TIDMPMO
RNS Number : 9561T
Premier Oil PLC
12 January 2017
This announcement has been determined to contain inside
information
PREMIER OIL PLC
("Premier" or "the Group")
Trading and Operations Update
12 January 2016
Premier today provides the following Trading and Operations
Update ahead of its 2016 Full Year Results which will be announced
on Thursday 9 March 2017.
2016 Highlights
-- Record production of 71.4 kboepd, up 24% on
2015 and in line with previously upgraded guidance
-- Opex per barrel of $15.7/bbl
-- Estimated capex of $690 million, below guidance
of $730 million
-- Net debt of $2.8 billion as at 31 December
2016, reduced in Q4 as anticipated
-- Cash and undrawn facilities of around $600
million
Outlook
-- 2017 production guidance of 75 kboepd, before
any contribution from Catcher and adjusted
for lower Solan profile
-- Catcher on schedule for start-up later this
year with total capex now forecast at $1.6
billion, 29% lower than sanctioned estimate
-- Approval of Tolmount development concept expected
shortly, will provide next phase of growth
-- Increased equity interest to 25% in large Zama
prospect (Mexico); expected to spud early Q2
-- 2017 capex guidance of $350 million (including
abandonment spend)
-- Net debt will continue to reduce at current
forward curve
Refinancing
-- All substantial commercial terms have been
agreed with the Coordinating Committee of the
RCF Group and representatives of the other
Private Lenders; long form term sheet at advanced
stage
-- Publication of full details of terms on circulation
of the long form term sheet to lenders which
is expected shortly
Tony Durrant, Chief Executive, commented:
"Premier achieved a strong operational performance in 2016,
resulting in record production and the successful integration of
the ex-E.ON portfolio. The Catcher project continues to progress
well and will provide another step change in production, generating
enhanced, tax-free cash flows for the Group. Our debt refinancing
is nearing completion which, together with the improving commodity
price environment, will enable us both to accelerate debt reduction
and to progress future growth projects."
Enquiries
Premier Oil plc Tel: 020 7730 1111
Tony Durrant, Chief
Executive
Richard Rose, Finance
Director
Bell Pottinger Tel: 020 3772 2570
Lorna Cobbett
Henry Lerwill
Refinancing update
All substantial commercial terms have now been agreed with the
Coordinating Committee of the RCF Group and representatives of the
other Private Lenders (Term Loan, Schuldschein and USPP
noteholders). The long form term sheet, in which these commercial
terms are embedded, is at an advanced stage and is expected to be
circulated to all lenders for their review and formal approval
shortly. At that time, Premier expects to announce the full detail
of the commercial terms which Premier anticipates will include
equity warrants as part of the economics to lenders. Implementation
of the refinancing will not otherwise be conditional upon the issue
of new equity.
Premier plans to enter into a lock up agreement in relation to
the long form term sheet with Private Lenders during February.
Revised refinancing documents will then be finalised along with the
documentation for implementation of the refinancing via a court
Scheme of Arrangement.
Substantially the same economic terms will be offered to the
retail bondholders as to the Private Lenders and these will also be
disclosed at the same time as the terms being offered to the
Private Lenders. Negotiations with the advisers to an ad hoc
committee of the Group's convertible bondholders are ongoing.
Production operations
Premier delivered record production of 71.4 kboepd in 2016, in
line with previously upgraded full year guidance of 68-73 kboepd
and up 24% on the prior year (2015: 57.6 kboepd). Production in Q4
2016 averaged over 80 kboepd, reflecting a full contribution from
the ex-E.ON assets and new production from the Solan field as well
as sustained high production efficiency across the portfolio.
Kboepd 2016 2015
------------- ----- -----
Indonesia 14.3 13.9
Pakistan &
Mauritania 7.9 10.1
UK 33.0 16.7
Vietnam 16.2 16.9
------------- ----- -----
Total 71.4 57.6
------------- ----- -----
In the UK, production averaged 33.0 kboepd during 2016, double
that of 2015, and over 40 kboepd in Q4 2016. The step change in
production was helped by the new contributions from the ex-E.ON
portfolio and the Solan field.
Production from the ex-E.ON portfolio exceeded expectations,
averaging 16.3 kboepd over the 8 months from 31 April to 31
December 2016. The Huntington field averaged 10.8 kboepd during
2016, significantly above budget as a result of high uptime and
strong reservoir performance. With further well management, Premier
aims to maintain production from the field at these levels during
2017. Production from the Elgin-Franklin field increased during the
year benefitting from an ongoing infill drilling programme,
averaging 5.0 kboepd for the 8 months from 31 April to 31 December
2016 and 6.5 kboepd in Q4 2016. Further infill wells are planned
for 2017. Babbage and Wytch Farm also delivered a strong
performance in 2016, underpinned by high facilities uptime of over
90% and continued strong reservoir performance. Premier will also
be implementing a not normally manned operation from Q2 2017 at
Babbage to reduce operating expenditure for the remainder of the
field life and also well intervention activities to maintain
production levels. The purchase of the E.ON portfolio, which cost
$120 million (before working capital adjustments), is expected to
reach pay back during 2017 1H, earlier than anticipated as a result
of both the stronger production performance and higher commodity
prices.
Production from the Premier-operated Solan field was lower than
anticipated as a result of a later start-up and poorer than
expected reservoir performance which is limiting water injection
and P2 production rates. Actions to address this issue are underway
including short term increases in water injection pump capacity
(now implemented) and other modifications being considered for
later in the year. Premier anticipates that production from the
field in 2017 will remain at 10-13 kbopd with any material
production uplift from remedial action unlikely before 2018.
Production efficiency of the facilities has been good and six oil
tanker-off loadings have now been successfully completed.
Premier's operated South East Asia assets outperformed during
2016. High uptime of over 90%, better than expected reservoir
performance and a successful well intervention programme helped to
mitigate natural decline from the Chim Sáo field in Vietnam. A two
well infill drilling programme, scheduled to commence in August
2017, will help to maximise production levels from the field.
Across the border in Indonesia, Premier's operated Natuna Sea Block
A secured an increased market share within its principal gas
contract GSA1 of 44% (2015: 43%) against a contractual share of 41%
and delivered record production under GSA2 of 94 BBtud during 2016.
Natuna Sea Block A's contractual share of GSA1 has increased to 47%
for 2017.
Production from Pakistan and Mauritania averaged 7.9 kboepd for
the year, 6% over budget. The decrease compared to the prior year
reflects natural decline in all of the fields.
Production in 2017 from Premier's existing producing assets is
expected to be around 75 kboepd, before any contribution from the
Catcher field and adjusted for revised lower Solan production. The
increase in production from Premier's existing producing assets
reflects a full year contribution from the ex-E.ON portfolio and
the Solan field partially offset by natural decline in the Group's
Pakistan fields and in certain of Premier's UK fields. The extent
of the contribution to 2017 production from Catcher is dependent
upon the timing of first oil.
Development and pre-development projects
In the UK, the Premier-operated Catcher project continues to
target oil production start-up later this year. Total capex is now
forecast at $1.6 billion, 29% lower than the sanctioned estimate.
Eight development wells have now been completed and all have come
in at or better than prognosis in terms of reservoir quality and
deliverability. Most recently, the second well on the Varadero
template (VP3) was completed in December and, while constrained by
surface equipment on the rig, achieved 8 kbopd on clean up. Due to
these strong well results and well placement optimisation, the well
count required to deliver the base plan has reduced to 20 wells,
thus delivering further significant reductions to the forecast
development cost.
2016 saw the completion of the installation of all of the
Catcher subsea equipment. Only short subsea campaigns, commencing
in June, will be required in 2017 to tie-in the new wells drilled
and to support the hook up of the FPSO. The last of the topside
modules was successfully lifted onto the FPSO in November and good
progress has been made on the integration of the topsides and
turret and with the early stages of yard-based pre-commissioning.
Consequently, the focus is now on final mechanical completion and,
in parallel, the pre-commissioning work scopes. The sail-away date
of the FPSO from Singapore is expected to be around mid-year.
Elsewhere in the UK the Tolmount project will provide the next
phase of growth for Premier benefitting from a higher gas price
than the E.ON acquisition case. The development concept for the
field is at an advanced stage, comprising a standalone NUI platform
and a new gas export pipeline to shore, and will be subject to a
formal approval process in Q1 2017. FEED contracts for the project
are expected to be awarded during the first quarter with a FEED
programme commencing immediately thereafter.
In Indonesia, a final investment decision on the development of
the Bison, Iguana and Gajah Puteri gas fields, which will support
Premier's existing long term contracts into Singapore, is expected
later this quarter. Elsewhere in Indonesia, significant progress
has been made towards securing a three-year extension to Premier's
Tuna exploration licence and formal approval of this is expected
imminently.
In the Falkland Islands, FEED for the Premier-operated Sea Lion
project progressed well during 2016. Throughout 2016 Premier worked
closely with its FEED contractors and also with candidate well
services and logistics contractors to optimise the facilities
design and installation methodology. As a result of this work, the
estimated breakeven price of the project was reduced to $45/bbl
compared to $55/bbl at the end of 2015. The focus is now on
progressing the commercial and fiscal work streams and securing a
financing solution for the development to allow the project to move
towards sanction.
Exploration and appraisal
The Ravenspurn North Deep well (Premier carried 5% interest) in
the Southern North Sea spudded on 2 December. The well is testing
the potential of a deep, Carboniferous age, horizon underlying the
Ravenspurn North field; if successful, it could provide material
follow-on opportunities for Premier within its Southern Gas Basin
portfolio, in addition to helping to prolong the life of the
Ravenspurn area fields.
In Mexico, having been carried through to the end of 2016,
Premier exercised its option to increase its equity interest in
Block 7 to 25% on the 22 December 2016, subject to CNH approval.
The recently reprocessed seismic data covering Block 7 confirmed
the robustness of the Zama prospect, a three-way dip structure
sealed against a salt feature. Encouragement was provided by a flat
spot seismic feature resulting in this prospect being classified as
low risk. The P90-P10 gross unrisked resource range of the overall
Zama structure is estimated at 100-500 mmboe (in line with released
CNH estimates). The JV partners plan to spud the Zama prospect in
Q2 2017 with initial results expected within 50 days of
spudding.
Premier continues to actively manage its exploration portfolio
with 16 licences relinquished or sold during 2016. A further 11
licences are scheduled for relinquishment subject to government
approvals. In particular, Premier exited its 35% interest in Block
FZA-M-90 in the Foz do Amazonas Basin in December (subject to ANP
approval) enabling the Group to focus its Brazilian exploration
efforts on its core area position in the Ceará basin.
Portfolio management
As previously announced, Premier reopened the process for the
sale of its Pakistan business to a limited group of buyers with an
offer deadline for later this month and a new effective date of 1
January 2017.
Premier is also seeking offers for its 30% interest in the
Esmond Transportation System (ETS) which it acquired through its
acquisition of E.ON's UK North Sea assets. Indicative offers have
been received from interested parties with the process expected to
conclude during 2017 1H.
Following unsolicited offers of interest from a number of
parties, Premier has also instigated a process to identify possible
investors for a 20% interest in its currently operated 50% Tolmount
project.
Finance
Total revenues for 2016 will be of the order of $980 million
(2015: $1.1 billion) with higher production partially offsetting
the effect of lower realised commodity prices.
The estimated average oil price realised for 2016 was $43.1/bbl
(2015: $52.6/bbl) (pre-hedge) and $51.0/bbl (2015: $79.0/bbl)
(post-hedge) compared with an average Brent crude price of
$43.7/bbl (2015: $52.4/bbl).
Estimated average gas prices for Premier's principal gas
producing areas for 2016 were:
Realised gas prices 2016 (pre-hedge) 2016 (post-hedge)
-------------------- ----------------- ------------------
UK 35.5p/therm 40.2p/therm
-------------------- ----------------- ------------------
Indonesia $7.5/mcf (2015: $8.3/mcf (2015:
$8.0/mcf) $9.4/mcf)
-------------------- ----------------- ------------------
Pakistan $2.8/mcf (2015: $2.8/mcf (2015:
$3.9/mcf) $3.9/mcf)
-------------------- ----------------- ------------------
Premier has currently hedged 33% of its 2017 oil entitlement
production through a mixture of swaps, options and fixed price term
sales. Specifically, 12% of Premier's 2017 oil production is
covered by options with a floor price of $50.7/bbl and 21% of
Premier's 2017 oil production has been hedged through swaps and
fixed price term sales at an average price of $50.8/bbl. To date,
the Group has also hedged around 40% of its 2017 UK gas entitlement
production through fixed price term sales at an average price of
50p/therm.
As a result of the weaker sterling exchange rate and continued
cost savings across the business, 2016 full year operating costs
are estimated to have been $15.7/boe, 11% below budget. In 2017, it
is anticipated that these levels of operating costs per barrel can
be maintained. In November, Premier in its capacity as operator of
Block 12W in Vietnam signed a revised FPSO charter party agreement
securing a reduction in the Chim Sáo FPSO lease rate effective from
1 November 2015 and an extension to the firm charter period.
Completion was achieved on 19 December 2016.
Development, exploration and abandonment spend for the full year
2016 was around $690 million, below previous guidance of $730
million as a result of the weaker sterling exchange rate, continued
savings secured on the Catcher project and some deferrals of
discretionary spend into 2017. 2017 development, exploration and
abandonment spend is expected to be $350 million (including
deferrals from 2016), of which $130 million relates to the Catcher
development, $50 million to exploration and $50 million to
abandonment costs. The abandonment spend principally relates to the
Chinguetti field in Mauritania which is expected to cease
production in Q2 2017 and the Caister field in the Southern North
Sea.
2016 payments into escrow in relation to future decommissioning
was in the order of $60 million, as previously guided, and includes
a $53 million catch up payment into escrow for future
decommissioning of Chim Sáo. A $15 million payment into escrow is
forecast for 2017 in relation to future decommissioning of the Chim
Sáo and Natuna Sea Block A fields.
Premier continues to benefit from its substantial UK corporation
tax loss and allowance position with estimated losses and
allowances of $4 billion carried forward at 31 December 2016. Cash
taxes are expected to be of the order of $60 million across the
Group.
Net debt was $2.8 billion, with cash and undrawn facilities of
around $600 million at 31 December. Going forward, Premier expects
to be cash flow positive after capex at oil prices above $50/bbl,
driving debt reduction.
2017 Board Changes
As already announced, following the completion of the external
auditor tender process in Q4 2016 and after serving nine years as a
non-executive member of the Board, David Lindsell will retire at
the next AGM in May. Iain Macdonald, who joined the Board in May
2016 will assume David Lindsell's role as Chairman of the Audit and
Risk Committee.
In accordance with Premier's existing succession planning and
current Corporate Governance guidelines, Joe Darby, Senior
Independent Director, who will complete 10 years as a Board member
during 2017 has indicated that he will step down from the Board at
the upcoming AGM in May.
In addition, Mike Welton, Chairman, has indicated to the Board
that he will step down as Chairman - after serving eight years in
the role - on completion of the current refinancing programme and
identification of a suitable replacement. Recruitment processes for
a new Senior Independent Director and Chairman are underway.
Forward Looking Statements
Certain statements in this announcement are forward looking
statements. These forward looking statements can be identified by
the use of forward looking terminology including the terms
"believes", "expects", "estimates", "anticipates", "intends",
"may", "will" or "should" or in each case, their negative, or other
variations or comparable terminology. These forward looking
statements reflect Premier's current expectations concerning future
events. They involve various risks, uncertainties and other factors
which may cause the actual results, performance or achievements of
the Group, third parties or the industry to be materially different
from any future results, performance or achievements expressed or
implied by such forward looking statements. Such risks,
uncertainties and other factors include, amongst other things,
general economic and business conditions, industry trends,
competition, changes in regulation, currency fluctuations, the
Group's ability to recover its reserves or develop new reserves and
to implement expansion plans and achieve cost reductions and
efficiency measures, changes in business strategy or development
and political and economic uncertainty. There can be no assurance
that the results and events contemplated by these forward looking
statements will in fact occur.
This information is provided by RNS
The company news service from the London Stock Exchange
END
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