TIDMPMO
RNS Number : 7538F
Premier Oil PLC
17 July 2019
Premier Oil plc
("Premier" or "the Group")
Trading and Operations Update
17 July 2019
Premier is pleased to provide an update on recent operational
activities and guidance in respect of its half year financial
results to 30 June 2019.
2019 1H highlights
-- 2019 1H production averaged 84.1 kboepd, up 11 per cent on the 2018 corresponding period
-- On track to meet previously increased full year production guidance of 75-80 kboepd
-- Free cash flow generation of $180m during the period, reducing net debt to $2.15 bn
-- Significant resource upgrade at Zama (Mexico) to 670-810-970 mmboe (P90-P50-P10) (gross)
-- Tolmount, Premier's next UK growth project, on schedule for first gas end 2020
-- Tolmount East appraisal well spud imminent, targeting an additional 220 Bcf (gross)
-- Increased Andaman Sea acreage position; significant area potential
-- Forecast 2019 opex (ex-lease costs) reduced to $12/boe; capex guidance unchanged ($340m)
-- Continue to forecast full year 2019 net debt reduction of over $300m
Tony Durrant, Chief Executive, commented
"We have delivered a strong first half. I am particularly
pleased with the continued high operating efficiency from our
producing portfolio which has enabled us to reduce our debt by $180
million. This puts us in good stead to meet our debt reduction
target for the full year, which remains a top priority for the
Group. In addition, we have retained significant optionality with
our future developments and an extremely attractive exploration
portfolio which together offer substantial upside exposure."
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
Group production averaged 84.1 kboepd for the first six months
of 2019, ahead of budget and underpinned by very high operating
efficiency. Premier is on track to meet its previously upgraded
full year production guidance of 75-80 kboepd.
Premier's UK assets contributed 57.7 kboepd during the period, a
40 per cent increase on the first half of 2018. This was driven by
an increased contribution from the Premier-operated Catcher Area
which averaged 34.8 kboepd (net, Premier 50 per cent) and achieved
99 per cent operating efficiency.
The Total-operated Elgin Franklin and Premier-operated
Huntington fields continue to produce ahead of expectations,
averaging 6.5 kboepd (net, Premier 5.2 per cent) and 6.7 kboepd
(Premier 100 per cent) respectively during the period. The Solan
field also performed well averaging 4.0 kbopd (Premier 100 per
cent) during the first half of the year. A new Solan production
well (P3) is planned for spring 2020. Premier has reached agreement
with Baker Hughes, a GE company, to align payment with milestone
dates, reducing Premier's cash outlay prior to the completion of
the well.
The Premier-operated Chim Sao field in Vietnam delivered 12.4
kboepd (net, Premier 53.13 per cent), ahead of budget and supported
by the completion of two successful well intervention programmes.
Chim Sao cargoes remain well bid with an average premium to Brent
of more than $4/bbl achieved over the period.
In Indonesia, Natuna Sea Block A averaged 11.5 kboepd (net,
Premier 28.7 per cent), lower than the prior corresponding period
in 2018 due to low offtake under the second gas sales agreement
(GSA2) as cheaper LNG gas was substituted for Natuna Sea pipeline
gas. Premier expects higher GSA2 production in the second half of
the year as Singapore customers look to meet their annual take or
pay obligations. Deliveries under GSA1, the principal gas contract,
were above take or pay levels with Natuna Sea Block A capturing a
52 per cent market share of GSA1.
Development activity
Premier continues to expect first gas from the Bison, Iguana and
Gajah Puteri fields in Indonesia by year-end. The first two of the
three development wells, SBS-1 (Bison) and SIG-1 (Iguana), were
completed and successfully flow tested. SBS-1 achieved a rate of 23
mmscfd, ahead of pre-drill expectations of 15 mmscfd, due to
thicker sand development and better reservoir properties
encountered in the main Middle Arang interval. Additional
productive sands were also encountered in the Upper Arang interval
which will be completed at a later date. SIG-1 flowed at a rate of
20 mmscfd, in line with expectations.
Formal approval for the two Catcher satellite oil fields,
Catcher North and Laverda, is expected next month. Catcher North
and Laverda, together with the Varadero infill well (V5) which is
scheduled to spud in the second quarter of 2020, will help maintain
Catcher Area production at 66 kbopd (gross).
The Premier-operated Tolmount development remains on schedule
and budget. In Italy, Rosetti are erecting the steel frame of the
topsides and the construction of the jacket is well advanced. In
the UK, fabrication of the pipeline to shore is expected to
commence shortly while engineering and procurement for the
Easington terminal modifications are underway with civil works
having commenced at site.
A comprehensive set of independent expert reports on the Sea
Lion project in the North Falklands Basin has now been completed.
These, together with the Preliminary Information Memorandum, will
form the basis of a loan application package which Premier plans to
submit imminently to export credit agencies for the senior debt
component of the project financing structure.
The Block 7 appraisal programme in Mexico proved better than
expected reservoir properties and, together with the progress made
on development engineering, has resulted in a significant upgrade
to the gross resource estimate of the Zama structure to 670-810-970
mmboe (P90-P50-P10). The joint venture focus is on concluding the
unitisation discussions with Pemex and on agreeing the optimal
development for the field ahead of final investment decision
scheduled for 2020.
Exploration and appraisal
In the UK Southern North Sea, drilling of the Tolmount East
appraisal well, which has the potential to add significantly to the
Tolmount resource, will commence shortly. Data from the Greater
Tolmount Area 3D seismic survey, which completed in April, is being
processed to define additional prospectivity in the area, such as
Tolmount Far East.
In Mexico, the 3D seismic survey acquisition across Block 30
(Premier 30 per cent) was completed in July. The data will be
processed to delineate the full extent of the Wahoo prospect, which
exhibits analogous direct hydrocarbon indicators (DHIs) to the Zama
discovery, in preparation for 2020 drilling, as well as to mature
other prospectivity on the Block, including the Cabrilla prospect.
Elsewhere in Mexico, Premier's exploration plan for its Burgos
Blocks 11 and 13 (Premier 100 per cent) were approved by CNH.
Reprocessing of 3D seismic will be completed ahead of a drilling
decision.
In Brazil, Premier is actively engaging rig contractors with
available units in country for a rig to drill its Berimbau/Maraca
prospect on Block 717 (Premier 50 per cent) in 2020.
Post period-end, Premier farmed in for a 20 per cent interest in
the South Andaman and Andaman I blocks, offshore Aceh in Indonesia.
Completion of the transaction is subject to government approvals.
The blocks are located within the South Andaman Sea gas play
fairway directly adjacent to Premier's existing Andaman II acreage.
This expands Premier's collaboration with Mubadala Petroleum, who
are the operator of the South Andaman and Andaman I blocks and also
the Group's joint venture partner in Andaman II, which Premier
operates. A 3D seismic acquisition programme across the Andaman I,
Andaman II and South Andaman licences was completed earlier this
year and will be used to mature the prospect inventory identified
on the earlier 2D data.
Finance
Premier has hedged 43 per cent of its second half 2019 oil
entitlement volumes at $69/bbl and 14 per cent of its 2020 oil
entitlement volumes at $66/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.
Operating costs and lease costs to the end of June averaged
$10.4/boe and $6.3/boe respectively, reflecting strong production
and continued tight cost control across the Group. As a result,
Premier now forecasts full year operating costs of $12/boe, reduced
from $13/boe. Full year guidance of $7/boe lease costs is
maintained. Guidance for 2019 full year development, exploration
and abandonment spend remains unchanged at $340 million.
Net debt reduced from $2.33 billion at the end of 2018 to $2.15
billion at the end of June as a result of free cash flow generation
of $180 million, ahead of budget due to strong production.
Premier's covenant leverage ratio (covenant net debt/EBITDA) at the
end of June was 2.4x, down from 3.1x at the end of 2018. At current
oil prices, Premier forecasts 2019 full year net debt reduction in
the upper half of $250m to $350m guidance and continues to expect a
year-end 2019 covenant leverage ratio (covenant net debt/EBITDA) of
less than 2.3x.
Group production breakdown
2019 1H 2018 1H
UK 57.7 41.1
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Vietnam 12.4 16.2
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Indonesia 11.5 13.5
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Pakistan(1) 2.5 5.3
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Total 84.1 76.1
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(1) sold at 26 March 2019
Hedging schedules
Oil
Swaps/forward 2019 2H 2020
Volume (mmbbls) 3.99 2.21
-------- -----
% of forecast entitlement
production 43 14
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Average price ($/bbl) 69 66
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Indonesia gas
Swaps/forward 2019 2H 2020
Volume (HSFO k te) 102 252
-------- -----
% of forecast production 40 39
-------- -----
Average price ($/te) 381 361
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UK gas
Swaps/forward 2019 2H 2020
Volume (million therms) 16 42
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% of forecast production 16 22
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Average price (p/therm) 62 51
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END
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