TIDMPMO
RNS Number : 9343F
Premier Oil PLC
26 February 2015
Press Release
Annual Results for the year ended 31 December 2014
Tony Durrant, Chief Executive, commented:
"Despite the challenging macroeconomic circumstances, the group
delivered record production and operating cashflow in 2014. In
2015, we will continue to optimise our stable production base, push
forward with approved developments and anticipate adding to our
substantial resource base with targeted exploration. This can be
achieved while re-setting the cost base to a new low oil price
environment. These actions will position Premier as a well-financed
low cost producer with significant undeveloped resources and
acquisition capacity, highly leveraged to a future recovery in oil
prices."
2014 highlights
-- Strong operating cash flow of US$924.3 million (2013:
US$802.5 million), up 15 per cent
-- Revenue of US$1.6 billion (2013: US$1.5 billion); loss after
tax of US$210.3 million (2013: profit after tax of US$234.0
million), reflecting non-cash post-tax impairments of US$327.8
million due to lower near term oil price assumptions
-- Record production of 63.6 kboepd (2013: 58.2 kboepd), up 9.3
per cent and above upper end of market guidance
-- Key milestones reached on development projects: government
approval of the Catcher project received, installation of the Solan
facilities achieved, FEED completed on the Vette field and a lower
capex solution for the Sea Lion project selected
-- Exploration successes included a 100 mmboe oil and
liquids-rich gas discovery at Kuda/Singa Laut in Indonesia
-- Continued portfolio rationalisation with approximately US$190
million of non-core asset sales announced of which Scott area and
Luno II disposals completed during the year
-- Dividend suspended for full year 2014
Financial position and outlook
-- Significant liquidity with cash and undrawn facilities of US$1.9 billion
-- Sustainable operating cost of less than US$20/boe
-- Favourable, low cost debt structure; renewal of main bank
facility completed on improved terms and increased to US$2.5
billion
-- Significant cost reductions budgeted for 2015 via sustainable
savings in operating costs, reduced G&A spend, and re-phasing
of capex
Mike Welton, Chairman Tony Durrant, Chief Executive
26 February 2015
ENQUIRIES
Premier Oil plc Tel: 020 7730 1111
Tony Durrant
Richard Rose
Bell Pottinger Tel: 020 3772 2500
Gavin Davis
Henry Lerwill
A presentation to analysts and investors will be held at 9.00am
today at the offices of Premier Oil's Falkland Islands Business
Unit, 157-197 Buckingham Palace Road, London SW1W 9SP. A live
webcast of this presentation will be available via Premier's
website at www.premier-oil.com.
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.
CHAIRMAN'S STATEMENT
The industry context
From a macro perspective, 2014 was a year of two halves: oil
prices remained steady above US$100 per barrel (bbl) in the first
half, as they have done broadly for the last four years, before
falling significantly, to close the year at less than US$60/bbl.
The fall was driven by strong global supply, particularly the
growth in unconventional resources in North America.
One direct consequence of lower oil prices is a fall in the cost
of services to the industry and this is already evident across the
supply chain. The fall in prices should also lead to a supply
correction as more marginal projects are cancelled and free cash
flow for near-term investment across the industry is reduced.
However, it will take time for oil prices to reach a mid-cycle
equilibrium and, as a company, we must and we are taking steps to
ensure we are well positioned to withstand a prolonged period of
weak commodity prices.
The sector has seen these price cycles before and few believe
that the oil price will not eventually recover from current levels.
This view is supported by the forward curve which shows rising oil
prices. We are highly leveraged to such a recovery with a low cost,
stable production base and an improving portfolio mix. Beyond this
year, we have little committed expenditure. Our unsanctioned
projects, however, offer future growth at a lower cost base.
Premier's performance
Premier delivered a strong operational performance in 2014. We
achieved a record annual average production rate of 63.6 thousand
barrels of oil equivalent per day (kboepd), exceeding our
expectations due to significantly improved uptime across the
majority of our assets. This performance was delivered despite the
continuing supply disruptions at Huntington (due to circumstances
outside the joint venture's control) and is testament to the hard
work and successful efforts of our operated production teams.
We continue to progress our pipeline of development projects and
were delighted to achieve new production from two operated fields
in Asia over the course of the year. In the UK North Sea,
installation of the facilities at our Solan development West of
Shetland was completed in September and while it is disappointing
that commissioning has progressed slowly during the winter and
costs have increased on the project, the Solan field will be a
material contributor to Premier's cash flows once on-stream.
Significant progress was also made on our other operated North
Sea projects, namely Catcher which received development sanction
and Vette in Norway where front-end engineering and design (FEED)
work was completed, while the scope and size of the initial phase
of the Sea Lion development in the Falkland Islands has been
scaled-back. This project is now much more manageable for a company
of Premier's size in the current environment and the focus in 2015
will be on progressing the project to the point of investment
decision.
Our exploration team continued to bring new, material projects
into the portfolio with notable success at Kuda/Singa Laut on the
Tuna Block in the Natuna Sea, Indonesia. This oil and liquids-rich
gas discovery is strategically located in a core area for Premier
and appraisal activity is planned for 2016.
A key tenet of our strategy is to realise value from our
non-core assets and to reallocate our financial and human resources
to our key projects. This continued in 2014 with the announced sale
of undeveloped resources in Indonesia and Norway and the disposal
of our non-operated stake in the Scott area in the UK North Sea. In
total, these asset sales will raise around US$190 million in
disposal proceeds.
During the year, we enhanced the group's financial liquidity
position with the successful refinancing of our principal debt
facility on improved terms. Our long-term, unsecured debt structure
and supportive banking relationships leave us well placed, although
we will need to continue to manage our covenant headroom if current
oil prices persist.
Health, safety and environmental matters continue to be of
paramount importance to us and, while cost cutting is clearly a
focus in the current climate, we will not compromise on the
integrity and safety of our operations. Our safety performance in
2014 saw a substantial reduction in our TRIR (Total Recordable
Injury Rate) which reached a five year low of 1.48 per million man
hours. 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. We are particularly proud of our track
record on our operated Anoa platform in Indonesia which, by
year-end 2014, had reached 1.6 million man hours without a lost
time injury.
Despite our much improved occupational health and safety
performance in 2014, I regret to report two fatalities in South
East Asia: one contractor fatality as a result of an offshore
vessel collision and a third party fatality as a result of a road
traffic accident. No blame was attached to Premier in either case
but we have taken steps to reduce the risk of these incidents
recurring. We are all saddened by the tragic outcomes for the
families involved.
Our annual reporting on corporate responsibility performance is
aligned with IPIECA Guidance and the Global Reporting Initiative's
Sustainability Reporting. We are also a long-standing member of the
FTSE4Good Index and the UN Global Compact and in 2014 were accepted
as a member of the Corporate Pillar of the Voluntary Principles on
Security and Human Rights. We remain committed to protecting our
people, our assets, our environment and our reputation by
maintaining the highest possible standards.
Future plans
In 2015 a key priority is to progress our sanctioned projects -
Solan and Catcher - through the execution phases and to deliver
safely the major four well exploration campaign on our Falkland
Islands acreage. Financially, we will minimise our cost base and
tailor our capital allocation to ensure that we are well positioned
through the current commodity price cycle.
Our substantial 2015 hedging programme has ensured that our
near-term cash flows are well protected and our debt position of
US$2.1 billion at year-end is manageable at this point in our
investment cycle. We are also taking further steps to dispose of,
or monetise, assets to reduce our debt position. We have
significant liquidity if the weak macro environment offers new
opportunities, as it has done in the past, although management
remain focused on ensuring that debt levels are kept under
control.
Board changes
I was pleased to announce that Tony Durrant, our former Finance
Director, accepted the role of Chief Executive during the year
replacing Simon Lockett. During Tony's tenure as Finance Director,
the company has maintained excellent relationships with our capital
providers and the Board believes he has all the right qualities to
take the company forward in the next stage of its evolution. We
also welcomed Richard Rose onto the Board as the new Finance
Director, bringing with him a broad range of experience from
accounting, industry and capital markets. I would like to pay
tribute to Simon Lockett who guided the company through a
substantial growth period and who ensured a smooth transition to
the new management team.
Andrew Lodge, our Exploration Director, has indicated that he
will retire effective 30 June this year and will therefore not seek
re-election as a board director at our forthcoming AGM. A new head
of exploration will be appointed in due course. Stephen Huddle, who
has been General Counsel and Company Secretary for 14 years, will
also retire on 31 May. Rachel Benjamin, currently Deputy Company
Secretary, will become Company Secretary on Stephen's
retirement.
We wish all our leavers well in their future endeavours. These
changes, together with other senior management changes, refresh the
leadership of the company and, in addition, will contribute to a
reduced cost base as we adapt to a new oil price environment.
Shareholder returns and share price performance
As we have stated in the past, our goal remains to deliver
consistent, measurable capital growth to our shareholders. Implied
within this strategy is a commitment to return cash to our
shareholders via distributions, after balancing the capital needs
of the business, when the performance of the company has not been
materially reflected in the share price.
Over the course of 2014, our share price fell by 47 per cent,
although this was not out of line with the rest of the sector which
also suffered with the fall in commodity prices. During the year,
we paid a dividend of 5 pence per share and returned a further
US$93 million of capital to shareholders through a share buyback
programme. This was in acknowledgment of the significant gap
between our share price and underlying net asset value. It also
reflected surplus cash flow generated by our production base in the
first half of the year, above the level expected using our
long-term oil price planning assumption.
As we enter 2015 with a significantly lower oil price than in
recent years, the Board believes it is not prudent to propose a
dividend payment for the full year or, as previously announced, to
continue with the share buyback programme. Our focus in the
near-term is on preserving cash, maintaining access to liquidity
and reducing gearing levels while continuing to invest in our
sanctioned development projects. We would expect to revisit our
decisions around shareholder distributions should the oil price
recover above our long term planning assumption.
On behalf of the Board as well as myself, I would like once
again to express my appreciation for the hard work and effort put
into the business by Premier's staff. Their continued dedication
and enthusiasm in what are trying times for the industry should see
us well placed amongst our peers to prosper in the future.
Mike Welton
Chairman
CHIEF EXECUTIVE'S REVIEW
We are all only too aware of the sharp fall in the oil price
that occurred in the second half of 2014 after several years of oil
price stability at historically high levels. While it is not clear
at this stage when the oil price will find a floor, or how long it
may take to recover, it offers the industry the chance to re-set
its cost base and will present new opportunities for the
better-funded companies in the sector.
For our part, we have been quick to respond to the falling oil
price and, by the end of 2014, we had already taken steps to reduce
significantly the costs of running our business without
compromising the safety or performance of our operations. We will
continue to look to cut or defer our expenditure to ensure that we
are able to manage the business successfully through a potentially
prolonged period of low oil prices.
Despite the backdrop of falling oil prices in the second half of
the year, Premier remained focused on operational delivery and
achieving the near-term priorities that we set ourselves. In this
respect, 2014 was a strong year for us.
Beating our production guidance
2014 saw Premier deliver record production of 63.6 kboepd, above
the upper end of market guidance, assisted by improved operating
efficiency across the majority of the group's assets.
Production (kboepd) Working interest Entitlement
---------------------
2014 2013 2014 2013
--------------------- --------- -------- ------ ------
Indonesia 14.4 13.7 10.3 8.8
Pakistan* 12.9 15.5 12.9 15.3
UK 19.4 14.9 19.4 14.9
Vietnam 16.9 14.1 15.2 13.4
Total 63.6 58.2 57.8 52.4
--------------------- --------- -------- ------ ------
*Includes Mauritania
Significantly higher production in the UK was driven by improved
uptime from our operated B Block assets, flush production from the
redevelopment of the Kyle field and increased contributions from
the Huntington and Rochelle fields. Frustratingly, Huntington
continued to disappoint in 2014 as it suffered from poor uptime,
primarily due to restrictions on gas export from the field imposed
by the CATS pipeline operator BP.
In Asia, our operated Chim Sáo asset in Vietnam performed well,
benefitting from a series of projects we had undertaken aimed at
maximising operating efficiency. As a result, record production
rates were achieved. Singapore demand for our Indonesian gas
remained strong and our operated Natuna Sea Block A again captured
a market share well in excess of its contractual share.
Deliverability from the block was increased with first gas from
Naga in November, while Pelikan is planned to be on-stream in the
first quarter of 2015. As well as backfilling our gas contracts
into Singapore which generate long-term, stable cash flows for the
group, the additional deliverability will enable us to exploit any
contractual supply shortfall or short-term strengthening of
Singapore demand for our gas.
As at 31 December 2014 proven and probable (2P) reserves, on a
working interest basis, were 243 million barrels of oil equivalent
(mmboe) (2013: 259 mmboe) with the impact of production and
disposals on our reserve base partially offset by the booking of
the Vette field as 2P reserves. This, together with the discovery
at Kuda/Singa Laut in Indonesia, means that we have ended the year
with 2P reserves and 2C contingent resources of 794 mmboe, in line
with the previous year.
Proven and probable 2P reserves and
2P reserves 2C contingent resources
(mmboe) (mmboe)
-------------------------- -------------------- -------------------------
1 January 2014 259 794
Production (23) (23)
Net additions, revisions 22 50
Disposals (15) (27)
31 December 2014 243 794
-------------------------- -------------------- -------------------------
Progressing our developments - deliver Solan, sanction Catcher
and right-size Sea Lion
Installation of the facilities on the Premier-operated Solan
field West of Shetlands at the end of the summer was a significant
milestone on the project, only two and a half years after receiving
government approval. However, the subsequent commissioning
programme has taken longer than anticipated due to poor weather
conditions and low productivity over the winter period. As a
result, costs have increased and first oil is now expected to be
later than the previous guidance of the second quarter although we
continue to target plateau rates of production from the field of
20-25 thousand barrels of oil per day (kbopd) (gross) by
year-end.
Our operated Catcher project received government approval in
June and is now into the execution phase. Construction of the FPSO
hull started in January 2015 and the project continues to progress
on schedule and to budget. Once on-stream, both the Solan and
Catcher projects will contribute materially to our cash flows,
given our tax advantaged position in the UK.
Turning to our operated pre-sanction projects, FEED work on the
Vette FPSO development in Norway was successfully completed during
2014 and we were in a position to submit development approval
documentation to the government early in 2015. However, following
the sharp reduction in the oil price, we have chosen to defer the
final investment decision until the end of 2015, enabling us to
re-engage with the supply chain with the aim of negotiating lower
costs for the project. Given the falling oil price and our desire
to maintain a strong funding position, we decided to opt for a
lower capex solution for our Sea Lion development, which will now
utilise a leased FPSO. We plan to progress the project to sanction
over the course of 2015 which we anticipate will allow us to secure
further cost reductions. It remains our intention to seek a partner
ahead of final investment decision.
Exploration discoveries
In 2014, Premier delivered a notable exploration success, with
the 100 mmboe oil and liquids- rich gas discovery at Kuda/Singa
Laut on the Tuna Block in Indonesia. While we have deferred
appraisal of this discovery to 2016, this project will likely play
an important role in the long-term future of Premier's Indonesian
business. We also enjoyed exploration success in Pakistan with the
K-36 exploration well which discovered gas in a separate step-out
compartment. The well was successfully tied in to production in
April 2014. During the year, unsuccessful wells were drilled on
other acreage offshore Mauritania, Indonesia and onshore Pakistan
and, subsequent to year-end, onshore Kenya.
A successful disposal programme
During 2014, we announced approximately US$190 million of
non-core asset sales which have all subsequently completed. Of
particular note was the sale of the high cost Scott area for US$130
million which, as well as reducing the group's operating costs, has
significantly decreased our future abandonment liabilities.
Further disposals are planned. Notably, our partner in the Solan
field is in discussions with banks about refinancing a portion of
our loan to them, while discussions with third parties over selling
a royalty interest over the Solan field's cash flows are on-going.
In addition, we have received a number of enquiries about our Sea
Lion development since rescaling the project in November and active
discussions with potential partners continue.
Financial performance and liquidity
The Group is reporting a loss after tax of US$ 210.3 million in
2014 (2013: US$234.0 million profit after tax) largely as a result
of impairment charges of US$327.8 million (post-tax) on the
carrying value of several of our oil and gas assets. These were due
to the impact of the lower near-term oil price assumptions used in
balance sheet tests at the year-end and should not detract from the
record operating cash flows generated during 2014 of US$924.3
million (2013: US$802.5 million).
The collapse in the oil price has served to highlight the
importance of maintaining a strong funding position and a
conservative financing approach. To protect our investment
programme in 2015 we have hedged approximately 50 per cent of our
liquids entitlement production at an average price of just under
US$98/bbl. In July, our finance team did an excellent job of taking
advantage of a relatively strong bank market to refinance and
increase our principal bank facility on improved terms with
extended maturities. As a result, we do not have any significant
debt maturities until late 2017. It is also reassuring that all of
our facilities are on a corporate unsecured basis and are not
subject to any reserve base redeterminations. Consequently, we have
ample liquidity with US$1.9 billion of cash and undrawn facilities
as at year-end, although we recognise the need to manage our
covenant headroom in the near-term.
2015 is anticipated to be a significantly lower capex year. This
coupled with our hedging programme, planned cost reductions and
further potential disposals means that we are well placed to meet
the challenges presented by the current oil price environment.
Tony Durrant
Chief Executive
BUSINESS UNIT REVIEWS
THE FALKLAND ISLANDS
In November, Premier opted to progress a smaller, scaled-back
Sea Lion development scheme in order to reduce the capex required
prior to first cash flows from the field. The initial phase of
development aims to recover 160 million barrels (mmbbls) of oil
from the north east part of the field for less than US$2 billion of
pre-first oil capex.
Final preparations for the four well exploration campaign are
under way with the first well, Zebedee, expected to spud in early
March. The outcome of this campaign, which has the potential to
more than double the discovered resource in the North Falklands
Basin, will determine the shape of subsequent development phases in
the area.
Development
Good progress was made in planning the Sea Lion development
scheme utilising a Tension Leg Platform (TLP) during 2014. However,
the oil price environment and Premier's commitment to maintaining a
strong financial position caused the Group to re-examine the scheme
with a view to reducing capex. As a result, in November, Premier
opted to progress a smaller initial development of just the north
east part of the Sea Lion field with a single subsea drill centre,
utilising a leased FPSO.
It is anticipated that this smaller scheme will recover around
160 mmbbls of oil over 15 years from 14 wells. Total capital
expenditure prior to first oil was expected to be less than US$2
billion in November when first estimated. Premier plans to take
advantage of weaker market conditions in the second half of the
year to capture lower costs for the project.
Work has commenced on assessing the FPSO design options for the
first phase of the development. The existing TLP topsides design
and equipment lists are being modified for use with a smaller
capacity FPSO and the conclusions of various metocean studies are
being fed into the FPSO design process. A project sanction for the
first phase of development is targeted for the first half of 2016,
although the exact timing of this will ultimately depend upon the
contracting strategy employed for the FPSO. Sanction of the project
will depend on the cost reductions that are achieved and the oil
price outlook at that time.
Rockhopper will fund their share of the pre-sanction costs and a
letter of agreement has been concluded such that the remaining
development carry will be split equally between the initial
development and the next phase (US$337 million to each). A
guarantee fee mechanism which applies to capex guarantees given by
Premier in respect of the development has been extended to include
the FPSO lease.
While it is likely that Premier would be able to fund a project
of this size from existing facilities and cash flows, the company
will continue to seek a partner for the Sea Lion development. Plans
for subsequent phases of development, which could involve either
further FPSOs or a TLP, will target a further 235 mmbbls of
existing discovered resources plus any new discoveries arising from
the 2015 exploration programme.
Exploration
Preparations for the multi-operator exploration drilling
campaign, due to commence in the first quarter of 2015 are well
under way. In June a rig contract and a rig sharing agreement were
signed and all major service contracts have now been awarded. A
temporary dock facility located in Stanley Harbour has been built
and has received the first two coasters of supplies for the
upcoming programme. The rig departed West Africa at the end of
January and is expected to arrive in the Falkland Islands by the
end of February.
The exploration drilling programme will consist of at least four
wells targeting multiple stacked fans in Licences PL004 and PL032.
The sequence of the wells is expected to be Zebedee, Isobel Deep,
Jayne East and Chatham/West Sea Lion. The rig will drill for
another operator between the Isobel Deep and Jayne East wells.
INDONESIA
2014 saw strong production and cash flows from Premier's
operated Natuna Sea Block A, which increased its market share of
the GSA1 contract and achieved record production rates.
Deliverability from Natuna Sea Block A was further enhanced with
first gas from the Naga field in November. Premier also enjoyed
exploration success in Indonesia with a significant oil and
liquids-rich gas discovery on the operated Tuna Block further
strengthening the portfolio and providing the group with future
growth opportunities.
Production and development
Net production from Indonesia in 2014 on a working interest
basis was 14.4 kboepd (2013: 13.7 kboepd), up 5 per cent on the
prior year. This was driven by a strong operational performance
from the Anoa field on the Premier-operated Natuna Sea Block A, our
key asset in Indonesia. The Anoa field delivered 141 billion
British thermal units per day (BBtud) during 2014, capturing 44.6
per cent (2013: 39.9 per cent) of GSA1 deliveries into Singapore,
against a contractual share of 39.4 per cent. Natuna Sea Block A's
contractual share for 2015 has been increased to 39.9 per cent.
Gross liquids production from the Anoa field averaged 1.5 kbopd
(2013: 1.7 kbopd).
Sales from the Gajah Baru field to Singapore under GSA2 averaged
79 BBtud (2013: 82 BBtud). In addition, gas sales of up to 40 BBtud
from the Gajah Baru field to the Indonesian market commenced under
a Domestic Swap Agreement (DSA) in July. Gas delivered under the
DSA replaces gas previously contracted to Batam Island, Indonesia,
from the Natuna Sea Block A under GSA3 and GSA4. DSA deliveries are
expected to continue until the domestic pipelines are constructed
and the GSA3 and GSA4 contracts commence.
In total, 242 BBtud (gross) (2013: 208 BBtud) was sold from
Natuna Sea Block A during 2014 with record peak production rates of
391 BBtud achieved. High deliverability from Premier's Anoa and
Gajah Baru fields gives Premier the flexibility to meet peak
customer demand and to capitalise upon other suppliers' maintenance
and unplanned downtime. Looking to 2015, Premier plans to continue
to optimise its production from Natuna Sea Block A and to
renegotiate supplier contracts to take advantage of the expected
price reductions in oil field services in order to maintain its
competitive low operating cost base.
Good progress was made during 2014 on our new Natuna Sea Block A
developments, Naga and Pelikan. Following the successful completion
of the offshore installation in 2013, hook up and commissioning of
the Pelikan and Naga well head platforms was completed in April
2014. The Hakuryu rig commenced development drilling at the Naga
field in July with first gas achieved on budget in November. The
three development wells at the Pelikan field were completed in
early 2015 and the field is expected on-stream at the end of the
first quarter.
Natuna Sea Block A's deliverability continues to exceed its
contractual commitments. As a result, Premier is well placed to
increase its market share should its partners not meet their
contractual commitments under GSA1 as well as to increase its
supply of gas into Singapore should demand strengthen.
Elsewhere on Natuna Sea Block A, it is anticipated that the 2012
Anoa Deep gas discovery well will be tied into the Anoa production
facilities in 2015 to support GSA1 deliveries. Premier is also
progressing FEED for the Bison and Iguana projects as single well
subsea tie-backs to Pelikan while concept select for the Gajah
Puteri field is underway.
Premier successfully divested its 41.67 per cent non-operated
interest in Block A Aceh onshore Indonesia for US$40 million in
2014. Government approvals for the sale were received at the end of
2014 with completion achieved in January 2015.
Exploration and appraisal
Premier drilled three exploration wells in Indonesia during
2014: the Kuda Laut-1 and Singa Laut-1 wells on the
Premier-operated Tuna Block and the Ratu Gajah-1 well on the
Premier-operated Natuna Sea Block A.
The Kuda Laut-1 well, which targeted Miocene sands within a
four-way dip closed structure, and the Singa Laut-1 side track,
which targeted the Oligocene sequence in the adjoining three- way
dip closure, discovered in excess of 100 mmboe. Gas gradients have
been measured and liquids-rich gas samples were recovered
suggesting that the discovery has a high natural liquid content.
Planning for a 2016 appraisal campaign is now under way. Premier
has 65 per cent equity in the block and will assess the appropriate
working interest level to hold as appraisal advances.
Premier also drilled the Ratu Gajah-1 well on Natuna Sea Block A
during 2014. While the well flowed gas to surface during testing,
less sandstone reservoir than expected was encountered and the
discovery is sub-commercial. The results of this well, however,
have been integrated into the group's broader understanding of the
Lama play and thicker sands have been identified at the basin
margin. The next well in our portfolio to test the Lama play will
be the appraisal of the Anoa Deep discovery, which is scheduled for
the second quarter of 2015.
NORWAY
Following concept select in February, Premier successfully
completed FEED on the Vette development and progressed the project
to the point of sanction. However, Premier has agreed with the
Norwegian Petroleum Directorate to defer the submission of the Plan
for Development and Operation (PDO) to enable Premier to re-engage
with the supply chain to capture lower costs. Premier successfully
concluded the sale of its interest in Luno II in 2014 while
preparations for our first test of the emerging Mandal High play
are well advanced with the Myrhauk well expected to spud
mid-2015.
Development
Premier acquired operatorship of the Bream development, now
known as Vette, in 2013. Since then, significant progress has been
made in commercialising the field and, at the end of 2014, Premier
booked the reserves for the development.
The development will focus on recovering 40 mmbbls of reserves
from the field using four producers and two injectors tied back to
a FPSO. The Mackerel discovery in the adjacent PL406 licence will
be incorporated into a possible second phase of development.
FEED engineering work and supply chain engagement on the
development concept for Vette was completed and the project was
brought to sanction decision by the end of 2014. As part of that
process, Premier also continued with the development of its
organisation in Norway in preparation for development operator
status and successfully completed a number of audits undertaken by
the Petroleum Safety Authority.
In light of the sharp fall in the oil price in the second half
of 2014, Premier agreed with the Norwegian Petroleum Directorate to
defer the submission of the PDO by a year. Premier will use the
intervening period to re-engage with the supply chain to negotiate
better rates which are more reflective of the current climate.
Assuming that appropriate cost savings are achieved, Premier will
consider making a final investment decision at the end of 2015
targeting first oil in 2019.
Work continued during 2014 on the non-operated Frøy field to
identify a viable development concept. Following acquisition and
interpretation of new seismic data, a reassessment of subsurface
resources was completed in 2014 and screening of development
concepts is under way, including both standalone options as well as
a tie-back solution to nearby infrastructure.
Exploration
Premier continued to high grade its Norwegian exploration
portfolio during 2014. This included the profitable sale of the
Group's non-operated interest in PL359, which included the Luno II
discovery, to Lundin Petroleum for a consideration of US$17.5
million. In addition, following technical evaluations, Premier
relinquished a number of its exploration licences in Norway.
Premier's immediate exploration focus in Norway is on the
Myrhauk well which is expected to spud mid-2015 and will be the
company's first test of the emerging Mandal High play. Premier has
built an extensive acreage position over the Mandal High, both
organically and through acquisition, and has identified significant
follow on potential to the Myrhauk well in the success case.
Premier was successful in the APA 2014 Licensing Round with the
award of a 20 per cent non-operated interest in PL782S which is
located in the Norwegian North Sea and will be operated by
ConocoPhillips. There are no firm well commitments with the
award.
PAKISTAN
2014 saw another strong performance from Premier's Pakistan
business unit. Production from our six non-operated onshore
Pakistan gas fields exceeded expectations and exploration success
was achieved with the Kadanwari K-36 well.
Production and development
Average production in Pakistan during 2014 was 12.4 kboepd (net
to Premier), around 16 per cent lower than in 2013 (14.9 kboepd).
This reflects natural decline in the Bhit, Qadirpur and Zamzama gas
fields only partially offset by higher production from the
Kadanwari and Badhra fields.
The Kadanwari gas field, in which Premier has a 15.8 per cent
non-operated interest, performed strongly in 2014 and delivered
production of 3.2 kboepd (net to Premier) (2013: 2.9 kboepd), a new
record for the field. This was driven by new production from the
K-33 and K-35 wells which came on-stream in December 2013 and
February 2014 respectively, and the successful exploration well
K-36, which was tied in to production in April 2014.
Average production from the Bhit and Badhra gas fields in 2014
was 3.0 kboepd (net to Premier) (2013: 3.3 kboepd). Higher
production was achieved from the Badhra gas field which benefitted
from two new wells being brought on-stream in the first quarter of
2014. An additional two development wells were tied in at Badhra at
the end of the year partially offsetting natural decline from
existing wells. Good progress has also been made on the compressor
reconfiguration project at Bhit, which was initiated in the first
half of 2014, to improve ultimate recovery by around 54 billion
cubic feet (bcf) (gross). Five of the 10 compressors have been
commissioned and the project is on track to complete in April
2015.
Production from the Qadirpur gas field averaged 3.2 kboepd
(2013: 3.6 kboepd). Production fell over the year, in part due to
natural decline in the field, but also due to an unplanned shutdown
at the power plants into which gas is delivered.
Production from the Zamzama field was lower in 2014 averaging
3.1 kboepd (2013: 5.1 kboepd). This marked decrease in production
was due to faster declining reservoir pressures than initially
anticipated and Premier has updated its remaining reserves estimate
for the field accordingly. However, this decline was partially
mitigated by intervention work carried out at the Zam-4 production
well in May and the re-start of gas production from the Zam-8 well
in October. The joint venture is also considering further infill
drilling and additional wellhead compression to mitigate the
natural decline seen in the existing wells.
First gas was achieved from the Zarghun South gas field in
August and the field is currently producing at around 13 million
standard cubic feet per day (mmscfd) (gross). All costs pertaining
to Premier's 3.75 per cent working interest in the field continue
to be carried by the operator.
Exploration and appraisal
Premier drilled the successful K-36 exploration well on
Kadanwari in Pakistan in the first half of 2014. The well
discovered gas in a separate step-out compartment and was tied-in
to the Kadanwari facilities during April 2014.
MAURITANIA
Production and development
Production from the Chinguetti field averaged 447 bopd (2013:
507 bopd) net to Premier during the year. The fall in production
was driven by natural decline from the existing wells as well as a
shutdown of the facilities in January for a mooring chain
replacement. The FPSO contract has now been extended to December
2017.
Elsewhere in Mauritania, Premier relinquished its non-operated
interest in PSC-A, which contains the Banda gas development and
PSC-B, which contains the Tiof and Tevet discoveries.
Exploration and appraisal
The Tapendar-1 exploration well was drilled on PSC C-10 in the
first half of 2014 and was plugged and abandoned as a dry hole.
Subsequently, the joint venture partners agreed to exit the licence
on 30 November 2014.
UNITED KINGDOM
Higher UK production, driven by improved operating efficiency at
B Block, increased contributions from Huntington and Rochelle and
flush production from Kyle, resulted in a strong rise in UK cash
flows in 2014, despite the sharp fall in the oil price in the
second half of the year. Key milestones were reached on Premier's
operated Solan and Catcher projects. In addition, the sale of the
high cost Scott area assets for US$130 million was successfully
completed in December.
Production
In 2014, UK production averaged 19.4 kboepd, an increase of 30.3
per cent on the corresponding period (2013: 14.9 kboepd).
Production from the Premier-operated Balmoral area exceeded
expectations, averaging 3.2 kboepd during 2014 (2013: 2.5 kboepd),
as the asset benefitted from improved operating efficiency and the
reinstatement of five wells, four at the end of 2013 and one in
2014. Production from the non-operated Wytch Farm asset was also
strong, averaging 5.6 kboepd (2013: 5.5 kboepd) again driven by
high operating efficiency as well as a successful programme of
infill drilling which saw four new wells brought on-stream in the
first half of 2014.
Production from Scott, Telford and Rochelle averaged 3.8 kboepd,
broadly in line with expectations. While production from the fields
was impacted by several unplanned shutdowns, reservoir productivity
was strong when unconstrained by facilities, with Rochelle, for
example, achieving rates of up to 100 mmscfd (gross). In December
Premier successfully completed the sale of the Scott area assets
for a consideration of US$130 million. As part of the transaction,
all associated decommissioning costs liabilities were transferred
to the buyer.
Average production from the non-operated Huntington field was
5.7 kboepd (2013: 3.5 kboepd). Although the Group benefitted from a
full year of production from the asset, production performance from
the field was significantly below expectations due to lower
operating efficiency as a result of downtime on the production
facilities and restrictions on exporting the gas through the CATS
pipeline system. Most recently, production from the field has been
restricted while repairs are undertaken to a topsides valve on the
CATS riser platform which failed to re-start in early December
following a planned outage. The field is now expected to restart
production in mid-March.
Since December 2011, the non-operated Kyle field underwent
redevelopment following storm damage to the Banff FPSO to which the
field ties back. That work was successfully completed in 2014 and
Kyle was brought back on-stream in July. The field benefited from
early flush production with peak rates in excess of 7 kbopd
(gross). While flush production has continued into 2015 with the
field currently averaging around 5 kbopd, this is expected to
decline during the year.
Developments
Further progress was made on the Premier-operated Solan project
West of Shetland during 2014. The onshore construction of the
subsea oil storage tank jacket and topsides were completed and the
facilities were successfully installed at the end of the summer
using the Heerema Thialf heavy lift vessel. The first producer and
injector wells also successfully completed in September with good
flow rates achieved.
Commissioning commenced in November with the arrival of the Safe
Scandinavia flotel which is able to accommodate up to 400 people.
This programme, however, has taken longer than anticipated due to
poor weather conditions and low productivity over the winter
period. Whilst productivity has improved in recent weeks,
additional accommodation modules will be required to achieve
habitation on the platform. Further flotel slots have been
identified whilst conversion of the drilling rig contracted to
arrive in April is also being considered. As a result, first oil
will be later than the previous guidance of the second quarter of
2015 and Premier will provide further updates to the market as the
work progresses. Premier continues to target plateau production
rates from the field of 20-25 kbopd (gross) by year-end.
Cash spend to 31 December 2014 stood at US$1.4 billion. Premier
agreed to extend its loan to Chrysaor to ensure the project remains
fully funded to first oil. In return, Premier will take 100 per
cent of the project's cash flow (after certain deductions) until
the loan and interest has been repaid. As at 31 December, the loan
and interest outstanding stood at US$547 million. However, Premier
continues to work with Chrysaor and potential providers of debt
finance on a partial sale or refinancing of the Chrysaor loan.
The Premier-operated Catcher area project is progressing on
budget and on schedule. The development achieved partner approval
and government sanction in 2014 and the project is now well into
the execution phase. Engineering procurement and construction of
key subsea equipment, including the drilling templates, gas export
line, pipeline manifolds and subsea trees and control systems is
under way. Fabrication of the FPSO hull has also commenced, with
the first steel cut in Japan in early January 2015.
Offshore construction activity is planned to commence in
mid-2015 with the installation of the subsea facilities, including
the gas export line and drilling templates. Preparations for
development drilling with the Ensco-100 jack up rig are well
advanced and the campaign is on track to commence mid-year.
Exploration
Premier's UK North Sea exploration efforts are focused on near
field exploration opportunities close to its existing developments
and production. In particular, preparation is under way to drill an
exploration well at the Laverda prospect to the north of the
Catcher area hub in 2016.
Work also continues on the Bagpuss and Blofeld heavy oil
prospects, located on the Halibut Horst, a well-defined basement
high within the Moray Firth. The joint venture partners are
targeting the first half of 2016 for the drilling of the Bagpuss
well.
2014 saw Premier continue to high grade and rationalise its UK
North Sea exploration portfolio with a number of licences either
relinquished or sold over the course of the year.
VIETNAM
The Premier-operated Chim Sáo field out-performed expectations
in 2014 as we continued to maximise production delivery and to
improve the reliability of the facilities. The subsea tie-back of
the Dua field was completed successfully in July, extending plateau
production and the field life of Chim Sáo.
Production and development
In 2014, production from Block 12W, which contains the Chim Sáo
and Dua fields, exceeded expectations averaging 16.9 kboepd (13.7
kbpd of oil and 15.4 mmscfd of gas) net to Premier, up 19.9 per
cent on 2013.
During 2014, Premier completed significant upgrades to the Chim
Sáo FPSO aimed at maximising production deliverability and
operating efficiency. This included upgrades to the boilers and gas
compressors as well as the installation of an additional diesel
generator to improve the reliability of power generation. Premier
also increased the offshore workforce at Chim Sáo substantially to
support this improvement programme. As a result, operating
efficiency from the Chim Sáo facility increased to 88 per cent
during 2014, up 14 per cent on 2013. Record production rates of
19.2 kboepd (net) were achieved in November and December and the
field is currently producing over 20 kboepd (net).
The three well subsea tie-back of the Dua oil field to the Chim
Sáo facilities was completed, with first oil from the field
achieved in July 2014. Following the completion of the Dua drilling
programme, the West Telesto rig drilled two furtherwater injector
wells at Chim Sáo to provide pressure support to the field's oil
production. This, together with new production from Dua, will
extend plateau production and the field life of Chim Sáo.
In January 2015, Premier surpassed the milestone of 30 mmbbls
(gross) of production from Chim Sáo. This strong performance from
Block 12W has generated significant cash flows for the group and
the costs incurred to bring both Chim Sáo and Dua on-stream have
now been fully recovered.
NEW COUNTRY ENTRY - EXPLORATION
In addition to exploring in our existing core areas, Premier
looks to build business units in new countries via an
exploration-led entry strategy. The focus is on emergent plays
that, with exploration success, have the ability to develop into
new business units in the 2018 to 2025 time frame. In these new
countries Premier has a strict disciplined approach to investment
ensuring that cost exposure in the exploration phase is minimised
and only the best opportunities are matured to drill-ready status.
At year-end, Premier had established such exploration positions in
Brazil, Iraq, Kenya and the Western Sahara (SADR).
Premier entered Brazil in late 2013 securing three licenses in
the under-explored offshore regions of the proven Foz Do Amazonas
and Ceara Basins. In 2014 a small representative office was
established and new 3D seismic data was acquired over Premier's Foz
Do Amazonas Basin acreage. The full processed products are expected
to be available in the first half of 2015. Acquisition of new 3D
data over the Ceara Basin acreage is expected to commence in July
2015. The earliest exploration well on Premier's acreage in Brazil
will not be until 2017.
Premier holds a 30 per cent non-operated interest in Block 12,
onshore Iraq, in the under-explored western part of one of the
world's most prolific oil basins. At year-end a 3D seismic survey
acquisition programme was 75 per cent complete and it is
anticipated that processed products will be available in the third
quarter of 2015. There is one commitment well on this licence which
is planned to be drilled in late 2016 or early 2017.
Premier entered Kenya in 2012, and following the withdrawal from
our offshore acreage in 2014, the company focussed on one onshore
licence (Block 2B). This licence covers a Tertiary sub-basin within
the Anza Graben and was assessed as a potential look-a-like to the
successful plays drilled recently both in Uganda and further west
in Kenya. The first well on the block (Badada-1), drilled in early
2015, did not find hydrocarbons. Premier has no further commitments
in Kenya beyond the drilling of this well.
Offshore SADR, Premier holds 45,000 square kilometres (net) of
acreage across five licences. At present, all SADR licences are in
abeyance pending the country's admission to the UN.
Premier maintains two small new venture groups, one in London
and one in Singapore, tasked with evaluating exploration-led entry
options in new countries. Any new entry will be dependent on the
quality of the opportunity and its ability to create value at our
conservative oil price assumptions at the time.
FINANCIAL REVIEW
Economic background
After three and a half years in which the price of oil averaged
above US$100/bbl, crude oil experienced a sharp fall in the second
half of 2014. The average for 2014 was US$98.9/bbl against
US$108.7/bbl for the prior year. In the first half of 2014 the
Brent oil price ranged between US$104/bbl and US$115/bbl, before
falling below US$55/bbl by the end of the year.
Premier's portfolio of crudes traded at a weighted average of
US$2.0/bbl premium to Brent (2013: US$2.6/bbl), as we continued to
realise favourable prices, particularly for our Chim Sáo crude.
Premier's average realisations for the year were US$98.2/bbl (2013:
US$109.0/bbl) after taking into account timings of actual liftings
and export duties paid in Vietnam. Post hedging, realised prices
increased to US$101.0/bbl (2013: US$109.1/bbl).
Average gas prices for the group were US$8.4 per thousand
standard cubic feet (mscf) (2013: US$8.3/mscf). Gas prices in
Singapore, linked to high sulphur fuel oil (HSFO) pricing and in
turn, therefore, linked to crude oil pricing, averaged US$16.8/mscf
(2013: US$17.1/mscf). The average price for Pakistan gas (where
only a portion of the contract formulae is linked to energy prices)
was US$4.6/mscf (2013: US$4.4/mscf).
Effect of steep decline of the oil price
The fall in both spot and forward oil prices has inevitably had
an impact on our reported financial results in respect of the
carrying value of certain of our oil and gas assets. An impairment
charge has been booked in the income statement relating to several
of our fields in the UK North Sea, Indonesia, Vietnam and
Mauritania. The total amount for the impairment (pre-tax) is
US$784.4 million (US$327.8 million, post-tax). Impairment charges
for the year, relating to UK fields, amounted to US$732.3 million
(pre-tax) (2013: US$178.7 million), and were recognised for the
Solan, Balmoral area and Huntington fields, while the remaining
impairment charge of US$52.1 million was recognised in respect of
the Chim Sao field in Vietnam, the Chinguetti field in Mauritania
and the Kakap field in Indonesia. The principal cause of the
impairment charge is a reduction in the short to medium-term oil
price assumption used in estimating the future discounted cash
flows for each field. In addition to the impact of the reduced oil
price assumptions, a review of the expected decommissioning costs
for the Balmoral area in the first half of 2014 has also driven
part of the impairment charge, whilst the Solan impairment has in
part been caused by an increase in the costs incurred to date and
expected costs to completion.
Income statement
Production in 2014 averaged 63.6 kboepd (2013: 58.2 kboepd) up 9
per cent on a working interest basis. On an entitlement basis,
which under the terms of our Production Sharing Contracts (PSCs)
allows for additional government take at higher oil prices,
production was 57.7 kboepd (2013: 52.4 kboepd). Working interest
gas production averaged 177 mmscfd (2013: 174 mmscfd) or
approximately 49 per cent of total production. The increase in the
group's production can be partially attributed to an increase in
operating efficiency across a number of assets in the portfolio.
The group's operating efficiency was 84 per cent in 2014 (2013: 75
per cent).
Total sales revenue from all operations reached a new record
level of US$1.6 billion (2013: US$1.5 billion), due to higher
production partially offset by lower average oil prices. Cost of
sales, excluding impairment charges, were US$986.6 million (2013:
US$856.1 million). Operating costs were stable at US$436.1 million
(2013: US$418.9 million). Unit operating costs were US$18.5 per
barrel of oil equivalent (boe) (2013: US$19.7/boe), lower than the
prior year due to higher production, improved operating efficiency
across several of the company's assets and one-off insurance claims
received in the year. Underlying unit amortisation rose to
US$19.9/boe (2013: US$17.7/boe) mainly reflecting higher production
from fields in the UK and Vietnam, carrying a higher amortisation
charge per boe compared to the group average.
Exploration expense and pre-licence expenditure costs amounted
to US$58.5 million (2013: US$106.2 million) and US$25.3 million
(2013: US$30.1 million) respectively. This includes the write-offs
relating to Block L10B in Kenya and the Ratu Gajah well in
Indonesia, exiting our exploration licences in Mauritania and the
relinquishment of various exploration licences in the UK as part of
Premier's portfolio management programme. Net administrative costs
were US$25.4 million (2013: US$20.2 million).
Operating loss was US$248.1 million (2013: operating profit of
US$352.0 million), mainly attributable to the impairment charges
described above. Finance costs and other charges, net of interest
revenue and other gains, were US$137.1 million (2013: US$65.4
million). The interest revenue from the loan to our partner on the
Solan field development has increased to US$36.8 million (2013:
US$6.3 million), however we have recognised a provision of US$61.2
million against this long-term receivable, reflecting a reduction
in the total returns expected on the Solan field in a lower oil
price environment. The charge for the unwinding of the discounted
decommissioning provision increased to US$46.9 million (2013:
US$36.4 million) reflecting increased provisions for future
decommissioning as industry cost estimates rise.
Pre-tax losses were US$384.0 million (2013: pre-tax profits
US$285.4 million). The group tax credit for 2014 is US$173.7
million (2013: tax charge of US$51.4 million), an effective tax
rate of 45.2 per cent of the pre-tax loss. The group's theoretical
tax rate is close to 50 per cent, which includes a higher taxation
rate in the UK being offset by lower rates in Vietnam and Pakistan.
The 2014 group tax credit arises as a result of a deferred tax
credit in the UK, mainly arising from the tax effect of the
impairment charges recognised in the year and recognition of the UK
Small Fields allowance for the Catcher field. The group has an
estimated US$2.7 billion of carried forward UK corporation tax
allowances and losses, the majority of which are forecast to be
utilised against UK ring fence profits over time, and are therefore
reflected in the deferred tax asset position at the year-end. The
group did not pay any corporation tax or supplementary charge in
the UK in 2014 due to these brought forward losses.
Loss after tax is US$210.3 million (2013: profit after tax
US$234.0 million) resulting in a basic earnings per share of a loss
of 40.3 cents (2013: profit 44.7 cents).
Dividend and buyback
During 2014, Premier purchased 18.4 million shares at a volume
weighted average price of 302.0 pence and paid a dividend of 5
pence per share. In December, a decision was taken by the Board to
postpone the buyback programme pending a recovery in the oil price.
The Board has also decided to suspend the dividend and therefore no
dividend is proposed.
Cash flow
Cash flow from operating activities was US$924.3 million (2013:
US$802.5 million) after accounting for tax payments of US$208.5
million (2013: US$228.3 million). Cash movements in working capital
have improved to US$74.7 million (2013: US$1.3 million).
Capital expenditure in 2014 totalled US$1,195.5 million (2013:
US$878.0 million).
Capital expenditure (US$ million) 2014 2013
=================================== ======== ======
Fields/development projects 887.5 603.7
Exploration and evaluation 294.1 260.5
Other 13.9 13.8
Total 1,195.5 878.0
=================================== ======== ======
The principal development projects were the Solan and Catcher
fields in the UK, and the Dua field in Vietnam. In addition,
US$318.4 million (2013: US$185.9 million) funding support was
provided to our partner in the Solan project.
Exploration and evaluation spend includes costs principally
related to the exploration drilling and pre-development activities
in Norway, Indonesia, the Falkland Islands and Kenya.
Disposals and asset held for sale
During the first half of 2014, Premier announced the proposed
sale of the non-operated Scott area assets in the UK North Sea for
US$130 million, the sale of Block A Aceh onshore Indonesia for
US$40 million, and the sale of PL359, which contains the Luno II
discovery offshore Norway, for US$17.5 million prior to working
capital adjustments. The Scott area assets and Luno II transactions
were completed during the second half of 2014, whilst a US$76.9
million loss has been recognised as the anticipated loss on the
sale of Block A Aceh, which was completed in January 2015. These
disposals, combined with the write off of deferred consideration of
US$7.0 million held for the Block 07/08 disposal in 2013, resulted
in a gain on disposal of non-current assets of US$2.7 million
(2013: US$3.6 million).
Balance sheet position
Net debt at 31 December 2014 amounted to US$2,122.2 million
(2013: US$1,452.9 million), with cash resources of US$291.8 million
(2013: US$448.9 million).
Net debt (US$ million) 2014 2013
=========================== ========== ==========
Cash and cash equivalents 291.8 448.9
Convertible bonds ^ (228.5) (224.2)
Other debt*^ (2,185.5) (1,677.6)
Total net debt (2,122.2) (1,452.9)
=========================== ========== ==========
* Other debt includes EUR120.0 million of long-term senior
notes, which are valued at year-end US$1.13:EUR spot rate. These
will be redeemed at an average of US$1.39:EUR due to cross currency
swap arrangements. It also includes GBP250.0 million of UK retail
bond and long-term bank financing which are valued at year-end
US$1.56:GBP spot rate. These will be redeemed at an average of
US$1.64:GBP due to cross currency swap arrangements.
^ 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$0.4 million (2013:
US$0.6 million) and debt arrangement fees of US$27.4 million (2013:
US$12.2 million) respectively.
Long-term borrowings consist of convertible bonds, UK retail
bonds, senior loan notes and bank debt. Premier took advantage of
the strength of the banking markets in the first half of 2014 to
refinance its principal US$1.2 billion facility with a new,
increased facility of US$2.5 billion on improved terms with
extended maturity to July 2019. The group repaid a US$300 million
term loan in January 2015 which was due to mature in April
2015.
Premier does not have any significant debt maturities until late
2017 and all debt is unsecured. As at 31 December, cash and undrawn
facilities stood at US$1.9 billion.
Financial risk management
Commodity prices
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 year-end, 5.4 mmbbls of Dated Brent oil were hedged through
forward sales for 2015 at an average price of US$98.3/bbl. This
volume represents approximately 50 per cent of the group's expected
liquids entitlement production in 2015. 84,000 metric tonnes (mt)
of HSFO, which drives our gas contract pricing in Singapore, has
been sold forward for 2015 at an average price of US$614.4/mt.
These hedges cover approximately 13 per cent of our expected
Indonesian gas entitlement production for 2015.
The year-end fair value on the commodity was US$250.1 million
(2013: loss US$24.2 million), which is expected to be released to
the income statement during 2015 as the related barrels are
lifted.
During 2014, forward oil sales of 5.6 mmbbls, and forward fuel
oil sales of 222,000 mt expired resulting in a net credit of
US$45.9 million (2013: US$0.8 million) which has been included
within 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$6.0 million on its outstanding
foreign exchange contracts (2013: gain of US$13.1 million). The
group currently has GBP150.0 million retail bonds, EUR120.0 million
long-term senior loan notes and 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$1.34: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, 56 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 4.4
per cent. Mark-to-market credits on interest rate swaps amounted to
US$6.8 million (2013: credit of US$6.4 million), which are recorded
as movements in other comprehensive income.
Cash balances are invested in short-term bank deposits and AAA
rated liquidity funds, subject to Board approved limits and with a
view to spreading counterparty risks.
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
2014, claims amounting to US$20.5 million were agreed in relation
to property damage and business interruption on Chim Sao gas export
pipeline damage in 2013.
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.
Due to the current weakness in oil and gas prices, the directors
have reduced planned development and exploration expenditure for
2015, are implementing a series of cost saving initiatives to
reduce both operating costs and G&A spend and have identified a
range of portfolio management opportunities to monetise certain of
the group's current development and exploration assets and to
source additional sources of financing.
At year-end, the group had significant headroom on its borrowing
facilities and related financial covenants. The group's forecasts
and projections, which take into account the actions described in
the preceding paragraph, also indicate that the company will be
able to operate within the requirements of its existing borrowing
facilities for 12 months from the date of approval of the Annual
Report and Accounts. However, if there were further sustained falls
in the oil price or if certain of the identified portfolio
management opportunities are delayed or cancelled, whilst forecasts
indicate that the group's liquidity will remain strong, it is
possible that management will need to request a temporary amendment
to the terms of one of its financial covenants. If the group's
ongoing forecasts were to suggest that this would be required,
management would take appropriate action with the support of its
long-term banking relationships well in advance of such
requirement, and management have no reason to believe that such
support would not be forthcoming. 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 and with whom we interact and our reputation.
Premier therefore has a comprehensive approach to risk
management.
A critical part of the risk management process is to assess the
impact and likelihood of risks occurring so that appropriate
mitigation plans can be developed and implemented. Risk severity
matrices are developed across Premier's business to facilitate
assessment of risk. The specific risks identified by project and
asset teams, business units and corporate functions are
consolidated and amalgamated to provide an oversight of key risk
factors at each level, from operations through business unit
management to the Executive Committee and the Board.
For all the known risks facing the business, Premier attempts to
minimise the likelihood and mitigate the impact. According to the
nature of the risk, Premier may elect to take or tolerate risk,
treat risk with controls and mitigating actions, transfer risk to
third parties, or terminate risk by ceasing particular activities
or operations. Premier has a zero tolerance to financial fraud or
ethics non-compliance, and ensures that HSES risks are managed to
levels that are as low as reasonably practicable, whilst managing
exploration and development risks on a portfolio basis.
The group has identified its principal risks for the next 12
months as being:
-- 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 the company's website
(www.premier-oil.com).
CONSOLIDATED INCOME STATEMENT
For the year ended 31 December 2014
2014 2013
$ million $ million
--------------------------------------------- ---------- ------------
Sales revenues 1,629.4 1,501.0
Other operating income - 38.7
Cost of sales (986.6) (856.1)
Impairment charge on oil and gas properties (784.4) (178.7)
Exploration expense (58.5) (106.2)
Pre-licence exploration costs (25.3) (30.1)
Profit on disposal of non-current assets 2.7 3.6
General and administration costs (25.4) (20.2)
--------------------------------------------- ---------- ------------
Operating (loss)/profit (248.1) 352.0
--------------------------------------------- ---------- ------------
Share of profit in associate 1.9 -
Interest revenue, finance and other gains 58.5 33.0
Finance costs, other finance expenses
and losses (196.3) (98.4)
Loss on commodity derivative financial
instruments - (1.2)
--------------------------------------------- ---------- ------------
(Loss)/profit before tax (384.0) 285.4
Tax 173.7 (51.4)
--------------------------------------------- ---------- ------------
(Loss)/profit after tax (210.3) 234.0
--------------------------------------------- ---------- ------------
Earnings per share (cents):
Basic (40.3) 44.2
Diluted (40.3) 43.2
--------------------------------------------- ---------- ------------
The results relate entirely to continuing operations.
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
For the year ended 31 December 2014
2014 2013
$ million $ million
------------------------------------------------------- ---------- ----------
(Loss)/profit for the year (210.3) 234.0
------------------------------------------------------- ---------- ----------
Cash flow hedges on commodity swaps:
Gains/(losses) arising during the year 296.1 (25.0)
Less: reclassification adjustments for
losses in the year (46.0) 0.8
---------- ----------
250.1 (24.2)
Tax relating to components of other comprehensive
income 139.0 13.9
Cash flow hedges on interest rate and
foreign exchange swaps 15.5 (0.8)
Exchange differences on translation of
foreign operations (48.3) (17.5)
Actuarial (losses)/gains on long-term
employee benefit plans (0.2) (6.5)
------------------------------------------------------- ---------- ----------
Other comprehensive income/(expense) 78.1 (35.1)
------------------------------------------------------- ---------- ----------
Total comprehensive (expense)/income for
the year (132.2) 198.9
------------------------------------------------------- ---------- ----------
All comprehensive income is attributable to the equity holders
of the parent.
CONSOLIDATED BALANCE SHEET
As at 31 December 2014
2014 2013
$ million $ million
-------------------------------------------- ---------- ----------
Non-current assets:
Intangible exploration and evaluation
assets 825.7 701.0
Property, plant and equipment 2,430.0 2,885.9
Goodwill 240.8 240.8
Investment in associate 7.6 6.2
Long-term employee benefit plan surplus 0.8 1.0
Long-term receivables 494.1 198.1
Deferred tax assets 971.7 762.4
-------------------------------------------- ---------- ----------
4,970.7 4,795.4
-------------------------------------------- ---------- ----------
Current assets:
Inventories 26.1 49.5
Trade and other receivables 411.0 421.8
Tax recoverable 57.9 82.4
Derivative financial instruments 273.4 15.9
Cash and cash equivalents 291.8 448.9
Assets held for sale 56.7 -
-------------------------------------------- ---------- ----------
1,116.9 1,018.5
-------------------------------------------- ---------- ----------
Total assets 6,087.6 5,813.9
-------------------------------------------- ---------- ----------
Current liabilities:
Trade and other payables (544.5) (512.4)
Current tax payable (84.2) (92.0)
Provisions (14.1) (13.1)
Derivative financial instruments (48.1) (38.3)
Short-term debt (300.0) -
Liabilities directly associated with asset (1.8) -
held for sale
(992.7) (655.8)
-------------------------------------------- ---------- ----------
Net current assets/(liabilities) 124.2 362.7
-------------------------------------------- ---------- ----------
Non-current liabilities:
Convertible bonds (228.1) (223.8)
Other long-term debt (1,858.1) (1,665.4)
Deferred tax liabilities (254.2) (306.8)
Long-term provisions (864.0) (824.6)
Long-term employee benefit plan deficit (18.3) (13.1)
(3,222.7) (3,033.7)
-------------------------------------------- ---------- ----------
Total liabilities (4,215.4) (3,689.5)
-------------------------------------------- ---------- ----------
Net assets 1,872.2 2,124.4
-------------------------------------------- ---------- ----------
Equity and reserves:
Share capital 106.7 110.5
Share premium account 275.4 275.3
Merger reserve 374.3 374.3
Retained earnings 1,142.3 1,342.1
Other reserves (26.5) 22.2
-------------------------------------------- ---------- ----------
1,872.2 2,124.4
-------------------------------------------- ---------- ----------
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
For the year ended 31 December 2014
Attributable to the equity holders of the parent
--------------------------------------------------------------------------------------
Other reserves
--------------------------------------
Share Share Retained Merger Capital Translation Equity Total
capital premium earnings reserve redemption reserves reserve
account reserve
$ million $ million $ million $ million $ million $ million $ million $ million
------------------ ---------- ---------- ---------- ---------- ------------ ------------ ---------- ----------
At 1 January 2013 110.5 274.9 1,150.1 374.3 4.3 17.1 22.3 1,953.5
Issue of Ordinary
Shares - 0.4 - - - - - 0.4
Purchase of ESOP
Trust
shares - - (12.8) - - - - (12.8)
Provision for
share-based
payments - - 24.6 - - - - 24.6
Transfer between
reserves - - 4.0 - - - (4.0) -
Dividends paid - - (40.2) - - - - (40.2)
Total
comprehensive
income - - 216.4 - - (17.5) - 198.9
------------------ ---------- ---------- ---------- ---------- ------------ ------------ ---------- ----------
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
------------------ ---------- ---------- ---------- ---------- ------------ ------------ ---------- ----------
CONSOLIDATED CASH FLOW STATEMENT
For the year ended 31 December 2014
2014 2013
$ million $ million
--------------------------------------------- ---------- ----------
Net cash from operating activities 924.3 802.5
--------------------------------------------- ---------- ----------
Investing activities:
Capital expenditure (1,195.5) (878.0)
Disposal of oil and gas properties 130.7 61.0
Loan to joint venture partner (318.4) (185.9)
--------------------------------------------- ---------- ----------
Net cash used in investing activities (1,383.2) (1,002.9)
--------------------------------------------- ---------- ----------
Financing activities:
Proceeds from issuance of Ordinary Shares 0.1 0.4
Purchase and cancellation of own shares (93.0) -
Purchase of ESOP Trust shares (6.4) (12.8)
Proceeds from drawdown of long-term bank
loans 655.0 384.1
Proceeds from issuance of senior loan notes - 156.7
Proceeds from issuance of retail bonds - 245.8
Debt arrangement fees (22.1) (7.1)
Repayment of long-term bank loans (100.0) (200.0)
Dividends paid (44.0) (40.2)
Interest paid (98.1) (71.1)
--------------------------------------------- ---------- ----------
Net cash from financing activities 291.5 455.8
--------------------------------------------- ---------- ----------
Currency translation differences relating
to cash and cash equivalents 10.3 6.1
--------------------------------------------- ---------- ----------
Net (decrease)/increase in cash and cash
equivalents (157.1) 261.5
Cash and cash equivalents at the beginning
of the year 448.9 187.4
--------------------------------------------- ---------- ----------
Cash and cash equivalents at the end of
the year 291.8 448.9
--------------------------------------------- ---------- ----------
NOTES TO THE PRELIMINARY FINANCIAL STATEMENTS
For the year ended 31 December 2014
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 25 February 2015.
The financial information for the year ended 31 December 2014
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 2013 were
approved by the Board of Directors on 25 February 2014 and
delivered to the Registrar of Companies and those for 2014 will be
delivered following the company's Annual General Meeting (AGM). The
auditor has reported on these accounts; the reports were
unqualified, did not include a reference to any matters to which
the auditor drew attention by way of emphasis of matter and did not
contain statements under section 498(2) or 498(3) of the Companies
Act 2006.
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 2015.
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.
Accounting policies
The accounting policies applied in this announcement are
consistent with those of the annual financial statements for the
year ended 31 December 2013, as described in those annual financial
statements. A number of amendments to existing standards and
interpretations were applicable from 1 January 2014. The adoption
of these amendments did not have a material impact on the group's
financial statements for the year ended 31 December 2014.
2 Operating segments
The group's operations are located and managed in seven business
units; namely the Falklands 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.
2014 2013
-------------------------------------------
$ million $ million
------------------------------------------- ---------- ----------
Revenue:
Indonesia 325.7 295.9
Pakistan (including Mauritania) 141.6 165.4
Vietnam 473.3 468.2
United Kingdom 688.8 571.5
------------------------------------------- ---------- ----------
Total group sales revenue 1,629.4 1,501.0
Other income - United Kingdom - 38.7
Interest and other finance revenue 39.4 10.9
=========================================== ========== ==========
Total group revenue 1,668.8 1,550.6
------------------------------------------- ---------- ----------
Group operating profit/(loss):
Indonesia 181.4 187.0
Norway (17.4) (26.5)
Pakistan (including Mauritania) 32.4 84.0
Vietnam 76.6 195.9
United Kingdom (446.6) (31.5)
Rest of the world (23.6) (8.7)
Unallocated * (50.9) (48.2)
------------------------------------------- ---------- ----------
Group operating (loss)/profit (248.1) 352.0
Share of profit in associate 1.9 -
Interest revenue, finance and other gains 58.5 33.0
Finance costs and other finance expenses (196.3) (98.4)
Loss on derivative financial instruments - (1.2)
------------------------------------------- ---------- ----------
(Loss)/profit before tax (384.0) 285.4
Tax 173.7 (51.4)
------------------------------------------- ---------- ----------
(Loss)/profit after tax (210.3) 234.0
------------------------------------------- ---------- ----------
Balance sheet
Segment assets:
Falkland Islands 430.6 297.2
Indonesia 701.0 731.5
Norway 197.9 231.3
Pakistan (including Mauritania) 101.7 117.4
Vietnam 569.9 648.5
United Kingdom 3,428.2 3,260.4
Rest of the world 92.1 62.8
Unallocated* 566.2 464.8
------------------------------------------- ---------- ----------
Total assets 6,087.6 5,813.9
------------------------------------------- ---------- ----------
2014 2013
=============================================
$ million $ million
============================================= ========== ==========
Liabilities:
Falkland Islands (28.5) (14.6)
Indonesia (326.4) (296.3)
Norway (60.3) (83.9)
Pakistan (including Mauritania) (103.0) (88.4)
Vietnam (322.7) (316.9)
United Kingdom (913.9) (948.1)
Rest of the world (26.2) (14.0)
Unallocated(*) (2,434.4) (1,927.3)
Total liabilities (4,215.4) (3,689.5)
============================================= ========== ==========
Other information
Capital additions and acquisitions:
Falkland Islands 112.9 54.0
Indonesia 149.2 101.0
Norway 68.1 49.9
Pakistan (including Mauritania) 33.4 33.8
Vietnam 156.7 121.9
United Kingdom 654.3 615.4
Rest of the world 36.8 47.5
--------------------------------------------- ---------- ----------
Total capital additions and acquisitions 1,211.4 1,023.5
--------------------------------------------- ---------- ----------
Depreciation, depletion, amortisation and
impairment:
Indonesia 73.7 57.1
Pakistan (including Mauritania) 41.8 42.5
Vietnam 185.6 117.1
United Kingdom 938.2 344.8
Rest of the world 1.5 1.0
--------------------------------------------- ---------- ----------
Total depreciation, depletion, amortisation
and impairment 1,240.8 562.5
--------------------------------------------- ---------- ----------
* 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.
3 Cost of sales
2014 2013
$ million $ million
============================================ ========== ==========
Operating costs 436.1 418.9
Stock overlift/underlift movement 48.5 9.8
Royalties 45.6 43.6
Amortisation and depreciation of property,
plant and equipment:
Oil and gas properties 446.1 375.0
Other fixed assets 10.3 8.8
986.6 1,034.8
============================================ ========== ==========
4 Tax
2014 2013
$ million $ million
========================================= ========== ==========
Current tax:
UK corporation tax on profits (1.5) (12.1)
UK petroleum revenue tax 65.4 100.9
Overseas tax 154.1 122.7
Adjustments in respect of prior years 1.9 (22.3)
----------------------------------------- ---------- ----------
Total current tax 219.9 189.2
----------------------------------------- ---------- ----------
Deferred tax:
UK corporation tax (382.2) (180.5)
UK petroleum revenue tax 33.7 (6.4)
Overseas tax (45.1) 49.1
----------------------------------------- ---------- ----------
Total deferred tax (393.6) (137.8)
Tax (credit)/charge on (loss)/profit on
ordinary activities (173.7) 51.4
========================================= ========== ==========
5 Deferred tax
2014 2013
$ million $ million
========================== ========== ==========
Deferred tax assets 971.7 762.4
Deferred tax liabilities (254.2) (306.8)
-------------------------- ---------- ----------
717.5 455.6
-------------------------- ---------- ----------
(Charged)/
At 1 credited Credited At 31
January Exchange Disposal to income to retained December
2014 movements of asset statement earnings 2014
$ million $ million $ million $ million $ million $ million
=============================== --------- ---------- --------- ---------- ------------- ----------
UK deferred corporation
tax:
Fixed assets and allowances (828.2) - - 72.2 - (756.0)
Decommissioning 321.7 - - 8.1 - 329.8
Deferred petroleum revenue
tax (5.4) - - 20.9 - 15.5
Tax losses and allowances 1,203.8 - - 171.6 - 1,375.4
Small field allowance 47.8 - - 109.4 - 157.2
Derivative financial
instruments 13.9 - - - (139.0) 125.1
------------------------------- --------- ---------- --------- ---------- ------------- ----------
Total UK deferred corporation
tax 753.6 - - 382.2 (139.0) 996.8
UK deferred petroleum
revenue tax(1) 8.7 - - (33.7) - (25.0)
Overseas deferred tax(2) (306.7) 7.4 22.2 22.9 - (254.2)
------------------------------- --------- ---------- --------- ---------- ------------- ----------
Total 455.6 7.4 22.2 371.4 (139.0) 717.5
------------------------------- --------- ---------- --------- ---------- ------------- ----------
(1) The UK deferred petroleum revenue tax relates mainly to
temporary differences associated with decommissioning provisions.
(2) The overseas deferred tax relates mainly to temporary differences
associated with fixed asset balances.
The group's unutilised tax losses and allowances at 31 December
2014 are recognised to the extent that taxable profits are expected
to arise in the future against which the tax losses and allowances
can be utilised. In accordance with paragraph 37 of IAS 12 -
'Income Taxes' the group re-assessed its unrecognised deferred tax
assets at 31 December 2014 with respect to ring fence tax losses
and allowances. The corporate model used to determine the
recognition of deferred tax assets was re-run, using an oil price
assumption of Dated Brent forward curve in 2015 and 2016, and
US$85/bbl in 'real' terms thereafter. The results of the corporate
model concluded that it was no longer appropriate to recognise an
amount of US$86.8 million in respect of the group's UK ring fence
deferred tax assets relating to tax losses and allowances.
In addition to the above, there are non-ring fence tax losses of
approximately US$263.1 million (2013: US$321.1 million) and current
year non-UK tax losses of US$40.8 million (2013: US$14.3 million)
for which a deferred tax asset has not been recognised.
None of the UK tax losses (ring fence and non-ring fence) have a
fixed expiry date for tax purposes.
No deferred tax has been provided on unremitted earnings of
overseas subsidiaries, following a change in UK tax legislation in
2009 which exempted foreign dividends from the scope of UK
corporation tax where certain conditions are satisfied.
6 (Loss)/earnings per share
The calculation of basic (loss)/earnings per share is based on
the (loss)/profit after tax and on the weighted average number of
Ordinary Shares in issue during the year.
Basic and diluted (loss)/earnings per share were calculated as
follows:
Year to Year to
31 31 December
December 2013
2014
(Loss)/earnings ($ millions):
(Loss)/Earnings for the purpose of
basic earnings per share being net
profit attributable to owners of the
company (210.3) 234.0
Effect of dilutive potential Ordinary
Shares:
Interest on convertible bonds - 2014
anti-dilutive - 10.3
=========================================== ========== =============
(Loss)/earnings for the purposes of
diluted earnings per share (210.3) 244.3
=========================================== ========== =============
Number of shares (millions):
Weighted average number of Ordinary
Shares for the purpose of basic earnings
per share 521.9 529.2
Effects of dilutive potential Ordinary
Shares:
Contingently issuable shares - 2014
anti-dilutive - 36.0
=========================================== ==========
Weighted average number of Ordinary
Shares for the purpose of diluted
earnings per share 521.9 565.2
=========================================== ========== =============
(Loss)/earnings per share (cents):
Basic (40.3) 44.2
Diluted (40.3) 43.2
=========================================== ========== =============
* There were 37.1 million anti-dilutive potential Ordinary
Shares in 2014 mainly comprising of shares to be issued
on conversion of convertible bonds.
7 Intangible exploration and evaluation (E&E) assets
Oil and gas properties Total
---------------------------------------------
$ million
--------------------------------------------- ==========
Cost:
At 1 January 2013 658.0
Exchange movements (17.3)
Additions during the year 266.9
Disposals (101.3)
Transfer to property, plant and equipment 0.9
Exploration expense (106.2)
============================================= ==========
At 31 December 2013 701.0
Exchange movements (37.1)
Additions during the year 294.0
Disposals (46.5)
Transfer from property, plant and equipment (1.7)
Exploration expense (58.5)
Transfer to asset held for sale (25.5)
============================================= ==========
At 31 December 2014 825.7
--------------------------------------------- ----------
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.
During the year, the group sold its interest in the PL359
licence in Norway, which contained the Luno II discovery, for
US$38.2 million cash consideration, recognising a loss tax of
US$9.7 million.
8 Property, plant and equipment
Oil and gas Other
properties fixed assets Total
$ million $ million $ million
=============================== =========== ============== ==========
Cost:
At 1 January 2013 4,183.2 38.5 4,221.7
Additions during the year 742.8 13.8 756.6
Transfer from/(to) intangible
E&E assets 3.3 (4.3) (1.0)
=============================== =========== ============== ==========
At 31 December 2013 4,929.3 48.0 4,977.3
Exchange movements - (2.0) (2.0)
Additions during the year 903.5 13.9 917.4
Disposals (211.4) - (211.4)
Transfer to asset held for
sale (124.5) - (124.5)
Transfer from/(to) intangible
E&E assets 1.7 - 1.7
=============================== =========== ============== ==========
At 31 December 2013 5,498.6 59.9 5,558.5
=============================== =========== ============== ==========
Amortisation and depreciation:
At 1 January 2013 1,509.0 19.8 1,528.8
Exchange movements - 0.1 0.1
Charge for the year 375.0 8.8 383.8
Impairment charge 178.7 - 178.7
At 31 December 2013 2,062.7 28.7 2,091.4
Exchange movements - (1.8) (1.8)
Charge for the year 446.1 10.3 456.4
Impairment charge 784.4 - 784.4
Disposals (179.9) - (179.9)
Transfer to asset held for
sale (22.0) - (22.0)
=============================== =========== ============== ==========
At 31 December 2014 3,091.3 37.2 3,128.5
=============================== =========== ============== ==========
Net book value:
At 31 December 2013 2,866.6 19.3 2,885.9
=============================== =========== ============== ==========
At 31 December 2014 2,407.3 22.7 2,430.0
------------------------------- ----------- -------------- ----------
* Finance costs that have been capitalised within oil and
gas properties during the year total US$42.2 million (2013:
US$25.6 million), at a weighted average interest rate
of 4.40 per cent (2013: 4.70 per cent).
Other fixed assets include items such as leasehold improvements,
motor vehicles and office equipment.
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 in the current year relates to the the
Balmoral area, Huntington and Solan fields in the UK (US$732.3
million), the Chim Sáo field in Vietnam (US$41.8 million), the
Kakap field in Indonesia (US$5.0 million) and the Chinguetti field
in Mauritania (US$5.3 million). The impairment charge of US$784.4
million 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 2015 and 2016, and
US$85/bbl in 'real' terms thereafter and were discounted using a
pre-tax discount rate in the range of 10.0 per cent for the UK
assets and 12.5 per cent for the non-UK assets. 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 principal cause of the impairment charge being
recognised in the year is a reduction in the short to medium term
oil price assumption being used when determining the future
discounted cash flows for each field. In addition to the impact of
the reduced oil price assumption, a review of the expected
decommissioning costs for the Balmoral area in the first half of
2014 has also driven part of the impairment charge, whilst the
Solan impairment has in part been caused by an increase in the
costs incurred to date and expected costs to completion for the
project.
During the year, the group disposed of its interest in the Scott
area assets in the UK North Sea for US$130 million, resulting in a
pre-tax profit of US$96.3 million. In addition, the group announced
its intention to sell its interests in Block A Aceh in Indonesia
for US$40 million, resulting in the asset being reclassified as
held for sale at 31 December 2014, . An anticipated loss of US$76.9
million has been recognised for the sale of Block A Aceh, which was
completed in early January 2015. At 31 December 2014, the assets
separately held on the balance sheet for Block A Aceh are US$56.7
million with associated liabilities of US$1.8 million. The gain on
disposal of non-current asset recognised int eh income statement
also includes the loss recognised in relation to PL 359 in Norway
(see note 7) and the write-off of deferred consideration of US$7.0
million previously held for the disposal of Block 07/03 in Vietnam
during 2013.
9 Notes to the cash flow statement
2014 2013
$ million $ million
=========================================== ========== ==========
(Loss) / profit before tax for the year (384.0) 285.4
Adjustments for:
Depreciation, depletion, amortisation and
impairment 1,240.8 562.5
Exploration expense 58.5 106.2
Provision for share-based payments 6.9 7.9
Share of profit in associate (1.9) -
Interest revenue and finance gains (58.5) (33.0)
Finance costs and other finance expenses 196.3 98.4
Other gains and losses (2.7) (3.6)
Loss on derivative financial instruments - 1.2
Operating cash flows before movements in
working capital 1,055.4 1,025.0
Decrease/(increase) in inventories 23.0 (14.9)
(Increase)/decrease in receivables 105.3 45.1
Decrease in payables (55.6) (28.9)
=========================================== ========== ==========
Cash generated by operations 1,130.1 1,026.3
Income taxes paid (208.5) (228.3)
Interest income received 2.7 4.5
=========================================== ========== ==========
Net cash from operating activities 924.3 802.5
=========================================== ========== ==========
Analysis of changes in net debt:
2014 2013
$ million $ million
================================================ ========== ==========
a) Reconciliation of net cash flow to movement
in net debt:
Movement in cash and cash equivalents (157.1) 261.5
Proceeds from drawdown of long-term bank
loans (655.0) (384.1)
Proceeds from issuance of senior loan notes - (156.7)
Proceeds from issuance of retail bonds - (245.8)
Repayment of long-term bank loans 100.0 200.0
Non-cash movements on debt and cash balances 42.8 (17.4)
------------------------------------------------ ---------- ----------
Increase in net debt in the year (669.3) (342.5)
Opening net debt (1,452.9) (1,110.4)
================================================ ========== ==========
Closing net debt (2,122.2) (1,452.9)
================================================ ========== ==========
b) Analysis of net debt:
Cash and cash equivalents 291.8 448.9
Borrowings(*) (2,414.0) (1,901.8)
=========================== ========== ==========
Total net debt (2,122.2) (1,452.9)
=========================== ========== ==========
* Borrowings consist of the short-term borrowings, the 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$0.4 million (2013: US$0.4 million)
and debt arrangement fees of US$27.4 million (2013: US$12.2
million) respectively.
10 Dividends
During 2014 Premier paid a dividend of 5 pence per share, no
dividend is proposed in relation to year-end 2014.
11 External audit
This preliminary announcement is consistent with the audited
financial statements of the group for the year-ended 31 December
2014.
12 Publication of financial statements
It is anticipated that the full Annual Report and Financial
Statements will be published on 7 April 2015. 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).
13 Annual General Meeting
The Annual General Meeting will be held at the Institute of
Directors, 116 Pall Mall, London SW1Y 5ED on Wednesday 13 May 2015
at 11.00am.
.
Working interest reserves at 31 December 2014
Working interest basis
-------------------- ======= ======= =============================================================================================================
Indonesia Mauritania Pakistan UK Vietnam TOTAL
Norway
---------------- ------------- ------------- ---------------- ---------------- ---------------- -------------------------
Oil,
Oil Oil Oil Oil Oil Oil Oil NGLs
and and and and and and and and
NGLs Gas NGLs Gas NGLs Gas NGLs Gas NGLs Gas NGLs Gas NGLs Gas(4) gas
mmbbls bcf mmbbls bcf mmbbls bcf mmbbls bcf mmbbls bcf mmbbls bcf mmbbls bcf Mmboe
-------------------- ------- ------- ------- ---- ------- ---- ------- ------- ------- ------- ------- ------- ------- ------- -------
Group proved plus probable
reserves:
At 1 January 2014 5.7 435.4 0.4 - - - 0.3 144.3 110.3 59.1 25.2 39.6 141.9 678.4 259.4
Revisions(1) (0.5) (12.9) 0.2 - 22.6 - (0.1) 17.2 (1.9) 0.5 0.1 0.4 20.3 (25.8) 15.8
Discoveries and
extensions(2) - - - - - - - 3.3 - - - - - 3.3 0.6
Acquisitions and
divestments(3) - - - - - - - - (5.7) (20.0) - - (5.7) (20.0) (9.4)
Production (0.3 (25.0) 0.2 - - - (0.1) (28.2) (6.0) (5.1) (5.0) (5.8) (11.5) (64.0) (23.1)
-------------------- ------- ------- ------- ---- ------- ---- ------- ------- ------- ------- ------- ------- ------- ------- -------
At 31 December
2014 4.9 397.6 0.4 - 22.6 - (0.2) 102.2 96.5 34.6 20.3 (34.2) 144.9 571.8 243.3
-------------------- ------- ------- ------- ---- ------- ---- ------- ------- ------- ------- ------- ------- ------- ------- -------
Total group developed and
undeveloped reserves:
Proved on
production 0.9 107.7 0.2 - - - (0.2) 86.3 14.8 4.8 13.6 25.6 29.6 224.4 69.6
Proved
approved/justified
for development 2.3 175.2 - - 15.4 - - - 40.2 18.8 1.4 - 59.3 196.6 90.2
Probable on
production 0.9 61.7 0.2 - - - - 15.9 9.9 4.9 5.4 8.5 16.4 91.0 33.3
Probable
approved/justified
for development 0.8 53.0 - - 7.3 - - - 31.6 6.1 - - 39.7 59.8 50.3
-------------------- ------- ------- ------- ---- ------- ---- ------- ------- ------- ------- ------- ------- ------- ------- -------
At 31 December
2014 4.9 397.6 0.4 - 22.6 - 0.2 102.2 96.5 34.6 20.3 34.2 144.9 571.8 243.3
-------------------- ------- ------- ------- ---- ------- ---- ------- ------- ------- ------- ------- ------- ------- ------- -------
Notes:
1. Includes re-evaluation of reserves at Anoa, Gajah Puteri, Iguana, Bison, Kakap (Indonesia); Kadanwari,
Bhit, Badhra,
Zamzama (Pakistan); Balmoral, Wytch Farm and Catcher Area (UK). Reserves from Beacon Field have been
re-classified
as contingent resources. Contingent resource in Bream has been reclassified as reserves - 'Justified for
Development'.
2. Includes reserves added at Kadanwari (Pakistan) through new K-36 well. Discoveries at
Kuda Laut & Singa Laut (Indonesia)
are classified as contingent resources and do not appear in this table.
3. Divestment of Scott, Telford and Rochelle (UK) was completed on 19 December 2014.
Note: Block A Aceh resource is still included in this table as Divestment completed after year end,
on 12 Jan 2015).
4. Proved plus probable gas reserves include 66 bcf fuel gas.
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.
This information is provided by RNS
The company news service from the London Stock Exchange
END
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