TIDMPMO
RNS Number : 3447T
Premier Oil PLC
14 November 2019
Premier Oil plc
("Premier" or "the Group")
Trading and Operations Update
14 November 2019
Premier today provides a Trading and Operations Update for the
10 months to 31 October 2019.
Highlights
-- Group production averaged 79.4 kboepd for the period with
high operating efficiency of 94%; forecast full year production at
upper end of 75-80 kboepd guidance
-- Catcher Area rates of 69 kboepd (gross) and very high
operating efficiency of almost 100% maintained; project cash
payback reached, 22 months after first oil
-- Near field projects on track: BIG-P (Indonesia) on track for
first gas by year-end; formal approval of Catcher Area satellites
received with first oil targeted for early 2021
-- Tolmount, Premier's next UK growth project, on schedule for
first gas by the end of 2020 adding a net 20-25 kboepd to Group
production once on plateau
-- Significant commercial discovery at Tolmount East (UK);
development planning already well advanced with project sanction
targeted for 2020 2H
-- Rig contracted to appraise the Malguk-1 discovery (Alaska
North Slope); targeting more than 1 bn bbls (gross) of STOIIP,
expected spud February 2020
-- Significant industry interest in Premier's Block 7 Zama
(Mexico) sales process; bid deadline extended into December to
accommodate levels of interest
-- Forecast 2019 opex (ex-lease costs) unchanged at $12/boe;
full year capex guidance reduced to between $300m and $320m from
$340m
-- Net debt reduced by $300m to $2.03bn as at 31 October;
underpinning full year net debt reduction guidance in excess of
$300m
Tony Durrant, Chief Executive, commented:
"We continue to deliver on our strategic priorities. We are
generating significant free cash flow, which is materially
deleveraging our balance sheet. At the same time, we are actively
managing our portfolio and selectively progressing growth projects
at the right exposure. We also continue to create value through the
drill bit and to build material new positions in emerging
exploration plays at low cost."
Enquiries
Premier Oil plc Tel: 020 7730 1111
Tony Durrant, Chief Executive
Richard Rose, Finance Director
Camarco Tel: 020 3757 4983
Billy Clegg
James Crothers
Production operations
Production averaged 79.4 kboepd for the period, underpinned by
continued high Group operating efficiency of 94 per cent. Summer
maintenance programmes were successfully completed and production
has returned to previous levels; October production averaged 78.4
kboepd. Premier expects full-year production to be at the upper end
of the 75-80 kboepd guidance range.
Premier's UK assets averaged 55.3 kboepd, a 27 per cent increase
on the prior corresponding period driven by a full contribution
from the Catcher Area at higher plateau rates. The Catcher Area
averaged 34.5 kboepd (net, Premier 50 per cent), achieving an
extraordinary operating efficiency of almost 100 per cent. This
continued outperformance resulted in the Group achieving cash
payback on the Catcher Area project at the end of October, 22
months after first oil.
The Elgin Franklin Area produced 6 kboepd (net, Premier 5.2 per
cent interest), ahead of expectations and supported by on-going
well intervention campaigns. Production from the Huntington field
averaged 6 kboepd (Premier 100 per cent interest), with a four week
scheduled maintenance programme successfully completed at the end
of August. Premier is in discussions with the Huntington FPSO
provider about options to extend economic production again to
beyond April 2020. Premier's operated Solan field delivered 3.6
kboepd (Premier 100 per cent interest) and preparations are well
advanced for the 2020 Solan P3 drilling campaign. Premier's other
UK assets have performed in line with expectations.
In Asia, Premier's operated Chim Sao field averaged 11.7 kboepd
(net, Premier 53.13 per cent), ahead of budget with natural decline
from the existing wells mitigated by four well intervention
campaigns during the period. Preparations are underway for a 2021
two well infill drilling programme aimed at maximizing recovery
from the Chim Sao field. Chim Sao cargoes remain well bid with an
average premium to Brent of more than $4.40/bbl achieved for
cargoes lifted over the period.
Premier's Indonesian gas fields delivered 11 kboepd (net,
Premier 28.67 per cent), with offtake under the two gas sales
agreements at or around annual take or pay levels. In October,
Premier successfully drilled and completed an infill well on the
Gajah Baru field targeting incremental reserves from the Middle
Arang Ca-3 sand. The well is expected to be tied into production
before year-end.
Development activities
The Premier operated 500 Bcf Tolmount development remains on
schedule and is tracking below budget. Construction of the platform
is progressing to plan: electrical fit-out of the topsides has
commenced and roll-up of the jacket frames is scheduled for early
December. Onshore linepipe fabrication is completed while shaft
construction at the terminal and landfall earthworks have
commenced. Development drilling is on track to start mid-2020. The
Group continues to expect first gas by the end of 2020 with plateau
rates of around 50 kboepd (gross, Premier 50 per cent).
In October, Premier announced a significant commercial discovery
at Tolmount East. The well, which targeted 220 Bcf of P50 gross
resource four kilometres east of Tolmount, penetrated 241 feet of
gas bearing high quality Leman sands with a net-to-gross ratio of
71 per cent. The well data is being integrated with the new 3D
seismic dataset as part of the fast-track development planning with
project sanction targeted for the second half of 2020.
Premier continues to forecast first gas from its operated Bison,
Iguana and Gajah Puteri (BIG-P) fields in Indonesia by year-end.
The three well development drilling programme, which completed in
September, yielded positive results and encountered incremental
reserves in excess of pre-drill estimates. Installation of the
subsea structures and flexible risers was completed in October and
the attachment of the umbilicals is underway, ahead of final hook
up and tie-in of the wells.
The two Catcher Area satellite developments, Catcher North and
Laverda, were formally approved in September. The Gorrilla V1 rig
will drill the two development wells mid-2020 immediately after a
Varadero infill well. First oil from Catcher North and Laverda is
targeted for early 2021 and, together with the Varadero infill
well, will extend plateau oil production across the Catcher
FPSO.
Premier's applications for senior debt financing in relation to
its operated Sea Lion development in the North Falkland Basin
continue to progress through the export credit agencies' due
diligence processes. Discussions also continue with several
interested parties about farming into the project. In November,
Premier received approval of an extension to the PL032 Discovery
Area licence term to 1 May 2021 from the Falkland Islands
Government.
In August, Premier commenced a formal sales process for its
interest in the fully-appraised Zama oil field offshore Mexico.
There has been significant industry interest in the process and, as
a result, Premier has extended the bid deadline to December to
accommodate this.
Exploration and appraisal
In Alaska, the Nordic-3 rig has been contracted to appraise the
Icewine Area A Malguk-1 discovery (Premier 60 per cent interest)
which Premier estimates could contain over 1 bn bbls of STOIIP. The
well, which will be flow tested, is expected to spud in February
2020.
Premier is in the final stages of concluding a rig contract to
drill the Berimbau/Maraca stacked prospects on its operated Block
717 in the Ceara Basin in Brazil. The well is scheduled to spud in
the third quarter of 2020 and is targeting gross unrisked resource
of 300 mmbbls.
In Mexico, Premier expects to receive the Block 30 final
processed 3D seismic dataset in the second quarter of 2020
following the acquisition of a 3D seismic survey earlier this year.
This will be used to fully delineate the prospectivity on block
ahead of drilling in 2021. Premier also expects to receive the
reprocessed 3D seismic data across Blocks 11 and 13 in the Burgos
Basin during 2020.
In Indonesia, Premier has received the fast track data from the
3D seismic acquisition programme across its Andaman Sea Blocks.
These initial processed results are highly encouraging with the
prospectivity identified on 2D seismic confirmed. Premier expects
to receive the fully processed data during the course of 2020 ahead
of a 2021 well programme.
Finance
Premier has hedged 41 per cent of its fourth quarter 2019 oil
entitlement volumes at $70/bbl and 29 per cent of its 2020 first
half oil entitlement volumes at $64/bbl. Premier has also hedged a
significant proportion of its remaining 2019 and 2020 Indonesian
and UK gas volumes. The Group's complete hedging schedule is set
out at the end of this release.
Over the period, operating costs and lease costs averaged
$12/boe and $6/boe respectively and Premier continues to forecast
full year operating costs in line with year-to-date levels.
Forecast 2019 full year development, exploration and abandonment
spend is between $300 million and $320 million, reduced from
previous guidance of $340 million, due to the release of
contingency spend related to the BIG-P drilling programme, which
has now completed, and the Tolmount project tracking below
budget.
Premier generated $300 million of free cash flow over the
period, reducing net debt from $2.33 billion at the end of 2018 to
$2.03 billion as at 31 October and underpinning full year net debt
reduction guidance in excess of $300 million. Premier continues to
forecast a year-end covenant leverage ratio of 2.3x or less against
the covenant level of 3.0x.
Group production breakdown
kboepd 1 Jan - 31 Oct 1 Jan - 31
2019 Oct 2018
Indonesia 11.0 13.4
Pakistan(1) 1.4 5.2
UK 55.3 43.5
Vietnam 11.7 15.6
--------------- -----------
Total 79.4 77.7
--------------- -----------
(1) sold at 26 March 2019
Hedging schedules
Oil
Swaps/forward Q4 2019 Q1 2020 Q2 2020
Volume (mmbbls) 2.0 1.4 1.2
-------- -------- --------
% of forecast ent. production 41 30 27
-------- -------- --------
Average price ($/bbl) 70 65 64
-------- -------- --------
Indonesia gas
Swaps/forward Q4 2019 Q1 2020 Q2 2020
Volume (HSFO k te) 51 63 63
-------- -------- --------
% of forecast production 40 46 46
-------- -------- --------
Average price ($/te) 362 385 379
-------- -------- --------
UK gas
Swaps/forward Q4 2019 Q1 2020 Q2 2020
Volume (million therms) 16.6 19.6 17.7
-------- -------- --------
% of forecast production 35 40 40
-------- -------- --------
Average price (p/therm) 64 60 52
-------- -------- --------
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END
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