TIDMPMO
RNS Number : 0511F
Premier Oil PLC
12 November 2020
Premier Oil plc
"Premier" or the "Company" or the "Group"
Trading and Operational Update
12 November 2020
Premier today provides a Trading and Operations Update for the
10 months to 31 October 2020.
Highlights
-- Proposed merger with Chrysaor announced, creating the largest
London listed independent oil and gas company with a strong balance
sheet and significant international growth opportunities
- Combined production to the end of October of 237.5 kboepd
- Creditor support received. Transaction completion expected by end Q1 2021
-- Premier's production averaged 62.5 kboepd for the 10 month
period. Full year production guidance is revised to 61-64 kboepd to
take into account recent constraints at Catcher
-- Solan P3 brought on-stream in September as planned,
production capacity of more than 10 kbopd from the field in the
near term
-- Tolmount: platform installed and drilling of the four
development wells commenced. First gas forecast for Q2 2021, adding
20-25 kboepd (net) once at plateau
-- Significant growth optionality maintained:
- Zama (Mexico) unitisation and development plan negotiations progressing with Pemex
- Tuna (Indonesia) farm-out agreement signed with Zarubezhneft
in September. Fully-carried two well appraisal programme planned
for 2021
- Highly encouraging results from new 3D data sets in Mexico and Indonesia
-- Forecast 2020 opex (ex-lease costs) unchanged at $12/boe and
full year capex guidance now $325 million, reflecting full year
savings and deferrals of c. $255 million
-- Net debt of $2.05 billion, as at end of October. Financial
covenants waived through to completion of the Transaction
Tony Durrant, Chief Executive, commented:
"The merger with Chrysaor, which will create a Combined Group
with diversity, scale and balance sheet strength, is progressing to
plan. We now have creditor approval and we expect to publish the
prospectus in December, with completion on track for the first
quarter of 2021."
Enquiries
Premier Oil plc Tel: 020 7824 1116
Tony Durrant (CEO)
Richard Rose (Finance Director)
Camarco Tel: 020 37575 4983
Billy Clegg, Georgia Edmonds
Notes to Editors
Terms defined in the announcement of 6 October shall have the
same meaning in this announcement.
Production operations
Group production averaged 62.5 kboepd to the end of October.
Summer maintenance programmes were safely completed. The additional
logistical complexity introduced by COVID-19 continues to be
successfully managed.
Premier's operated Catcher Area, the Group's largest producer,
averaged 26.5 kboepd (net, Premier operated 50 per cent) to the end
of October. The August shutdown was completed successfully and
plateau production was re-established in September, with the
Varadero infill well (VP1) now also online. However, in late
September, production was constrained due to the produced water
plant being offline while a build-up of calcium naphthenate was
removed. This work took longer than originally envisaged and the
produced water plant was reinstated in early November.
On 9(th) November, there was a fire in the electrical equipment
(HVAC switchboard) in the main store room on board the FPSO which
was swiftly and safely extinguished. No personnel were injured. The
facilities were made safe and production shut in. BWO, the operator
of the Catcher FPSO, is working to reinstate the HVAC which would
enable production to restart within the next week.
The third producer (P3) at Solan was successfully brought
on-stream on 15 September. The well free-flowed at rates of up to
9.5 kbopd, demonstrating the successful targeting and delivery of
the reservoir by the subsurface and drilling teams. Production was
choked back from these levels to minimise excess flaring while the
fuel gas and power system are recommissioned. Production from the
P3 well, with the ESP online, is expected to reach rates in excess
of 10 kbopd (Premier 100 per cent).
The Elgin Franklin Area produced 6.8 kboepd (net, Premier 5.2
per cent), which was ahead of budget. Production continues to be
supported by high operating efficiency and an active rig programme
with the F13 well brought on-stream in October.
As previously announced, Premier, together with its joint
venture partners decided to cease production from certain mature UK
fields not generating positive cash flows in the current
environment. At Huntington, which ceased production in April, the
first phase of the decommissioning programme was substantially
completed with the sailaway of the FPSO and recovery of the riser
systems. The second phase, which will entail recovery of the subsea
equipment and remaining mooring system, is scheduled for 2022.
Final production from the operated Balmoral Area, which surpassed
two years without a lost time injury in September, is planned for
November 2020 with sailaway of the FPV scheduled for Q2 next
year.
Production from Premier's operated Natuna Sea Block A fields in
Indonesia averaged 12.2 kboepd (net, Premier 28.67 per cent
interest), in line with budget. Singapore demand for Premier's
Indonesian gas was stable for the period, averaging around take or
pay levels under Premier's gas sales contracts, GSA1 and GSA2.
Natuna Sea Block A captured a 55.8 per cent market share of GSA 1,
materially above its contractual share of 52.5 per cent. Government
and joint venture approvals have been received for the planned 2021
infill drilling campaign to help maintain deliverability from
Natuna Sea Block A.
In Vietnam, Premier's operated Chim Sao field produced 8.7
kboepd (net, Premier 53.125 per cent interest), benefitting from
high uptime of over 90 per cent and four well intervention
campaigns, with the final campaign being completed in October. In
addition, Premier is in the process of securing the necessary
regulatory approvals for a two well infill programme in 2022.
Demand for Chim Sao crude remains robust with cargoes sold during
the period realising an average premium to Brent in excess of
$4/bbl.
Development
The 500 BCF (gross) Tolmount development (Premier-operated, 50
per cent interest) remains on track for first gas in Q2 2021. The
platform, which left the yard in Italy in September, was
successfully installed over the Tolmount field in the UK Southern
Gas basin during October. A shallow gas survey pilot hole has been
successfully completed and the first of the four firm development
wells was spudded by the Valaris 123 rig on 10(th) November. The
Tolmount field is expected to add 20-25 kboepd (net, Premier 50 per
cent) to Group production once at plateau rates.
On the proposed Tolmount East development, Premier is now in
final negotiations with its selected contractors ahead of making a
final investment decision on the project. Once on-stream, Tolmount
East will help extend plateau production from the Tolmount Area. In
addition, in September, Premier was awarded two licences directly
adjacent to its Tolmount Field Development Area and is in the
process of maturing a number of leads and prospects which, in the
success case, could be developed via the Tolmount
infrastructure.
In Mexico, negotiations between the Block 7 partners and PEMEX
regarding the Zama field development plan and the unitisation of
the Zama field are progressing and are expected to conclude in Q1
2021. FEED on the Zama project scheme (two platforms plus FSO) is
reaching a conclusion and pending progress on the unitisation and
other approvals a final investment decision would be made later in
2021.
In the Falkland Islands, the 250 mmbbl Sea Lion Phase 1 project
is currently on hold. In the meantime, Premier continues to work
with the Falkland Islands Government (FIG) on licensing, fiscal and
regulatory matters. The proposed farm-out of the Sea Lion licences
to Navitas is subject to FIG and, pursuant to the Merger Agreement,
Chrysaor's approval.
Exploration and appraisal
In Indonesia, the farm out agreement with Zarubezhneft for a 50
per cent interest in the Tuna discoveries was signed in September.
Premier and Zarubezhneft are now in the process of securing
Indonesian government approval for the farm out agreement and a one
year extension to the Tuna PSC to March 2022. Zarubezhneft will
carry Premier for its share of a two well appraisal programme
targeted for mid-2021 with the rig procurement process
well-advanced.
Premier continues to mature its highly prospective portfolio of
opportunities on the new 3D data sets in Mexico and the Andaman
Sea, Indonesia, ahead of drilling campaigns targeted for 2022.
Premier also plans to drill the stacked Berimbau/Maraca prospect on
its operated Block 717 (Premier 50 per cent interest) in Brazil in
2022.
Finance
Premier's operating costs and lease costs averaged $12/boe and
$7/boe respectively for the first 10 months of the year. The Group
continues to forecast $110 million of opex savings for the full
year.
Premier now forecasts 2020 full year total capex, including
abandonment expenditure, of $325 million, compared to previous
guidance of $340 million, reflecting total capex savings and
deferrals of $145 million.
Net debt as at the end of October was $2.05 billion (30 June
2020: $1.97 billion). The cash outflow during the third quarter
reflects the impact of the summer maintenance period together with
constrained production at Catcher. As previously announced, the
Group's financial covenants have been waived through to completion
of the Transaction, which is expected by the end of Q1 2021.
Board and management changes
As previously announced Tony Durrant will step down as Chief
Executive by the end of the year. Richard Rose will be the interim
Chief Executive until completion of the Transaction, in addition to
his current role as Finance Director. Stuart Wheaton, currently
Chief Operating Officer, will assume the role of interim Deputy
Chief Executive.
Proposed merger with Chrysaor
In October, Premier announced the proposed merger of Premier and
Chrysaor Holdings Limited and the reorganisation of Premier's
existing financing arrangements. Premier has subsequently received
the requisite level of support from each class of its creditors for
the Transaction. As a result, the merger agreement between Premier,
Harbour, funds managed by EIG and Chrysaor was released from escrow
on 2(nd) November.
Premier plans to publish a prospectus, which will include an
independent valuation of Chrysaor's 2P reserves, and a shareholder
circular by the end of the year. The shareholder circular will
include details of the shareholder meeting to approve the
Transaction, which is anticipated to take place in January.
Premier will launch the Court-approved restructuring plan
processes, to implement the repayment and cancellation of its
existing debt, through the issuance of a practice statement letter,
immediately after the Prospectus for the Transaction is
published.
The Transaction is expected to complete by the end of Q1
2021.
Chrysaor update
The following information has been provided by Chrysaor for the
period to the end of October.
Chrysaor's production averaged 175 kboepd to the end of October.
This was split 84 kboepd from liquids and 91 kboepd from gas;
operated assets 103 kboepd and non-operated assets 72 kboepd.
Chrysaor's full-year forecast remains unchanged and in the range of
170-180 kboepd, with reduced levels of drilling and rephrasing of
operational activities offset by a shortening of planned
shutdowns.
Chrysaor's operated drilling programme, which had been suspended
in March, resumed in September with the Valaris 120 heavy duty jack
up over the Jasmine wellhead platform to drill the Joanne Chalk S16
well. This well has been successfully drilled to depth and
completion operations continue with first production expected
before the year end. The Transocean Paul B Lloyd Jnr also commenced
drilling operations in September and has successfully drilled the
Greater Britannia Area - Callanish F5 well to depth. First
production from this well is expected in Q1 2021.
Operating costs (including net tariff costs) for the period were
$11.5/boe, below Chrysaor's benchmark of $15/boe. Chrysaor's total
capex (including abandonment expenditure) to the end of October was
$605 million. Chrysaor currently expects capital, decommissioning
and operating expenditure for 2020 to be around $600 million lower
than forecast at the outset of the year, reflecting continued cost
control, the pause in non-essential platform activity and the
suspension of operated drilling activities for nearly six
months.
Chrysaor benefits from a significant hedge programme with c. 85
per cent of its Q4 2020 oil production hedged at $62/bbl and c.44
per cent of its Q4 2020 gas production at 49 pence/therm. In
addition, Chrysaor has hedged approximately 67 per cent of its 2021
1H oil volumes at an average price of $60/bbl and 73 per cent of
its 2021 1H gas volumes at an average price of 42 pence/therm.
Additional information on Chrysaor can be found at
www.chrysaor.com.
Appendix
Premier Group production breakdown
kboepd 1 January - 31 October 1 January - 31 October
2020 2019
Indonesia 12.2 11.0
----------------------- -----------------------
Pakistan(1) - 1.4
----------------------- -----------------------
UK 41.6 55.3
----------------------- -----------------------
Vietnam 8.7 11.7
----------------------- -----------------------
Total 62.5 79.4
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(1) Sold as at 26 March 2019
The information contained within this announcement is deemed by
Premier to constitute inside information as stipulated under the
Market Abuse Regulation. By the publication of this announcement
via a Regulatory Information Service, this inside information is
now considered to be in the public domain. The person responsible
for arranging for the release of this announcement on behalf of
Premier is Andy Gibb (Group General Counsel).
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