period of time. As a result,
partner funding concerns around the Solan project have been removed
while, at the same time, the group's balance sheet exposure to the
project has been reduced.
VIETNAM
A robust production performance, together with substantially
reduced operating costs and minimal capital expenditure, resulted
in the Vietnam business unit generating strong positive net cash
flows for the group.
Production
Production from the Premier-operated Block 12W, which contains
the Chim Sáo and Dua fields, averaged 19.6 kboepd, up 16 per cent
(2014 H1: 16.9 kboepd). Dua, which came on-stream in July 2014, has
helped extend the plateau from Chim Sáo. However, the main driver
behind Block 12W's strong production was high operating efficiency
of 95 per cent and better than predicted reservoir performance.
High uptime was achieved as a result of investments, aimed at
improving the reliability of the Chim Sáo facilities, made during
2014. While plateau rates from Block 12W have been maintained for
longer and at higher rates than originally envisaged at sanction,
some natural decline from the existing wells is now being seen.
In response to lower oil prices, operating costs have been
proactively managed downwards. Chim Sáo operating costs were around
US$10/bbl, reflecting both savings in expenditure and higher
production. Cost savings have been achieved through a variety of
measures: renegotiation of contracts; assumption of direct control
of the offshore operations and maintenance services for the Chim
Sáo FPSO; operating efficiencies, such as changing crew shift
patterns and the use of lower cost and more fuel efficient supply
vessels.
EXPLORATION
Premier's exploration portfolio has seen significant change over
the last few years, moving away from its traditional but now mature
areas. The forward focus is on under-explored but proven
hydrocarbon basins that have the potential to develop into new
business units in the 2018 and beyond time frame.
Premier successfully entered Mexico with the award of a
non-operated 10 per cent interest in Blocks 2 and 7 at no upfront
cost in Mexico's Round 1 in July 2015. Premier has the option to
increase its interest to 25 per cent prior to drilling. The Blocks
contain numerous leads in established and emerging plays, located
in the shallow water Sureste Basin, a proven and prolific
hydrocarbon province in the Gulf of Mexico. Premier is carried on
each of the blocks up to the point of the first well, most likely
2017.
(MORE TO FOLLOW) Dow Jones Newswires
August 20, 2015 02:01 ET (06:01 GMT)
In April, Premier increased its footprint in the Ceará Basin,
our top ranked basin in Brazil, by farming into CE-M-661 for a
non-operated 30 per cent equity interest at no upfront cost.
Multi-client 3D seismic acquisition across Premier's operated
blocks CE-M-665 and CE-M-717 and non-operated block CE-M-661
(subject to government approval) is expected to commence in the
third quarter of 2015. Interpretation of recently reprocessed 3D
seismic surveys, which partly cover block CE-M-717, has indicated
the presence of several structures that may form additional targets
for the 2017/18 drilling campaign. Elsewhere in Brazil, fast-track
processed data has been received from the 2014 3D multi-client
seismic acquisition in the Foz do Amazonas basin where Premier has
a non-operated 35 per cent interest in Block FZA-M-90. Final
results from the processing are expected at the end of 2015.
Premier holds a 30 per cent non-operated interest in Block 12,
onshore Iraq, in the underexplored western part of one of the
world's most prolific oil basins. A 3D seismic survey acquisition
programme was completed in the first quarter and the processed
products are now being interpreted ahead of selecting a well
location for drilling in 2016/17.
In Kenya, Premier drilled the unsuccessful Badada-1 well onshore
Block 2B (Premier equity 55 per cent) in early 2015. Premier
withdrew from the licence at the end of April and consequently no
longer has an acreage position in Kenya.
FINANCE REVIEW
Income Statement
Despite the continued low oil price environment, Premier
continues to generate strong operating cash flows and has made
significant progress in reducing its underlying costs of
production
Group production on a working interest basis averaged 60.4
kboepd in the first half of 2015 compared to 64.9 kboepd in the
first half of 2014 and 63.6 kboepd for the full-year 2014. Lower
production year-on-year is a result of the Scott area disposal and
natural decline in the portfolio, partially offset by increased
production from the Chim Sáo field in Vietnam. This was driven by
high operating efficiency and better than predicted reservoir
performance. Entitlement production for the period was 55.7 kboepd
(2014 H1: 59.8 kboepd).
Oil and gas prices, which fell steeply in the second half of
2014, have remained low against prices observed in the last four
years, with the Dated Brent oil price in the first half of 2015
fluctuating between US$45.2/bbl and US$66.7/bbl and averaging
US$57.8/bbl (2014 H1: US$108.9/bbl). Premier's revenues and
cashflows were substantially protected by prior period forward
sales resulting in our average realised oil price for the period
being US$83.7/bbl on a post-hedge basis (2014 H1:
US$107.9/bbl).
The average realised gas price (post-hedge) for Indonesian
production sold into Singapore was US$12.3 per thousand standard
cubic feet (mscf) (2014 H1: US$16.9/mscf). In Pakistan, gas prices
across all producing fields averaged US$4.4/mscf (2014 H1:
US$4.7/mscf). The combined effect of lower realised prices and a
slight reduction in production year-on-year saw a 35 per cent
decrease in sales revenues to US$577.0 million (2014: US$884.7
million).
Cost of sales, excluding impairment charges, in the period were
US$298.8 million (2014 H1: US$502.3 million). Underlying operating
costs were US$13.7 per barrel of oil equivalent (boe) (2014 H1:
US$18.5/boe) with the year-on-year reduction mainly reflecting the
sale of the high cost Scott area in the UK as well as significant
savings realised in on-going operations across the group.
Amortisation of oil and gas properties fell from US$224.0
million to US$170.6 million and on a unit basis from US$19.1/boe to
US$15.6/boe. Impairment charges for the period amounted to US$385.3
million (2014: US$144.0 million) on a pre-tax basis and were
recognised for the Solan field in the UK. The principal drivers for
the impairment charge are increases in the expected cost to
complete the project and future decommissioning costs, a reduction
in the forecast forward curve used to perform the impairment
testing and the recognition of contingent consideration payable to
Chrysaor in future periods.
Exploration expense and pre-licence exploration costs amounted
to US$51.5 million (2014 H1: US$49.8 million) and mainly relates to
the unsuccessful Badada-1 well drilling costs in Kenya and a write
off of costs held for the Pancing discovery in Indonesia. Operating
loss for the period was US$167.0 million (2014 H1: profit US$92.0
million). The group general and administrative ("G&A") costs on
a gross basis were significantly reduced year-on-year at US$115.0
million (2014 H1: US$140.0) million, resulting in net G&A costs
to the group of US$8.4 million (2014 H1: US$12.7 million)
Net finance costs of US$47.7 million (2014 H1: US$43.5 million)
include unwinding of the discount on decommissioning of US$21.5
million, bank fees of US$29.0 million and a net impairment of the
interest accrued on the loan due from the Chrysaor, the former
joint venture ("JV") partner on the Solan field, of US$5.3 million.
Finance costs capitalised during the period totalled US$25.2
million (2014 H1: US$17.0 million).
The group has a current tax charge for the period of US$61.7
million (2014: US$150.4 million) and a non-cash deferred tax charge
for the period of US$98.8 million (2014: credit of US$272.7
million) which results in a total tax charge for the period of
US$160.5 million (2014: credit of US$122.3 million).
The total tax charge for the period is distorted by a number of
specific tax items arising in the UK. These include the effects of
the UK Supplementary Charge to Tax rate reduction from 32 to 20 per
cent on the opening deferred tax asset balance (US$119.4 million
charge), and the net impact of ring fence expenditure supplement
claims in the UK during the period offset by the non-recognition of
UK tax losses and small field allowances due to the low prevailing
oil price environment (US$105.9 million net charge). In addition,
an element of the group impairment charge for the period was
treated as a permanent difference which resulted in a reduction in
the impairment deferred tax credit of approximately US$33.0
million. After adjusting for the net impact of these items of
US$258.3 million, the underlying group tax during the period was a
credit of US$97.8 million, an effective tax rate of 45.6 per
cent.
Loss after tax for the period to 30 June 2015 was US$375.2
million (2014 H1: profit US$172.7 million). Basic loss per share
for the period was 73.5 cents (2014 H1: earnings of 32.8
cents).
Acquisitions and disposals
During the period, Premier acquired Chrysaor's 40 per cent
interest in the Solan field for nil upfront cash consideration. In
return, Chrysaor can potentially receive a number of contingent
payments from a notional 40 per cent interest in the field's net
operating cash flow. As a result of this transaction, Premier will
recognise 100 per cent of the Solan field's production, revenues
and capex in its financial results. The consideration for the
transaction, recognised as part of our total development cost for
the Solan field (pre-impairment) was US$614.8 million, which
included deemed consideration of US$549.0 million for waiving of
the outstanding loan balance due from Chrysaor and US$56.0 million
for the fair value of the contingent consideration using Premier's
long term oil price planning assumptions.
Separately, Premier received cash of US$82.7 million from the
completion of the disposals of the non-operated Scott area assets
in the UK North Sea (completed in December 2014) and the sale of
Block A Aceh onshore Indonesia (completed in January 2015).
Cash flow
Cash flow from operating activities amounted to US$513.0 million
(2014 H1: US$499.4 million). Included within this balance is US$100
million received by Premier from FlowStream Commodities in return
for granting FlowStream 15 per cent of production from the Solan
field until sufficient barrels have been delivered to achieve the
rate of return within the agreement. Capital expenditure in the
period was US$439.7 million (2014 H1: US$506.3 million).
Capital expenditure
2015 2014
Half-year Half-year
$ million $ million
Fields/developments * 379.7 469.9
Exploration 137.0 137.7
Other 0.9 3.1
----------------------- ----------- -----------
Total 517.6 610.7
----------------------- ----------- -----------
* Funding provided to the former JV partner on Solan has been
included within development capex above
The majority of the development expenditure in the first half
was for the Solan field in the UK and the Dua field in Vietnam.
Exploration expenditure in the first half was mainly relating to an
exploration campaign in the Falkland Islands.
Balance sheet
Net debt at 30 June 2015 of US$2,092.5 million (December 2014:
US$2,122.2 million) including cash resources of US$372.4 million
(December 2014: US$291.8 million) was slightly lower than the year
end position primarily due to our strong production performance,
Premier's hedging programme, lower operating costs and proceeds
received from disposals. Cash received from FlowStream of US$100
million has been recognised as deferred income on the balance sheet
and will be released to the income statement once barrels are
delivered to FlowStream post first oil from Solan.
2015 2014 2014
Half-year Year-end Half-year
$ million $ million $ million
--------------------------- ----------- ----------- -----------
Cash and cash equivalents 372.4 291.8 255.0
Convertible bonds (230.3) (228.5) (226.3)
Other long-term debt (2,234.6) (2,185.5) (1,717.8)
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August 20, 2015 02:01 ET (06:01 GMT)
--------------------------- ----------- ----------- -----------
Net debt (2,092.5) (2,122.2) (1,689.1)
--------------------------- ----------- ----------- -----------
Long-term borrowings consist of convertible bonds, UK retail
bonds, senior loan notes and bank debt. During the period, Premier
bought back US$148 million and EUR40 million of its US private
placement notes at a discount to par and repaid a US$300 million
term loan maturing in the second quarter of 2015. Premier retains
significant cash and undrawn facilities which, at 30 June 2015,
were US$372.4 million and US$1.1 billion respectively.
Premier has agreed with its lending group to modify its
financial covenants until mid-2017. Under this agreement our
financial covenants have been modified as follows:
-- EBITDAX cover ratio increases to 4.75 times until the period
ending 31 December 2016 and to 4.5 times for the period ending 30
June 2017, before returning to its pre-modified level of 3.0 times
for the period ending 31 December 2017.
-- Interest cover ratio reduced to 3.0 times until the period
ending 30 June 2017, before returning to its pre-modified level of
4.0 times for the period ending 31 December 2017.
Under the terms of the agreement with our lending group, we are
restricted from proposing a dividend to the extent that our
projections indicate that our financial covenants will be above
their pre-modified levels.
Financial risk management
The Board's commodity pricing and hedging policy continues to be
to lock in oil and gas prices for a proportion of expected future
production at a level which ensures that investment programmes for
sanctioned projects are adequately funded. Where investment
requirements are well covered by cash flows without hedging, it is
recognised that there may be an advantage, in periods of strong
commodity prices, in locking in a portion of forward production at
favourable prices on a rolling forward 12-18 month basis.
At period end, 6.4 mmbbls of Dated Brent oil were hedged through
forward sales for the rest of 2015 and full-year 2016. This volume,
represents approximately 60 per cent of the group's expected
liquids entitlement production in H2 2015 at an average of
US$92.3/bbl and 24 per cent of total forecast liquids production
for 2016 at an average price of US$68.6/bbl. In addition, 108,000
metric tonnes (MT) of high sulphur fuel oil (HSFO), which drives
the group's gas contract pricing in Singapore, has been sold
forward for the rest of 2015 and 2016 representing approximately 17
per cent of our expected Indonesian gas entitlement production for
the next 18 months. For 2015, 36,000 MT have been forward sold at
an average price of US$341.8/MT, whilst 72,000 MT have been forward
sold for 2016 at an average price of US$400/MT.
During the first half of 2015, forward oil sales of 2.7 mmbbls
and forward gas sales of 84,000 MT of HSFO matured at a net credit
of US$145.0 million (2014: net cost US$8.3 million) which has been
included within sales revenue.
Premier operates and reports in US dollars. Foreign exchange
exposure therefore relates only to certain sterling and other local
currency expenditures. These exposures are covered by the purchase
of local currency on a spot or short-term forward basis. The
average sterling/dollar rate achieved for transactions maturing in
the first half of 2015 was US$1.52:GBP1. Forward foreign exchange
contracts outstanding at 30 June amounted to GBP130 million at an
average rate of US$1.53:GBP1.
The group's main debt facilities include both fixed and floating
interest rate borrowings. At 30 June, 35 per cent of the group's
total debt of US$2.5 billion was denominated in fixed rate
instruments, or locked into fixed rate costs using the interest
rate swap market.
There have been material transactions or changes in transactions
with related parties as described in note 24 of the Annual Report
and Financial Statements for the year ended 31 December 2014.
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 30 June 2015, the group had significant headroom on its
existing borrowing facilities and related financial covenants, but
there was a possible risk that in a period of ongoing sustained low
oil prices it might breach one of its financial covenants within
the next 12 months. Accordingly, the group has reached agreement
with its lending group to modify its financial covenants, as
summarised above. The group's forecasts and projections, indicate
that the group will be able to operate within the requirements of
its modified financial covenants and within the current level of
its borrowing facilities for 12 months from the date of approval of
the Interim Report and Accounts. The directors therefore continue
to adopt the going concern basis in preparing the 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, those 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 the following principal risk areas for
the remaining six months of the year:
-- health, safety, environment and security (HSES);
-- production and development delivery;
-- commodity price volatility;
-- exploration success and reserves addition;
-- host government - political and fiscal risks;
-- organisational capability;
-- joint venture partner alignment; and
-- financial discipline and governance
Further information detailing the way in which these risks are
mitigated is provided on pages 22 to 25 of the 2014 Annual Report
and Financial Statements. This information is also available on
company's website www.premier-oil.com.
STATEMENT OF DIRECTORS' RESPONSIBILITIES
Each of the directors of the company confirms that to the best
of his or her knowledge:
a) the condensed set of financial statements, which has been
prepared in accordance with International Accounting Standard 34 -
'Interim Financial Reporting' gives a true and fair view of the
assets, liabilities, financial position and profit of the
company;
b) the Half-Yearly Results statement includes a fair review of
the information required by DTR 4.2.7R (indication of important
events during the first six months and description of principal
risks and uncertainties for the remaining six months of the year);
and
c) the Half-Yearly Results statement includes a fair review of
the information required by DTR 4.2.8R (disclosure of related
parties' transactions and changes therein).
On behalf of the Board
Richard Rose
Finance Director
19 August 2015
Disclaimer
This results announcement contains certain forward-looking
statements that are subject to the usual risk factors and
uncertainties associated with the oil and gas exploration and
production business. Whilst the group believes the expectations
reflected herein to be reasonable in light of the information
available to it at this time, the actual outcome may be materially
different owing to factors beyond the group's control or otherwise
within the group's control but where, for example, the group
decides on a change of plan or strategy. Accordingly, no reliance
may be placed on the figures contained in such forward-looking
statements.
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August 20, 2015 02:01 ET (06:01 GMT)
CONDENSED CONSOLIDATED INCOME STATEMENT
Six months Six months Year to
to 30 June to 30 June 31 December
2015 2014 2014
Unaudited Unaudited Audited
Note $ million $ million $ million
============================================= ==== =========== =========== =============
Sales revenues 2 577.0 884.7 1,629.4
Cost of sales 3 (298.8) (502.3) (986.6)
Impairment charge on oil and gas properties
* 9 (385.3) (144.0) (784.4)
Exploration expense (45.3) (37.4) (58.5)
Pre-licence exploration costs (6.2) (12.4) (25.3)
(Loss)/profit on disposal of assets - (83.9) 2.7
General and administration costs (8.4) (12.7) (25.4)
============================================= ==== =========== =========== =============
Operating (loss)/profit (167.0) 92.0 (248.1)
Share of profit in associate - 1.9 1.9
Interest revenue, finance and other
gains 4 47.4 24.9 58.5
Finance costs and other finance expenses 4 (95.1) (68.4) (196.3)
(Loss)/profit before tax (214.7) 50.4 (384.0)
Tax 5 (160.5) 122.3 173.7
============================================= ==== =========== =========== =============
(Loss)/profit for the period/year (375.2) 172.7 (210.3)
(Loss)/earnings per share (cents):
Basic 7 (73.5) 32.8 (40.3)
Diluted 7 (73.5) 31.3 (40.3)
============================================= ==== =========== =========== =============
* The June 2014 income statement has been restated to disclose
separately the impairment charge on oil and gas properties
Notes 1 to 13 form an integral part of these condensed financial
statements.
CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
Six months Six months Year to
to 30 June to 30 June 31 December
2015 2014 2014
Unaudited Unaudited Audited
Note $ million $ million $ million
============================================= ==== =========== =================== ============
(Loss)/Profit for the period/year (375.2) 172.7 (210.3)
--------------------------------------------- ---- ----------- ------------------- ------------
Cash flow hedges on commodity swaps:
Gains/(losses) arising during the
period/year 4.8 (17.0) 296.1
Less: reclassification adjustments
for (gains)/ losses in the period/year (145.0) 7.6 (46.0)
============================================= ==== =========== =================== ============
(140.2) (9.4) 250.1
Tax relating to components of other
comprehensive income 6 80.9 5.8 (139.0)
Cash flow hedges on interest rate and
foreign exchange swaps (2.8) 6.2 15.5
Exchange differences on translation
of foreign operations (13.4) 3.4 (48.3)
Losses on long-term employee benefit
plans* - - (0.2)
============================================= ==== =========== =================== ============
Other comprehensive (expense)/income (75.5) 6.0 78.1
============================================= ==== =========== =================== ============
Total comprehensive expense/income
for the period/year (450.7) 178.7 (132.2)
============================================= ==== =========== =================== ============
* Not expected to be reclassified subsequently to profit and loss
account
All comprehensive income is attributable to the equity holders
of the parent.
CONDENSED CONSOLIDATED BALANCE SHEET
At At At 31 December
30 June 30 June 2014
2015 2014 Audited
Unaudited Unaudited
Note $ million $ million $ million
========================================= ==== ========== =========== ===============
Non-current assets:
Goodwill 240.8 240.8 240.8
Intangible exploration and evaluation
assets 8 910.3 753.5 825.7
Property, plant and equipment 9 2,946.9 2,679.5 2,430.0
Investments 7.7 8.4 7.6
Long-term employee benefit plan surplus 0.8 1.3 0.8
Other receivables 9.1 316.4 494.1
Deferred tax assets 6 945.3 1,057.2 971.7
========================================= ==== ========== =========== ===============
5,060.9 5,057.1 4,970.7
========================================= ==== ========== =========== ===============
Current assets:
Inventories 29.8 44.7 26.1
Trade and other receivables 344.4 473.8 411.0
Tax recoverable 41.1 89.0 57.9
Derivative financial instruments 96.5 16.3 273.4
Cash and cash equivalents 372.4 255.0 291.8
Assets held for sale - 327.9 56.7
884.2 1,206.7 1,116.9
========================================= ==== ========== =========== ===============
Total assets 5,945.1 6,263.8 6,087.6
========================================= ==== ========== =========== ===============
Current liabilities:
Trade and other payables (469.2) (607.3) (544.5)
Current tax payable (74.5) (122.6) (84.2)
Provisions (11.8) (15.7) (14.1)
Derivative financial instruments (53.2) (47.6) (48.1)
Short-term debt - - (300.0)
Deferred income 11 (17.3) - -
Liabilities directly associated with
assets held for sale - (235.5) (1.8)
(626.0) (1,028.7) (992.7)
========================================= ==== ========== =========== ===============
Net current assets 258.2 178.0 124.2
========================================= ==== ========== =========== ===============
Non-current liabilities:
Convertible bonds (230.3) (225.9) (228.1)
Other long-term debt (2,211.3) (1,707.1) (1,858.1)
Deferred tax liabilities 6 (244.3) (296.4) (254.2)
Deferred income 11 (82.7) - -
Long-term provisions (1,100.2) (753.7) (864.0)
Long-term employee benefit plan deficit (17.2) (14.5) (18.3)
(3,886.0) (2,997.6) (3,222.7)
========================================= ==== ========== =========== ===============
Total liabilities (4,512.0) (4,026.3) (4,215.4)
========================================= ==== ========== =========== ===============
Net assets 1,433.1 2,237.5 1,872.2
========================================= ==== ========== =========== ===============
Equity and reserves:
Share capital 106.7 109.2 106.7
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August 20, 2015 02:01 ET (06:01 GMT)
Share premium account 275.4 275.4 275.4
Merger reserve 374.3 374.3 374.3
Retained earnings 718.8 1,453.8 1,142.3
Other reserves (42.1) 24.8 (26.5)
========================================= ==== ========== =========== ===============
1,433.1 2,237.5 1,872.2
========================================= ==== ========== =========== ===============
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
____________Attributable to the equity holders
of the parent___________
Other reserves
=========== =========== ========= ----------- ===================================== =========
Share Capital
Share premium Retained Merger redemption Translation Equity
capital account earnings reserve reserve reserves reserve Total
$ million $ million $ million $ million $ million $ million $ million $ million
------------------ ----------- ----------- --------- ----------- ----------- ----------- ----------- ---------
At 1 January 2014 110.5 275.3 1,342.1 374.3 4.3 (0.4) 18.3 2,124.4
Issue of Ordinary
Shares - 0.1 - - - - - 0.1
Purchase and
cancellation
of own shares (3.8) (93.0) - 3.8 - - (93.0)
Purchase of ESOP
Trust shares - - (6.4) - - - - (6.4)
Provision for
share-based
payments - - 23.3 - - - - 23.3
Transfer between
reserves* - - 4.2 - - - (4.2) -
Dividends paid - - (44.0) - - - - (44.0)
Total
comprehensive
expense - - (83.9) - - (48.3) - (132.2)
------------------ ----------- ----------- --------- ----------- ----------- ----------- ----------- ---------
At 31 December
2014 106.7 275.4 1,142.3 374.3 8.1 (48.7) 14.1 1,872.2
Provision for
share-based
payments - - 11.6 - - - - 11.6
Transfer between
reserves* - - 2.2 - - - (2.2) -
Total
comprehensive
expense - - (437.3) - - (13.4) - (450.7)
------------------ ----------- ----------- --------- ----------- ----------- ----------- ----------- ---------
At 30 June 2015 106.7 275.4 718.8 374.3 8.1 (62.1) 11.9 1,433.1
------------------ ----------- ----------- --------- ----------- ----------- ----------- ----------- ---------
At 1 January 2014 110.5 275.3 1,342.1 374.3 4.3 (0.4) 18.3 2,124.4
Issue of Ordinary
Shares - 0.1 - - - - - 0.1
Cancellation of
Ordinary
Shares (1.3) - (33.3) - 1.3 - - (33.3)
Provision for
share-based
payments - - 11.6 - - - - 11.6
Dividends paid - - (44.0) - - - - (44.0)
Transfer between
reserves* - - 2.1 - - - (2.1) -
Total
comprehensive
income - - 175.3 - - 3.4 - 178.7
------------------ ----------- ----------- --------- ----------- ----------- ----------- ----------- ---------
At 30 June 2014 109.2 275.4 1,453.8 374.3 5.6 3.0 16.2 2,237.5
------------------ ----------- ----------- --------- ----------- ----------- ----------- ----------- ---------
* 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.
CONDENSED CONSOLIDATED CASH FLOW STATEMENT
Six months Six months Year to
to 30 June to 30 June 31 December
2015 2014 2014
Unaudited Unaudited Audited
Note $ million $ million $ million
======================================= ==== ============ ============ =============
Net cash from operating activities 10 513.0 499.4 924.3
======================================= ==== ============ ============ =============
Investing activities:
Capital expenditure (439.7) (506.3) (1,195.5)
Proceeds from disposal of oil and
gas properties 82.7 - 130.7
Loan to joint venture partner* (77.9) (104.4) (318.4)
======================================= ==== ============ ============ =============
Net cash used in investing activities (434.9) (610.7) (1,383.2)
======================================= ==== ============ ============ =============
Financing activities:
Proceeds from issuance of Ordinary
Shares - - 0.1
Purchase and cancellation of own
shares - - (93.0)
Net purchases of ESOP Trust shares - - (6.4)
Share buyback - (33.3) -
Proceeds from drawdown of bank loans 550.0 100.0 655.0
Debt arrangement fees - (1.7) (22.1)
Repayment of bank loans and senior
notes (500.8) (70.0) (100.0)
Dividends paid - (44.0) (44.0)
Interest paid (48.7) (47.2) (98.1)
======================================= ==== ============ ============ =============
Net cash from/(used in) financing
activities 0.5 (96.2) 291.5
======================================= ==== ============ ============ =============
Currency translation differences relating
to cash and cash equivalents 2.0 13.6 10.3
============================================= ============ ============ =============
Net increase/(decrease) in cash and
cash equivalents 80.6 (193.9) (157.1)
Cash and cash equivalents at the
beginning of the period/year 291.8 448.9 448.9
======================================= ==== ============ ============ =============
Cash and cash equivalents at the
end of the period/year 10 372.4 255.0 291.8
--------------------------------------- ---- ============ ============ =============
*Funding provided to the former Joint Venture partner until the
completion of the asset acquisition of 40 per cent interest in the
Solan field (see note 9).
NOTES TO THE CONDENSED FINANCIAL STATEMENTS
1. BASIS OF PREPARATION
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.
The condensed financial statements for the six months ended 30
June 2015 were approved for issue in accordance with a resolution
of a committee of the Board of Directors on 19 August 2015.
The information for the year ended 31 December 2014 contained
within the condensed financial statements does not constitute
statutory accounts within the meaning of section 434 of the
Companies Act 2006. Statutory accounts for the year ended 31
December 2014 were approved by the Board of Directors on 25
February 2015 and delivered to the Registrar of Companies. The
auditor reported on those accounts; the report was unqualified, did
not draw attention to any matters by way of emphasis and did not
contain any statement under section 498(2) or 498(3) of the
Companies Act 2006.
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August 20, 2015 02:01 ET (06:01 GMT)
The financial information contained in this report is unaudited.
The condensed consolidated income statement, condensed consolidated
statement of comprehensive income, condensed consolidated statement
of changes in equity and the condensed consolidated cash flow
statement for the six months to 30 June 2015, and the condensed
consolidated balance sheet as at 30 June 2015 and related notes,
have been reviewed by the auditors and their report to the company
is attached.
Basis of preparation
The condensed financial statements for the six months ended 30
June 2015 have been prepared in accordance with IAS 34 - 'Interim
Financial Reporting', as adopted by the European Union and with the
requirements of the Disclosure and Transparency Rules issued by the
Financial Conduct Authority. These condensed financial statements
should be read in conjunction with the annual financial statements
for the year ended 31 December 2014, which have been prepared in
accordance with International Financial Reporting Standards as
adopted by the European Union.
The condensed financial statements have been prepared on the
going concern basis. Further information relating to the going
concern assumption is provided in the Financial Review.
Accounting policies
The accounting policies applied in these condensed financial
statements are consistent with those of the annual financial
statements for the year ended 31 December 2014, as described in
those annual financial statements. A number of new standards,
amendments to existing standards and interpretations were
applicable from 1 January 2015. The adoption of these amendments
did not have a material impact on the group's condensed financial
statements for the half-year ended 30 June 2015.
2. OPERATING SEGMENTS
The group's operations are located and managed in seven business
units; namely the Falkland Islands, Indonesia, Norway, Pakistan
(including Mauritania), the United Kingdom, Vietnam and the Rest of
the World.
Some of the business units currently do not generate revenue or
have any material operating income.
The group is only engaged in one business of upstream oil and
gas exploration and production, therefore all information is being
presented for geographical segments.
Six months Six months Year to
to 30 June to 30 June 31 December
2015 2014 2014
Unaudited Unaudited Audited
$ million $ million $ million
==================================== ============ ============ =============
Revenue:
Indonesia 124.1 175.9 325.7
Pakistan (including Mauritania) 52.1 77.0 141.6
Vietnam 142.5 241.3 473.3
United Kingdom 258.3 390.5 688.8
==================================== ============ ============ =============
Total group sales revenue 577.0 884.7 1,629.4
Interest and other finance revenue 28.6 15.1 39.4
Total group revenue 605.6 899.8 1,668.8
==================================== ============ ============ =============
Group operating (loss)/profit:
Indonesia 59.1 9.9 104.5
Norway (0.2) (2.4) (17.4)
Pakistan (including Mauritania) 17.9 26.0 32.4
Vietnam 37.1 107.7 153.5
United Kingdom (236.9) (16.4) (446.6)
Rest of the World (29.5) (11.8) (23.6)
Unallocated* (14.5) (21.0) (50.9)
------------------------------------------ ------------------- ------- --------
Group operating (loss)/profit (167.0) 92.0 (248.1)
Share of profit in associate - 1.9 1.9
Interest revenue, finance and other
gains 47.4 24.9 58.5
Finance costs and other finance expenses (95.1) (68.4) (196.3)
(Loss)/profit before tax (214.7) 50.4 (384.0)
Tax (160.5) 122.3 173.7
========================================== =================== ======= ========
(Loss)/profit after tax (375.2) 172.7 (210.3)
========================================== =================== ======= ========
Six months Six months Year to
to 30 June to 30 June 31 December
2015 2014 2014
Unaudited Unaudited Audited
$ million $ million $ million
Balance sheet - Segment assets:
Falkland Islands 553.0 358.6 430.6
Indonesia 653.2 765.4 702.0
Norway 189.9 274.2 197.9
Pakistan (including Mauritania) 85.2 132.5 101.7
Vietnam 476.3 659.1 569.9
United Kingdom** 3,442.6 3,787.6 3,428.2
Rest of the World 76.1 79.0 92.1
Unallocated* 468.8 207.4 565.2
--------------------------------- ------------ ------------ -------------
Total assets 5,945.1 6,263.8 6,087.6
--------------------------------- ------------ ------------ -------------
* Unallocated expenditure and assets include amounts of a corporate
nature and not specifically attributable to a geographical segment.
These items include corporate general and administration costs
and pre-licence exploration costs, cash and cash equivalents
and mark-to-market valuations of commodity contracts and interest
rate swaps.
** Includes goodwill.
3. COST OF SALES
Six months Six months Year to
to 30 June to 30 June 31 December
2015 2014 2014
Unaudited Unaudited Audited
$ million $ million $ million
============================================ ============ ============ =============
Operating costs 149.8 216.9 436.1
Stock overlift/underlift movement (39.7) 32.0 48.5
Royalties 12.6 24.7 45.6
Amortisation and depreciation of property,
plant and equipment
- Oil and gas properties 170.6 224.0 446.1
- Other fixed assets 5.5 4.7 10.3
298.8 502.3 986.6
============================================ ============ ============ =============
4. INTEREST REVENUE AND FINANCE COSTS
Six months Six months Year to
to 30 June to 30 June 31 December
2015 2014 2014
Unaudited Unaudited Audited
$ million $ million $ million
========================================== ============ ============ =============
Interest revenue, finance and other
gains:
Short-term deposits 0.7 1.2 2.1
Gain on forward contracts 9.9 - -
Gain on extinguishment of debt 4.1 - -
Loan to joint venture partner 27.9 12.9 36.8
Exchange differences and others 4.8 10.8 19.6
========================================== ============ ============ =============
47.4 24.9 58.5
========================================== ============ ============ =============
Finance costs:
Bank loans, overdrafts and bonds (29.0) (25.8) (62.1)
Payable in respect of convertible
bonds (5.3) (5.2) (10.5)
Payable in respect of senior loan
notes (15.6) (18.2) (31.3)
Long-term debt arrangement fees (4.4) (3.3) (7.0)
Loss on forward contracts (11.3) - (18.9)
Exchange differences and others - (11.2) (0.6)
========================================== ============ ============ =============
(65.6) (63.7) (130.4)
Other finance expenses
Unwinding of discount on decommissioning
provision (21.5) (21.7) (46.9)
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Provision for doubtful loan to joint
venture partner (33.2) - (61.2)
========================================== ============ ============ =============
(54.7) (21.7) (108.1)
Gross finance costs and other finance
expenses (120.3) (85.4) (238.5)
Finance costs capitalised during the
period/year 25.2 17.0 42.2
========================================== ============ ============ =============
(95.1) (68.4) (196.3)
------------------------------------------ ------------ ------------ -------------
5. TAX
Six months Six months Year to
to 30 June to 30 June 31 December
2015 2014 2014
Unaudited Unaudited Audited
$ million $ million $ million
======================================= ============ ============ =============
Current tax:
UK corporation tax on profits - (1.8) (1.5)
UK petroleum revenue tax 21.3 78.8 65.4
Overseas tax 40.8 71.0 154.1
Adjustments in respect of prior years (0.4) 2.4 1.9
======================================= ============ ============ =============
Total current tax 61.7 150.4 219.9
======================================= ============ ============ =============
Deferred tax:
UK corporation tax 117.5 (296.2) (382.2)
UK petroleum revenue tax (10.1) 7.1 33.7
Overseas tax (8.6) 16.4 (45.1)
======================================= ============ ============ =============
Total deferred tax 98.8 (272.7) (393.6)
======================================= ============ ============ =============
Tax charge/(credit) on (loss)/profit
on ordinary activities 160.5 (122.3) (173.7)
======================================= ============ ============ =============
The group has a current tax charge for the period of US$61.7
million (2014: US$150.4 million) and a non-cash deferred tax charge
for the period of US$98.8 million (2014: credit of US$272.7
million) which results in a total tax charge for the period of
US$160.5 million (2014: credit of US$122.3 million) on a loss
before tax for the period US$214.6 million.
The total tax charge for the period is distorted by a number of
specific tax items arising in the UK. These include the effects of
the UK Supplementary Charge to Tax rate reduction from 32 to 20 per
cent on the opening deferred tax asset balance (US$119.4 million
charge) and the net impact of ring fence expenditure supplement
claims in the UK during the period offset by the non-recognition of
UK tax losses and small field allowances due to the low prevailing
oil price environment (US$105.9 million net charge). In addition,
an element of the group's impairment charge for the period was
treated as a permanent difference which resulted in a reduction in
the impairment deferred tax credit of approximately US$33.0
million. After adjusting for the net impact of these items of
US$258.3 million, the underlying group tax during the period was a
credit of US$97.8 million, an effective tax rate of 45.6 per
cent.
6. DEFERRED TAX
Six months Six months Year to
to to 31
30 June 30 June December
2015 2014 2014
Unaudited Unaudited Audited
$ million $ million $ million
========================== =========== =========== ===========
Deferred tax assets 945.3 1,057.2 971.7
Deferred tax liabilities (244.3) (296.4) (254.2)
========================== =========== =========== ===========
701.0 760.8 717.5
========================== =========== =========== ===========
(Charged)/
At credited Credited At
1 January Exchange to income to retained 30 June
2015 movements statement earnings 2015
$ million $ million $ million $ million $ million
=============================== ========== ========== ========== ============= =========
UK deferred corporation
tax:
Fixed assets and allowances (756.0) - (65.8) - (821.8)
Decommissioning 329.8 - 31.3 - 361.1
Deferred petroleum revenue
tax 15.5 - (7.2) - 8.3
Tax losses and allowances 1,375.4 - 81.4 - 1,456.8
Small field allowances 157.2 - (157.2) - -
Derivative financial
instruments (125.1) - - 80.9 (44.2)
Total UK deferred corporation
tax 996.8 - (117.5) 80.9 960.1
=============================== ========== ========== ========== ============= =========
UK deferred petroleum
revenue tax(1) (25.0) - 10.1 - (14.9)
=============================== ========== ========== ========== ============= =========
Overseas deferred tax(2) (254.2) 1.3 8.6 - (244.2)
=============================== ========== ========== ========== ============= =========
Total 717.5 1.3 (98.8) 80.9 701.0
=============================== ========== ========== ========== ============= =========
1 The UK deferred petroleum revenue tax relates mainly to temporary
differences associated with fixed assets.
2 The overseas deferred tax relates mainly to temporary differences
associated with fixed asset balances.
The group's deferred tax assets at 30 June 2015 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 30 June
2015 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 in 2H
2015,2016 and H1 2017, and then US$85/bbl in 'real' terms
thereafter. The results of the corporate model demonstrated that it
was no longer appropriate to recognise an additional amount of
US$49.6 million on (2014: US$86.8 million) in respect of the
group's UK ring fence deferred tax assets relating to tax losses
and allowances based on expected future profitability.
In addition to the above, there are carried forward non-ring
fence UK tax losses of approximately US$283.2 million (2014:
US$263.1 million) and current year non-UK tax losses of
approximately US$34.0 million (2014: US$40.8 million) for which a
deferred tax asset has not been recognised.
None of the UK tax losses (ring fence and non-ring fence) have a
fixed expiry date for tax purposes.
A deferred petroleum revenue tax (PRT) asset has been recognised
to the extent that it is probable that the asset will reverse when
the PRT field is fully decommissioned.
No deferred tax has been provided on unremitted earnings of
overseas subsidiaries, following a change in UK tax legislation in
2009 which exempted foreign dividends from the scope of UK
corporation tax, where certain conditions are satisfied.
7. (LOSS)/EARNINGS PER SHARE
The calculation of basic earnings per share is based on the
profit after tax and on the weighted average number of Ordinary
Shares in issue during the period. Basic and diluted
(loss)/earnings per share are calculated as follows:
Six months Six months Year to
to 30 June to 30 June 31 December
2015 2014 2014
Unaudited Unaudited Audited
(Loss)/earnings ($ millions):
(Loss)/earnings for the purpose of
basic earnings per share being net
profit attributable to owners of the
company (375.2) 172.7 (210.3)
Effect of dilutive potential Ordinary
Shares:
Interest on convertible bonds - 5.2 -
=========================================== ============ ============ =============
(Loss)/earnings for the purposes of
diluted (loss) earnings per share (375.2) 177.9 (210.3)
=========================================== ============ ============ =============
Number of shares (millions):
Weighted average number of Ordinary
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August 20, 2015 02:01 ET (06:01 GMT)
Shares for the purpose of basic earnings
per share 510.8 527.1 521.9
Effects of dilutive potential Ordinary
Shares:
Contingently issuable shares - 40.8 -
=========================================== ============
Weighted average number of Ordinary
Shares for the purpose of diluted
earnings per share 510.8 567.9 521.9
=========================================== ============ ============ =============
(Loss)/earnings per share (cents)
Basic (73.5) 32.8 (40.3)
Diluted (73.5) 31.3 (40.3)
=========================================== ============ ============ =============
There were 41.3 million anti-dilutive potential Ordinary Shares
in the six months to 30 June 2015 mainly compromising of shares to
be issued on the conversion of the convertible bond.
8. INTANGIBLE EXPLORATION AND EVALUATION (E&E) ASSETS
Oil and
gas properties
$ million
----------------------------- ----------------
Cost:
At 1 January 2015 825.7
Exchange movements (12.9)
Additions during the period 142.8
Exploration expense (45.3)
At 30 June 2015 910.3
----------------------------- ----------------
At 30 June 2014 753.5
----------------------------- ----------------
The amounts for intangible E&E assets represent costs
incurred on active exploration projects. These amounts are written
off to the income statement as exploration expense unless
commercial reserves are established or the determination process is
not completed and there are no indications of impairment. The
outcome of ongoing exploration, and therefore whether the carrying
value of E&E assets will ultimately be recovered, is inherently
uncertain.
9. PROPERTY, PLANT AND EQUIPMENT
Oil and gas Other
properties fixed assets Total
$ million $ million $ million
=============================== =========== ============== ==========
Cost:
At 1 January 2015 5,498.6 59.9 5,558.5
Solan asset acquisition 614.8 - 614.8
Additions during the period 462.8 0.8 463.6
At 30 June 2015 6,576.2 60.7 6,636.9
=============================== =========== ============== ==========
Amortisation and depreciation:
At 1 January 2015 3,091.3 37.2 3,128.5
Exchange movements - 0.1 0.1
Charge for the period 170.6 5.5 176.1
Impairment charge 385.3 - 385.3
At 30 June 2015 3,647.2 42.8 3,690.0
=============================== =========== ============== ==========
Net book value:
At 30 June 2015 2,929.0 17.9 2,946.9
=============================== =========== ============== ==========
At 31 December 2014 2,407.3 22.7 2,430.0
------------------------------- ----------- -------------- ----------
At 30 June 2014 2,660.9 18.6 2,679.5
------------------------------- ----------- -------------- ----------
During the period, Premier acquired a further 40 per cent
interest in the Solan field for nil upfront cash consideration to
increase the group's total interest to 100 per cent. Under the
terms of the transaction, the group has agreed to make three types
of contingent consideration (royalty) payments to Chrysaor which
depend on the future profits generated from a notional 40 per cent
interest in the Solan field. The terms of each royalty differ and
in certain cases include a fixed monetary cap and in other cases
allow for deductions designed to allow Premier to notionally
recover the loan previously advanced to Chrysaor and/or a notional
40 per cent share of the total project capex.
The consideration for the acquisition was US$614.8 million,
representing the fair value of the outstanding loan balance due
from Chrysaor which has been waived (US$549.0 million), the fair
value of the above contingent consideration due to Chrysaor using
Premier's long term planning assumptions (US$56.0 million) and
other working capital adjustments (US$10.0 million). This
contingent consideration is included in long term provisions at its
fair value. The fair value of the contingent consideration has been
determined using our long term corporate modelling assumptions
consistent with those used for impairment testing purposes, as set
out below.
Amortisation and depreciation of oil and gas properties is
calculated on a unit-of-production basis, using the ratio of oil
and gas production in the period to the estimated quantities of
proved and probable reserves on an entitlement basis at the end of
the period plus production in the period, on a field-by-field
basis. Proved and probable reserve estimates are based on a number
of underlying assumptions including oil and gas prices, future
costs, oil and gas in place and reservoir performance, which are
inherently uncertain. Management uses established industry
techniques to generate its estimates and regularly references its
estimates against those of joint venture partners or external
consultants.
However, the amount of reserves that will ultimately be
recovered from any field cannot be known with certainty until the
end of the field's life.
The impairment charge relates entirely to the Solan field in the
UK. The carrying amount of the Solan field at 30 June 2015, after
the impairment charge, is US$1,334.8 million. The impairment charge
was calculated by comparing the future discounted 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 H2 2015, 2016 and H2 2017, and
US$85/bbl in 'real' terms thereafter and were discounted using a
pre-tax discount rate of 10.0 per cent. Assumptions involved in
impairment measurement include estimates of commercial reserves and
production volumes, future oil and gas prices and the level and
timing of expenditures, all of which are inherently uncertain. The
impairment charge is driven by increases in the total expected
costs to complete the project and future decommissioning costs, a
reduction in the forecast forward curve and the recognition of
contingent consideration payable to Chrysaor as outlined above.
10. NOTES TO THE CONDENSED CONSOLIDATED CASH FLOW STATEMENT
Six months Six months Year to
to 30 June to 30 June 31 December
2015 2014 2014
Unaudited Unaudited Audited
$ million $ million $ million
============================================== ============ ============ =============
(Loss)/profit before tax for the period/year (214.7) 50.4 (384.0)
Adjustments for:
Depreciation, depletion, amortisation
and impairment 561.4 372.7 1,240.8
Exploration expense 45.3 37.4 58.5
Provision for share-based payments 5.9 3.2 6.9
Share of profit in associate - (1.9) (1.9)
Interest revenue and finance gains (47.4) (24.9) (58.5)
Finance costs and other finance expenses 95.1 68.4 196.3
Loss/(profit) on disposal of assets - 83.9 (2.7)
Operating cash flows before movements
in working capital 445.6 589.2 1,055.4
(Increase)/decrease in inventories (3.7) 4.1 23.0
Decrease/(increase) in receivables 15.8 (84.6) 105.3
Increase/(decrease) in payables 112.6 98.1 (53.6)
============================================== ============ ============ =============
Cash generated by operations 570.3 606.8 1,130.1
Income taxes paid (58.0) (109.5) (208.5)
Interest income received 0.7 2.1 2.7
============================================== ============ ============ =============
Net cash from operating activities 513.0 499.4 924.3
============================================== ============ ============ =============
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Analysis of changes in net debt:
Six months Six months Year to
to 30 June to 30 June 31 December
2015 2014 2014
Unaudited Unaudited Audited
$ million $ million $ million
======================================= ============ ============ =============
a) Reconciliation of net cash flow
to movement in net debt:
Movement in cash and cash equivalents 80.6 (193.9) (157.1)
Proceeds from drawdown of bank loans
and senior loan notes (550.0) (100.0) (655.0)
Repayment of bank loans 500.8 70.0 100.0
Non-cash movements on debt and cash
balances (1.7) (12.3) 42.8
======================================= ============ ============ =============
Decrease/(increase) in net debt in
the period/year 29.7 (236.2) (669.3)
Opening net debt (2,122.2) (1,452.9) (1,452.9)
======================================= ============ ============ =============
Closing net debt (2,092.5) (1,689.1) (2,122.2)
======================================= ============ ============ =============
b) Analysis of net debt:
Cash and cash equivalents 372.4 255.0 291.8
Borrowings(*) (2,464.9) (1,944.1) (2,414.0)
=========================== ========== ========== ==========
Total net debt (2,092.5) (1,689.1) (2,122.2)
=========================== ========== ========== ==========
* Borrowings consist of the short-term borrowings, convertible
bonds and the other long-term debt. The carrying values 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$0.3 million (December 2014: US$0.4 million) and
debt arrangement fees of US$23.0 million (December 2014: US$27.4
million) respectively.
11. 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 has been recognised
as deferred income in the balance sheet and will be released to the
income statement as barrels are delivered to FlowStream following
first oil from Solan.
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.
12. FINANCIAL INSTRUMENTS
Derivative financial instruments
The group held the following financial instruments at fair value
at 30 June 2015. The group has no financial instruments with fair
values that are determined by reference to significant unobservable
inputs i.e. those that would be classified as level 3 in the fair
value hierarchy, nor have there been any transfers of assets or
liabilities between levels of the fair value hierarchy.
There are no non-recurring fair value measurements.
At 30 June
2015 Level 2
$ million $ million
----------------------- ---------- ----- ---- ----------- -----------
Financial assets:
Gas forward sale contracts 3.7 3.7
Oil forward sales contracts 88.3 88.3
Forward foreign exchange contracts 4.5 4.5
Total 96.5 96.5
------------------------------------------------ ----------- -----------
Financial Liabilities:
Forward foreign exchange contracts 0.6 0.6
Cross currency
swaps 52.6 52.6
Total 53.2 53.2
------------------------------------------------ ----------- -----------
At 30 June
2014 Level 2
$ million $ million
----------------------- ---------- ----- ---- ----------- -----------
Financial assets:
Gas forward sale contracts 0.3 0.3
Forward foreign exchange contracts 1.7 1.7
Cross currency
swaps 14.3 14.3
Total 16.3 16.3
------------------------------------------------ ----------- -----------
Financial Liabilities:
Oil forward sales contracts 38.7 38.7
Gas forward sale contracts 0.5 0.5
Cross currency
swaps 1.2 1.2
Interest rate
swaps 7.2 7.2
Total 47.6 47.6
------------------------------------------------ ----------- -----------
The fair values were determined from counterparties with whom
the trades have been entered into. Fair value is the amount at
which a financial instrument could be exchanged in an arm's length
transaction, other than in a forced or liquidated sale. Where
available, market values have been used to determine fair values.
The estimated fair values have been determined using market
information and appropriate valuation methodologies. Values
recorded are as at the balance sheet date, and will not necessarily
be realised. Non-interest bearing financial instruments, which
include amounts receivable from customers and accounts payable are
also recorded materially at fair value reflecting their short-term
maturity.
Fair value of financial assets and financial liabilities
The carrying values and fair values of the group's non
derivative financial assets and financial liabilities (excluding
current assets and current liabilities for which carrying values
approximate to fair values due to their short-term nature) are
shown below.
At 30 June
2015 At 30 June
Fair value 2015 Carrying
amount amount
$ million $ million
---------------------------------------------- ------------ ---------------
Primary financial instruments held or issued
to finance the group's operations:
Bank loans 1,482.0 1,482.0
Senior loan notes 516.8 516.8
Retail bond 219.2 235.5
Convertible bonds 217.5 230.6
----------------------------------------------- ------------ ---------------
13. EVENTS AFTER THE BALANCE SHEET DATE
The group has reached agreement with its lending group to modify
its financial covenants until mid-2017. Further details are
provided in the Financial Review.
INDEPENDENT REVIEW REPORT TO PREMIER OIL PLC
We have been engaged by the company to review the condensed set
of financial statements in the half-yearly financial report for the
six months ended 30 June 2015 which comprises the condensed
consolidated income statement, the condensed consolidated statement
of comprehensive income, the condensed consolidated balance sheet,
the condensed consolidated statement of changes in equity, the
condensed consolidated cash flow statement and related notes 1 to
13. We have read the other information contained in the half-yearly
financial report and considered whether it contains any apparent
misstatements or material inconsistencies with the information in
the condensed set of financial statements.
This report is made solely to the company in accordance with
International Standard on Review Engagements (UK and Ireland) 2410
"Review of Interim Financial Information Performed by the
Independent Auditor of the Entity" issued by the Auditing Practices
Board. Our work has been undertaken so that we might state to the
company those matters we are required to state to it in an
independent review report and for no other purpose. To the fullest
extent permitted by law, we do not accept or assume responsibility
to anyone other than the company, for our review work, for this
report, or for the conclusions we have formed.
Directors' responsibilities
The half-yearly financial report is the responsibility of, and
has been approved by, the directors. The directors are responsible
for preparing the half-yearly financial report in accordance with
the Disclosure and Transparency Rules of the United Kingdom's
Financial Conduct Authority.
As disclosed in note 1, the annual financial statements of the
group are prepared in accordance with International Financial
Reporting Standard (IFRS) as adopted by the European Union. The
condensed set of financial statements included in this half-yearly
financial report has been prepared in accordance with International
Accounting Standard 34, "Interim Financial Reporting," as adopted
by the European Union.
Our responsibility
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