TIDMPMO
RNS Number : 8493J
Premier Oil PLC
22 August 2019
Premier Oil PLC
Half-Year Results for the six months to 30 June 2019
Press Release
Tony Durrant, Chief Executive, commented:
"I am pleased to report another strong performance for Premier
where we have exceeded our financial and operational targets for
the period. The Company's strong cash flow is driving debt
reduction and the Zama divestment and Sea Lion farm-down processes
are targeting further strengthening of the balance sheet, which
remains the Group's highest priority. Premier's operated Tolmount
gas project, due on-stream next year, and the addition of good
quality exploration and appraisal acreage offer significant low
cost opportunities for future value growth."
Operational highlights
-- Production of 84.1 kboepd (2018 1H: 76.2 kboepd), a record for 1H
-- Catcher Area high plateau rates of 70 kboepd (gross) maintained, operating efficiency of 99%
-- Tolmount project on schedule and under budget
-- Zama gross resource upgraded to 810 mmboe (P50) following successful appraisal
-- Attractive acreage captured: Andaman Sea position increased,
entry into a high-impact appraisal project in Alaska
-- Climate Change Committee established; review of all operations to reduce emissions initiated
Financial highlights
-- Profit after tax of US$121 million (2018 1H: US$98 million)
-- EBITDAX of US$680 million (2018 1H: US$488 million, adjusted for impact of IFRS 16)
-- Opex of US$10/boe plus lease costs of US$6/boe
-- Cash margins 35% higher than 2018 1H
-- Free cash flow of US$182 million (2018 1H: US$90 million cash outflow)
-- Net debt reduced to US$2.15 billion (31 December 2018: US$2.33 billion)
2019 Outlook
-- Production (75-80 kboepd) and expenditure (US$12/boe opex,
US$340 million capex) guidance unchanged
-- Over 40% of 2019 2H oil production hedged at US$69/bbl
-- First gas from Bison, Iguana and Gajah-Puteri (BIG-P) gas fields expected end Q4
-- Tolmount East appraisal well results due early Q4
-- Sea Lion Phase 1: discussions with senior lenders progressing, farm down process launched
-- Formal Zama sale process initiated
-- Forecast full year net debt reduction of over US$300 million
reiterated (excluding any potential disposal proceeds)
Enquiries
Premier Oil plc Tel: 020 7730 1111
Tony Durrant, Chief Executive
Richard Rose, Finance Director
Camarco Tel: 020 3757 4980
Billy Clegg
James Crothers
A presentation to analysts will be held at 9.30am today at the
offices of Premier Oil, 23 Lower Belgrave Street, London SW1W 0NR
and will be webcast live on the Company's website at
www.premier-oil.com. A copy of this announcement is available for
download from Premier's website at www.premier-oil.com.
Overview
Premier delivered another period of record production, supported
by extremely high Group operating efficiency. Together with
improved cash margins, this resulted in strong free cash flow
delivery.
The Premier-operated Catcher Area (Premier-operated 50 per cent
interest) in the UK North Sea was the Group's highest net producer,
achieving 99 per cent operating efficiency, validating the new
build FPSO design, the delivery capacity of the existing well stock
and the operational management of the plant and the reservoir.
Following the asset's continued strong subsurface performance,
Premier currently expects to increase Catcher Area reserves as part
of the Group's formal year-end reserves assessment.
Premier's operated assets in South East Asia - Chim Sáo
(Premier-operated 53.1 per cent interest) and Natuna Sea Block A
(Premier-operated 28.67 per cent interest) - continue to generate
material free cash flow for the Group (after ongoing capital
expenditures), producing with high uptime and from a low cost base.
Output was lower than the prior corresponding period due to weaker
Singapore demand for Premier's Indonesian gas and due to some
natural decline from the Chim Sáo oil field.
Across the Group's producing assets, in both the North Sea and
South East Asia, Premier has identified numerous opportunities to
increase the reserves and field life of its producing assets
through incremental investment in infill drilling and well
intervention programmes, plant modifications, satellite
developments and near field exploration. These projects, which are
at various stages of maturity, are typically low cost with high
rates of return and a rapid payback period.
On the development side, the Tolmount gas field
(Premier-operated 50 per cent interest) is on track for first gas
at the end of 2020 and underpins the Group's medium-term UK growth
profile. There is considerable upside in the Greater Tolmount Area
including at Tolmount East which targets incremental resources of
up to 300 BCF (gross).
The conclusion of the appraisal programme at the giant Zama
field in Block 7 (Premier non-operated 25 per cent interest)
offshore Mexico resulted in Premier upgrading its resource
estimates and reaffirming Zama's status as a world-class asset.
Progress has also been made on the Group's fully appraised Sea Lion
field which, at 250 mmboe (gross) of resource in Phase 1, is a
material oilfield development opportunity. Post period end, Premier
submitted the Preliminary Information Memorandum, which forms the
basis of a loan application for the senior debt component of the
project financing structure, to export credit agencies.
The Group's immediate priority is to further strengthen its
balance sheet and this, together with significant industry
interest, has led to Premier initiating a formal sales process for
its interest in the Zama field which, if successful, will result in
a material reduction in debt levels. In addition, Premier has
launched a formal farm-down process of its 60 per cent operated
interest in Sea Lion to optimise its level of participation in the
project.
Exploration remains a key component of Premier's strategy. The
current environment has provided the opportunity to access highly
prospective acreage without compromising the Group's near term
deleveraging targets. During the period, Premier increased its
position in the emerging South Andaman Sea gas play at low upfront
cost and has also entered the North Slope of Alaska, a prolific
super basin, by farming into an appraisal project, which is
estimated to contain 1 billion barrels (gross) of discovered
conventionally reservoired oil-in-place.
The Group's strong operational performance along with continued
tight control of its cost base and capital expenditure generated
US$182 million of free cash flow during the period. This was
directed at reducing debt levels and underpins Premier's
expectation of achieving the upper half of its full year 2019 net
debt reduction guidance of US$250 million to US$350 million. The
Group also continues to reduce its covenant leverage ratio
(covenant net debt / EBITDA), which was down from 3.1x at year-end
2018 to 2.4x at the end of the period. Premier's covenant leverage
ratio is expected to continue to reduce further by year-end
2019.
Integral to Premier achieving its business objectives is being a
responsible operator and the Group adheres to the highest health,
environmental and safety standards. The first half saw Premier
establish a Climate Change Committee, initiate a review of its
operations to identify further opportunities to reduce its
emissions and align its Climate Change Policy with the Task Force
on Climate-related Financial Disclosures (TCFD) recommendations.
Premier's Greenhouse Gas (GHG) intensity was materially lower
compared to the prior corresponding period primarily due to a
higher production contribution from the Group's Catcher Area, which
has a low GHG intensity.
Looking to the remainder of 2019, the Group remains focused on
maintaining its strong and safe operating performance and
maximising its cash flows, which are protected via a robust hedging
programme, and will be prioritised towards improving further the
Group's balance sheet. In addition, Premier looks forward to the
outcome of the Tolmount East appraisal well, first gas from the
BIG-P gas fields, feedback from potential senior lenders and
farminees to its Sea Lion project, and progressing the Zama
divestment process.
OPERATIONAL REVIEW
GROUP PRODUCTION
Group production for the first half averaged 84.1 kboepd, up 10
per cent on the prior corresponding period and a record for
Premier. This reflected very high operating efficiency across the
portfolio and an increased contribution from the Premier-operated
Catcher Area. The Group is on track to meet its previously
increased full year production guidance of 75-80 kboepd.
The Group realised 35 per cent higher cash margins for the
period, compared to the prior corresponding period, despite lower
commodity prices. This was due to higher margin UK oil production
accounting for a greater proportion of the Group's output and
Premier's hedging programme which provided protection against the
fall in commodity prices.
kboepd 2019 1H 2018 1H
UK 58.1 41.3
Vietnam 12.4 16.2
Indonesia 11.1 13.4
Pakistan(1) 2.5 5.3
Total 84.1 76.2
(1) sold at 26 March 2019
UNITED KINGDOM
UK production averaged 58.1 kboepd (2018: 41.3 kboepd) and
represented almost 70 per cent of the Group's production (2018: 54
per cent) for the period. This increase resulted in a 35 per cent
rise in the Group's cash margins. First gas from Premier's operated
Tolmount field, the Group's next UK growth project, is on track for
the end of 2020. Premier continues to expect UK production to
average over 50 kboepd in the medium term.
The Greater Catcher Area
Premier's operated Catcher Area averaged 70.2 kboepd (gross,
Premier-operated 50 per cent interest) for the first half,
reflecting very high operating efficiency of 99 per cent and strong
reservoir performance. The Catcher Area is forecast to reach cash
pay back by the end of 2019, only two years after first oil,
vindicating the Group's continued investment in the project through
the oil price downturn.
Catcher Area production data continues to demonstrate good
pressure support provided by the aquifer and injector wells and
generally excellent lateral reservoir connectivity. In addition,
water cut remains at low levels. Well productivity, supported by
the better than expected permeability, remains constrained by the
FPSO design capacity and the well stock is being managed to
optimise production and ultimate oil recovery. Premier currently
expects to increase Catcher Area reserves as part of the Group's
formal year-end reserves assessment.
Future infill drilling opportunities along with satellite field
tie-backs are being pursued to improve further recovery from the
Catcher Area and to keep the FPSO operating at full oil capacity
until 2021, materially longer than anticipated at sanction. Premier
expects to receive formal approval of the development of the
Catcher North and Laverda satellite oil fields imminently.
Development drilling is expected to start in mid-2020 with first
oil targeted for early 2021.
Premier plans to drill an infill well on the Varadero field
immediately before the Catcher North and Laverda drilling programme
to target resources beyond the reach of the initial suite of
production wells. A 4D seismic survey across the Catcher Area is
scheduled for mid-2020 to help confirm additional future infill
well locations.
Other producing UK fields
Huntington production averaged 6.8 kboepd (Premier-operated 100
per cent interest), benefitting from high uptime and the newly
converted water injector which is providing good pressure support
to the whole field. In addition, productivity from the production
well H5 increased following a successful squeeze treatment in
July.
The non-operated Elgin-Franklin field averaged 6.5 kboepd (net,
Premier 5.2 per cent interest) for the first six months of the
year. This was ahead of forecast as the area benefitted from
successful remedial work on existing wells and continued high
operating efficiency. Further intervention work is planned which,
together with an ongoing infill drilling programme, is expected to
help maintain production from the area.
Production from Premier's operated Solan field averaged 4.0
kboepd (Premier-operated 100 per cent interest), slightly ahead of
forecast and driven by excellent plant operating efficiency. A new
Solan production well (P3) is planned for Spring 2020 to boost
production from the central northern part of the reservoir and to
extend field life. 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. On the
successful completion of the P3 well, excess gas will be used to
replace diesel as a fuel for power generation on the facility.
Premier's operated Balmoral Area delivered 1.5 kboepd (net,
Premier 79 per cent interest) during the period. Premier currently
anticipates cessation of production no earlier than 2021.
Production from the Perenco-operated Ravenspurn North field
averaged 1.2 kboepd (net, Premier 28.8 per cent interest), broadly
in line with expectations. Perenco plans to drill two infill wells
at Ravenspurn North commencing later this year to boost future
production from the field.
Production from the rest of Premier's UK portfolio was broadly
in line with expectations.
The Greater Tolmount Area
The development of the Premier-operated 500 BCF (gross) Tolmount
gas field (Premier 50 per cent interest) in the Southern North Sea
is on schedule and, to date, below budget.
The Tolmount field development entails four producer wells tied
into a minimal facilities platform, a new gas export pipeline to
shore and modifications to an existing onshore gas receiving
terminal at Easington. Construction of the topsides steel frame and
the jacket continues apace with sailaway of the platform from the
Rosetti yard in Italy on track for the second quarter of 2020.
A rig has been contracted to drill the Tolmount development
wells, with the first well expected to spud mid-2020. Preparations
for the pipeline shore tie-ins are expected to commence shortly
while engineering and procurement for the Easington terminal
modifications are underway with civil works having commenced at
site. Premier continues to expect first gas from the field by the
end of 2020 with initial peak production rates of 50 kboepd
(gross).
Post-period end, Premier spudded the Tolmount East appraisal
well which is targeting 220-300 BCF (P50 to P90) of gross
contingent resource. In the success case, Tolmount East will be
tied back to Tolmount to ensure the infrastructure is kept at full
capacity. Early concept work has been completed so that an
accelerated Tolmount East development could be pursued. Data from
the Greater Tolmount Area 3D seismic survey, completed in April, is
being processed to define additional prospectivity in the area,
such as Tolmount Far East, Tolmount West and Mongour.
INDONESIA
Robust production and continued low operating costs resulted in
the Indonesian Business Unit generating positive net cash flows for
the Group, after ongoing capital expenditures on the BIG-P
development. BIG-P remains on track for first gas by the end of the
year with positive drilling results achieved to date.
Production from the Premier-operated Natuna Sea Block A averaged
11.1 kboepd (net, Premier 28.67 per cent interest) (2018 1H: 12.8
kboepd) during the first half of the year.
Singapore demand for gas sold under GSA1, the Group's principal
gas sales agreement, averaged 285 BBtud (gross) (2018 1H: 269
BBtud), ahead of take-or-pay levels and driven by high offtake
early in the year when the LNG spot price was above that of GSA1.
Premier's Anoa and Pelikan fields delivered 149 BBtud (gross) (2018
1H: 144 BBtud (gross)) during the period and accounted for 52 per
cent of GSA1 deliveries (2018 1H: 53 per cent), above Natuna Sea
Block A's contractual share of 51 per cent. In May, Premier
completed a successful perforation at WL-6, one of the Anoa West
Lobe wells, adding 19 mmscfd (gross) of production delivery from
the Lower Gabus reservoir interval.
Production from Gajah Baru and Naga gas under GSA2 averaged 50
BBtud (gross) (2018 1H: 88 BBtud), a reduction on the prior
corresponding period and below take-or-pay levels as cheaper spot
LNG gas was substituted for Natuna Sea pipeline gas.
The price that Premier achieves for its Indonesian gas is linked
to the price of HSFO and, in light of IMO2020, Premier has taken
the opportunity to hedge a substantial proportion of its post-tax
2020 Indonesian gas volumes at an average equivalent price c.
US$9/BBtu.
Development
The development of the BIG-P gas fields in Natuna Sea Block A
involves a three well subsea tie-back to existing infrastructure
and is progressing to budget and schedule. Once on-stream, BIG-P
will support the Group's long-term contracts into Singapore and
help maintain production from Natuna Sea Block A.
The first two out of the three development wells, SBS-1 at Bison
and SIG-1 at Iguana, were completed and successfully flow tested.
SBS-1 achieved a rate of 23 mmscfd, ahead of pre-drill
expectations, due to thicker net sand development and better
reservoir properties encountered in the main Middle Arang interval.
Additional productive sands were also encountered in the Upper
Arang interval. These will be exploited at a later date. SIG-1
flowed at a rate of 20 mmscfd, in line with expectations. The third
well, SGP-1 at Gajah-Puteri, is currently being completed.
Onshore fabrication of the subsea structures for BIG-P has been
completed with load out imminent. The Iguana-to-Bison-to-Pelikan
and the Anoa-to-Gajah-Puteri pipelines have been successfully
installed. Installation of the subsea structures and flexible
risers will commence in September followed by installation of the
umbilicals and final hook up and tie-in of the wells.
VIETNAM
Premier's Vietnam operations delivered a robust production
performance. This, together with a continued low cost base,
generated material free cash flows for the Group.
Production from the Premier-operated Block 12W, which contains
the Chim Sáo and Dua fields, averaged 12.4 kboepd (net,
Premier-operated 53.1 per cent interest) (2018 1H: 16.2 kboepd).
The reduction on the prior period reflects natural depletion across
the existing suite of wells partially offset by skilled reservoir
management and ongoing well intervention campaigns which added
production from new zones within existing wells. Production was
also supported by sustained high operating efficiency in excess of
90 per cent. Demand for Chim Sáo oil remained strong with an
average premium to Brent of over US$4/bbl achieved during the first
six months of the year.
Three further well intervention campaigns are planned for the
remainder of 2019 and a further four are under initial planning for
2020. In addition, preparations are underway for a 2021 two well
infill drilling programme aimed at maximizing recovery from the
Chim Sáo field. These incremental investments are aimed at
extending the productive life of the Chim Sáo field.
Robust production performance, low operating costs and the
continuing premiums to the Brent oil price commanded by Chim Sáo
crude contributed to a positive net operating cash flow from the
Vietnam Business Unit during the period.
THE FALKLAND ISLANDS
During the period, Premier has continued to advance its operated
Sea Lion Phase 1 project towards a final investment decision with a
focus on progressing the project's financing structure.
The Sea Lion project is a material opportunity for the Group
with around 330 mmbbls (net to Premier) to be developed over two
phases. Sea Lion Phase 1 will develop 250 mmbbls (gross) resources
in PL032 (Premier 60 per cent operated interest), using a
conventional FPSO based scheme, similar to Premier's successful
Catcher development. The project is at a mature stage of definition
and has been substantially de-risked from a technical, cost and
schedule perspective.
Premier continues to benefit from a collaborative relationship
with its Tier 1 supply chain. Substantive optimisation and value
engineering has been achieved during the period with the key
service and supply contracts nearing final form in preparation for
their execution as the project approaches sanction decision.
The critical path to sanction remains securing the financing for
the project. Post-period end, Premier completed a Preliminary
Information Memorandum supported by a comprehensive set of
independent expert reports on the project. These form the basis of
a financing guarantee application package for the senior debt
component of the project financing which was submitted to export
credit agencies in July. The project is now in a period of lender
due diligence which will entail, among other items, finalising the
term sheets with potential senior lenders.
A formal farm-down process of Premier's 60 per cent operated
interest in Sea Lion Phase 1 has been launched through which the
Group proposes to optimise its level of participation in the
project.
EXPLORATION AND APPRAISAL
In recent years, Premier has sought to rebalance its exploration
portfolio away from traditional but now mature areas to
underexplored but proven hydrocarbon basins with the potential to
develop into new business units over the medium-term. During the
first half of the year, the Group expanded its position in the
South Andaman Sea and entered Alaska, consistent with Premier's
strategy of focusing on underexplored, emerging plays in proven
hydrocarbon provinces.
Indonesia
Post-period end, Premier farmed in for a 20 per cent interest in
the South Andaman and Andaman I blocks which are located within the
emerging South Andaman Sea gas play fairway directly adjacent to
Premier's existing Andaman II acreage. Completion of the
transaction is subject to government approvals. This expands
Premier's collaboration with Mubadala Petroleum, who are operator
of the South Andaman and Andaman I blocks and also the Group's
joint venture partner in Andaman II, which Premier operates with a
40 per cent interest.
A 3D seismic acquisition programme across the Andaman I, Andaman
II and South Andaman licences was completed during the period and
will be used once processed to mature the prospects identified on
the existing 2D data, many of which exhibited direct hydrocarbon
indicators. Drilling is targeted for early 2021. Premier's Andaman
Sea position has the potential to deliver multi-TCF of gas and adds
a potentially material gas play to Premier's Indonesia
portfolio.
Mexico
The Talos-operated Block 7 Zama appraisal campaign successfully
completed in July, on schedule and below budget, and comprised two
appraisal wells and a vertical sidetrack which was flow tested. A
comprehensive set of data was acquired and demonstrated reservoir
properties at the upper end of expectation. This resulted in
Premier increasing its gross resource estimate of the Zama
structure to 670-810-970 mmboe (P90-P50-P10).
The results from the appraisal programme are being integrated
into the pre-FEED and FEED work ahead of the optimal development
for the field being selected. In parallel, discussions have
commenced around the Zama field resource split between Block 7
(Premier 25 per cent non-operated interest) and the adjacent block
which is 100 per cent owned by Pemex. The Block 7 joint venture
partnership is aiming to agree an initial tract participation by
year-end with formal FDP submission in 2020.
The Group's highest priority is to further strengthen its
balance sheet and, given considerable industry interest in shallow
water Mexico, this has prompted Premier to initiate a formal sales
process for its interest in the Zama field. In the success case,
this will lead to a material reduction in the Group's debt levels.
Premier retains exposure to exploration upside in Mexico through
its other offshore licence interests, each of which has the
potential to deliver material future value for Premier. A 3D
seismic survey acquisition across Block 30 (Premier 30 per cent
interest) was completed in July. The data is now being processed to
delineate the full extent of the Wahoo prospect, which exhibits
direct hydrocarbon indicators analogous to Zama, as well as to
mature other prospectivity on the Block, including the Cabrilla
prospect. Drilling is targeted for end 2020. Premier's exploration
plan for its 100 per cent operated Burgos Blocks 11 and 13 were
approved by CNH in July triggering the start of the four-year
initial term for these licences. Reprocessing of the existing 3D
seismic has commenced and is expected to be completed in first
quarter 2020.
Brazil
In Brazil, Premier is actively engaging with rig contractors
with available units in-country to drill a well targeting the
stacked Berimbau and Maraca prospects on Block 717 (Premier 50 per
cent operated interest) in the offshore Ceara Basin in 2020.
Elsewhere in the Ceara basin, on Block 661 (Premier 30 per cent
non-operated interest), the joint venture was successful in
obtaining a licence extension through to November 2021 and now
plans to postpone the drilling of the well to 2021. The joint
venture aims to reach alignment on final well location to test the
stacked Itarema and Tatajuba prospects shortly. The two wells on
Blocks 717 and 661 will test in excess of 500 mmbbls of combined
gross prospective resource.
Having fully evaluated the prospectivity on Block 665 (Premier
50 per cent operated interest), Premier and its joint venture
partner unanimously decided to relinquish the licence in April
2019.
Alaska
Premier has signed a Sale and Purchase Agreement with 88 Energy
and Burgundy Xploration LLC to farm-in for a 60 per cent interest
in Area A of their conventional Project Icewine acreage in the
proven Alaska North Slope basin. This acreage lies close to the
Trans-Alaska Pipeline and the Dalton Highway. The transaction
provides Premier with a cost effective entry point into an emerging
play, following recent advances in drilling and completion
techniques, within a proven oil province and one which has the
potential to deliver significant organic growth opportunities for
the Group.
Area A contains the Malguk-1 discovery drilled by BP in 1991.
This well discovered but never tested 251 feet of light oil pay in
turbidite sands in the Torok formation, within the recently
emerging Brookian play. Premier estimates an accumulation of more
than 1 billion barrels of oil in place, based on the original well
data and its evaluation of the existing 3D dataset. There is also
considerable upside in the shallower Schrader Bluff formation which
has yet to be explored in a play similar to the Pikka/Horseshoe
trend. The Alaska North Slope has attracted considerable industry
interest recently with technological advances enabling these once
stranded resources to now be commercialised. Several similar
developments are already underway at various levels of maturity
involving operators such as ConocoPhillips, ENI, Repsol and Oil
Search.
Under the terms of the SPA, Premier will pay the full costs of
an appraisal well up to a total of US$23 million to test the
reservoir deliverability of the Malguk-1 discovery. The well will
be drilled and tested in Q1 2020 with rig options having already
been identified and contracting negotiations underway. On
successful completion of the work programme, Premier will have the
option to assume operatorship.
FINANCIAL REVIEW
Context
2019 has continued to see oil price volatility with observed
prices being as high as US$74.7/bbl and as low as US$50.2/bbl in
the period. Brent crude opened the year at US$50.2/bbl before
closing at US$63.9/bbl on 30 June 2019. The average for 2019 1H was
US$65.7/bbl compared to US$70.6/bbl for the corresponding period in
2018.
Against this economic backdrop our production averaged 84.1
kboepd in the period (2018 1H: 76.2 kboepd), which is ahead of
budget for 2019 and is underpinned by very high operating
efficiency across the portfolio. The increase when compared to the
corresponding prior period was predominantly due to an increased
contribution from the Premier-operated Catcher Area, which averaged
35.1 kboepd (net) and achieved 99 per cent operating efficiency.
This increased production has underpinned total sales revenue from
all operations of US$883.1 million compared with US$643.3 million
in 2018 1H.
Business performance
EBITDAX for the period from continuing operations was US$680.2
million, an increase of US$192.4 million compared to the prior
period EBITDAX of US$487.8 million, once lease expenses have been
added back following the implementation of IFRS 16. The increased
EBITDAX, on a like-for-like basis, is due to improved production
and realised oil prices post hedging with costs remaining broadly
flat due to tight cost control.
Business performance (continuing operations) 2019 2018
1H 1H
$ million $ million
Operating profit 327.5 185.5
Add: DD&A 346.5 185.6
Add: Exploration and new venture costs 8.7 7.4
(Less)/add: (Profit)/loss on disposal
of assets (2.5) 10.4
EBITDAX as reported 680.2 388.9
Add: lease expenses - 98.9
=========== ===========
EBITDAX adjusted for lease expenses 680.2 487.8
=========== ===========
Income statement
Production and revenue
Group production on a working interest basis averaged 84.1
kboepd for the period compared to 76.2 kboepd in 2018 1H, due to
high operational efficiency across the asset portfolio and the
increased contribution from the Catcher Area. Entitlement
production for the period was 79.9 kboepd (2018 1H: 69.2 kboepd).
Post hedging, Premier realised an average price for the period of
US$68.3/bbl (2018 1H: US$61.6/bbl) vs a Brent average price of
US$65.7/bbl (2018 1H: US$70.6/bbl).
In the UK, Premier achieved average natural gas prices of 44
pence/therm (2018 1H: 49 pence/therm), which included 21.7 million
therms which were sold under fixed price master sales agreements.
Gas prices in Singapore, indirectly linked with crude oil pricing,
averaged US$11.3/mscf (2018 1H: US$9.7/mscf) post hedging.
Realised prices 2019 2018
1H 1H
Oil price (US$/bbl) post hedging 68.3 61.6
---- ----
UK natural gas (pence/therm) 44 49
---- ----
Singapore HSFO (US$/mscf) 11.3 9.7
---- ----
Total sales revenue from all operations (including Pakistan
until its disposal in March 2019) increased to US$883.1 million
(2018 1H: US$643.3 million), due to an increase in realised oil and
HSFO prices in the period combined with higher production. From
continuing operations (excluding Pakistan), revenue increased to
US$871.3 million compared to US$625.0 million in the prior
period.
Operating costs
Cost of operations comprise operating costs, changes in lifting
positions, inventory movement and royalties. Cost of operations,
which now exclude lease expenses following the adoption of IFRS 16,
for the Group was US$183.4 million for 2019 1H, compared to
US$132.7 million for 2018 1H, once lease costs of US$98.9 million
are removed from the prior period.
2019 2018
1H 1H
$ million $ million
Operating costs
=========== ===========
Continuing operations 154.5 232.5
Less: lease expenses - (98.9)
Discontinuing operations (Pakistan) 2.4 4.7
------------------------------------- ----------- -----------
Operating costs 156.9 138.3
=========== ===========
Operating cost per barrel (US$ per
barrel) 10.3 10.0
------------------------------------- ----------- -----------
Lease expenses in 2019 1H were US$96.5 million, giving a lease
cost per barrel of US$6.3, which is broadly consistent year on
year.
2019 2018
1H 1H
$ million $ million
Amortisation and depreciation
---------------------------------- ----------- -----------
Total DD&A 344.3 180.8
---------------------------------- ----------- -----------
DD&A per barrel (US$ per barrel) 22.6 13.1
---------------------------------- ----------- -----------
Total depreciation has increased year-on-year due to DD&A
charges of US$121.4 million recognised on right-of-use-assets now
recorded on the balance sheet as property, plant and equipment
following the adoption of IFRS 16 on 1 January 2019. The DD&A
charge reflects the positive impact of the revised Catcher reserves
estimates.
Exploration expenditure and new ventures
Exploration expense and new venture costs amounted to US$8.7
million (2018 1H: US$7.4 million) primarily related to work
performed on potential new ventures. After recognition of these
expenditures, the exploration and evaluation asset remaining on the
balance sheet at 30 June 2019 amounts to US$870.6 million (31
December 2018: US$812.6 million) which primarily includes the Sea
Lion and Tuna projects, as well as the Group's share of expenditure
on the Zama prospect in Mexico.
General and administrative expenses
Net G&A costs of 2019 1H of US$3.3 million (2018 1H: US$3.0
million) are broadly consistent with the prior period.
Finance gains and costs
Net finance costs of US$207.6 million are broadly in line with
the prior year of US$210.2 million. An increase in finance costs
due to lease liabilities recognised on adoption of IFRS 16 has been
broadly offset by lower finance expenses for changes in the fair
value of Premier's equity warrant instruments in the period
compared to 2018 1H. Cash interest expense in the period was
US$127.5 million (2018 1H: US$125.5 million).
Taxation
The Group has a current tax charge for the period of US$36.9
million (2018 1H: charge of US$46.5 million) and a non-cash
deferred tax credit for the period of US$29.4 million (2018 1H:
credit of US$161.3 million) which results in a total tax charge for
the period of US$7.5 million, from continuing operations (2018 1H:
credit of US$114.8 million).
The total tax charge for the period represents an effective tax
rate of 6.3 per cent (2018 1H: 464.8 per cent). The low effective
tax rate is predominantly driven by prior year adjustments relating
to overseas tax disputes found in Premier's favour as well as ring
fence expenditure supplement, which continues to be claimed to
uplift UK ring fence tax losses carried forward.
The Group continues to recognise its UK deferred tax assets in
respect of ring fence tax losses and investment allowances in full
in line with the assumptions taken at 31 December 2018 on the basis
that there have been no impairment triggers identified at the
balance sheet date of 30 June 2019.
Profit after tax
Profit after tax for the period was US$120.6 million (2018 1H:
US$98.4 million), including US$8.2 million from the Pakistan
Business Unit which was classified as a discontinued operation
prior to the completion of its disposal in March 2019, resulting in
a basic earnings per share of 14.7 cents (2018 1H: 13.2 cents).
Cash flow
Cash flow from operating activities was US$544.6 million (2018
1H: US$224.6 million) after accounting for tax payments of US$42.1
million (2018 1H: US$62.5 million) and movement in joint venture
cash balances in the period of US$5.8 million. The increase is
driven by increased production and revenue in the period and due to
US$98.1 million of lease cash costs in 2019 1H recorded as
financing and not operating cash flows.
Capital expenditure in the period to 30 June 2019 totalled
US$103.3 million (2018 1H: US$164.3 million).
Capital expenditure 2019 2018
1H 1H
$ million $ million
Field/development projects 32.4 137.9
Exploration and evaluation 69.9 25.8
Other 1.0 0.6
Total 103.3 164.3
The development expenditure mainly relates to the BIG-P
development in Indonesia and the Tolmount project in the UK. The
largest part of the E&E capital expenditure in the period was
the appraisal drilling for the Zama project in Mexico. In addition,
cash expenditure for decommissioning activity in the period was
US$24.3 million (2018 1H: US$45.1 million). Further to this, US$5.2
million of cash was funded into long-term abandonment accounts for
future decommissioning activities (2018 1H: US$9.8 million).
Disposals
The Group completed the sale of its Pakistan business to the
Al-Haj Group in March 2019. In total Premier received the full
consideration of US$65.6 million for the sale including deposits
and completion payments paid by the buyer and net cash flows
collected by Premier since the economic date of the transaction.
The Pakistan Business Unit results for the current and prior
periods are presented as a discontinued operation.
Balance sheet position
Net Debt
Accounting net debt at 30 June 2019 amounted to US$2,151.2
million (31 December 2018: US$2,330.7 million), with cash resources
of US$253.5 million (31 December 2018: US$244.6 million).
During the period, Premier made debt repayments of US$169.7
million. The Group also cancelled US$100.3 million of undrawn
capacity of its RCF debt facility.
Premier retains significant cash at 30 June 2019 of US$225.7
million and undrawn facilities of US$419.6 million, giving
liquidity of US$645.3 million (31 December 2018: US$569.6 million)
when excluding cash of US$27.8 million held on behalf of joint
venture partners.
In July 2019, subsequent to the period end, the Group made a
further repayment of US$100 million of its RCF debt facility
reducing gross debt. The Group also cancelled US$233.5 million of
undrawn capacity of this facility, which will reduce commitment
fees going forward.
Provisions
Total decommissioning provisions at 30 June 2019 are US$1,186.1
million (31 December 2018: US$1,214.5 million, excluding those
associated with assets held for sale), with the reduction driven by
expenditure in the period.
Non-IFRS measures
The Group uses certain measures of performance that are not
specifically defined under IFRS or other generally accepted
accounting principles. These non-IFRS measures used within this
Interim Report and Accounts are EBITDAX, Cash Margin, Free Cash
Flow, Operating cost per barrel, DD&A per barrel, Net Debt and
Liquidity and are defined in the glossary.
Impact on key financial metrics on adoption of IFRS 16
Leases
A new IFRS standard on leases came into effect on 1 January
2019. The impact on key financial metrics for the period is shown
below.
$ million Impact of IFRS
16
Balance Sheet at 30 June 2019 (1)
Fixed assets 744.5
Net investment in sub-lease 85.9
Lease liabilities 873.1
===============
Income Statement for 2019 1H (2)
Costs of Production 96.5 Decrease
DD&A 121.4 Increase
Net finance costs 19.8 Increase
Net impact on profit after tax 44.7 Decrease
===============
Cash flow for 2019 1H (3)
Operating cash flow 98.1 Increase
Lease payments (within financing cash 98.1 Increase
flows)
Free cash flow Nil
===============
1. Balance Sheet
Following the adoption of IFRS 16, US$744.5 million of
right-of-use assets, US$85.9 million of net investment in sublease
and US$873.1 million of lease liabilities have been included in the
Group balance sheet as at 30 June 2019. All of these were
previously classified as operating leases as the Group did not have
any finance leases under IAS 17. Lease liabilities are now
presented separately on the Group balance sheet as both current and
non-current liabilities, do not form part of finance debt and are
not included in net debt under the terms of the Group's financing
facilities.
2. Income Statement
Charges to the income statement due to the adoption of IFRS 16
have increased by US$44.7 million. This represents an increase in
depreciation and finance costs recognised on right-of-use assets
and lease liabilities, which are partially offset by the absence of
operating lease expenses within costs of production. EBITDAX, as
previously defined, has increased, due to the absence of operating
lease expenses within costs of production. For the purposes of
covenant calculations, lease expenses continue to be included
within costs of production.
3. Cash flow
In prior years, operating lease payments were presented as
operating cash flows. Lease payments are now classified as
financing cash flows which has caused operating cash flows to
increase. There were US$98.1 million of lease payments included
within financing cash flows for 2019 1H, that would previously have
been reported within operating cash flows before the adoption of
IFRS 16.
Financial risk management
Commodity prices
Premier continue to take advantage of the improved oil price
environment observed at times in 2019 to increase its hedging
position in 2019 2H and 2020 to protect free cash flows and
covenant compliance.
The Group's current hedge position to the end of 31 December
2020 is as follows:
Oil
Swaps / forwards 2019 2H 2020
--------
Volume (mmbbls) 4.0 2.2
Average price (US$/bbl) 69 66
------------------------- -------- -----
UK gas
Swaps / forwards 2019 2H 2020
--------
Volume (million therms) 16.6 42.3
Average price (p/therm) 62 51
------------------------- -------- -----
Indonesia gas
Swaps / forwards 2019 2H 2020
--------
Volume (HSFO k te) 102 252
Average price (US$/te) 381 361
------------------------ -------- -----
At 30 June 2019, the fair value of the open oil and gas
instruments above was an asset of US$37.9 million (31 December
2018: asset of US$119.3 million), which is expected to be released
to the income statement during 2019 2H and 2020 as the related
barrels are lifted or therms delivered.
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. During the period, the Group
recorded a mark-to-market gain of US$1.9 million on its outstanding
foreign exchange contracts. The Group currently has GBP150.0
million retail bonds, EUR60.0 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$1.37:EUR.
Interest rates
The Group has various financing instruments including senior
loan notes, UK retail bonds, term loans and revolving credit
facilities. Currently, approximately 66 per cent of total
borrowings is fixed or has been fixed using the interest rate swap
markets. On average, the effective interest on drawn funds for the
period, recognised in the income statement, was 8.3 per cent.
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.
Management's base case forecast assumes an oil price of
US$65/bbl in 2019 and 2020, and production in line with prevailing
rates. The Group has run downside scenarios, where oil prices are
reduced by a flat US$10/bbl throughout the going concern period and
where total Group production is forecast to reduce by 10 per
cent.
At 30 June 2019, the Group continued to have significant
headroom on its financing facilities and cash on hand. The base
case forecasts show that the Group will have sufficient financial
headroom for the 12 months from the date of approval of the 2019
Interim Report and Accounts. In the individual downside scenarios
ran, no covenant breach is forecasted in the going concern period.
If both downside scenarios were to materialise immediately and were
sustained throughout the going concern period, then, in the absence
of any mitigating actions, a breach of one or more of the financial
covenants during the 12 month going concern assessment period could
arise. This potential breach could be mitigated by non-core asset
disposals, such as the Group's interest in the Zama prospect, as
well as further hedging activity or deferral of expenditure.
Accordingly, after making enquiries and considering the risks
described above, the Directors have a reasonable expectation that
the Company has adequate resources to continue in operational
existence for the foreseeable future. Accordingly, the Directors
continue to adopt the going concern basis of accounting in
preparing these consolidated 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 to business unit
management, 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's principal risks for the remaining 6 months of the
year are set out below:
-- Commodity price volatility
-- Financial discipline and governance
-- Production and development delivery and decommissioning
execution
-- Joint venture partner alignment and supply chain delivery
-- Climate change
-- Organisational capability
-- Exploration success and reserves addition
-- Health, safety, environment and security
-- Host government: political and fiscal risks
These risks are consistent with those identified at 31 December
2018, with the addition of a new principal risk related to the
impact of climate change.
The potential impact related to the risk of climate change is as
follows:
-- Adverse investor and lender sentiment towards the oil and gas
sector
-- Failure to comply with climate change related operational
regulations and disclosure requirements
-- Disruption to Premier's projects and operations, as a result
of changing weather patterns and more frequent extreme weather
events
-- Longer term reduction in demand for oil and gas products
resulting in lower oil and gas prices, as a result of commercial
deployment of alternative energy technologies and shifts in
consumer preference for lower greenhouse gas emission products
Further information detailing the way in which these risks are
mitigated is provided on pages 36 to 41 of the 2018 Annual Report
and Financial Statements. This information is also available on
Company's website www.premier-oil.com.
STATEMENT OF DIRECTORS' RESPONSIBILITIES
Each of the Directors of the Company confirms that to the best
of his or her knowledge:
a) the condensed set of financial statements, which has been
prepared in accordance with International Accounting Standard 34 -
'Interim Financial Reporting' as adopted by the European Union
gives a true and fair view of the assets, liabilities, financial
position and profit of the Company;
b) the half-yearly results statement includes a fair review of
the information required by DTR 4.2.7R (indication of important
events during the first six months and description of principal
risks and uncertainties for the remaining six months of the year);
and
c) the half-yearly results statement includes a fair review of
the information required by DTR 4.2.8R (disclosure of related
parties' transactions and changes therein).
On behalf of the Board
Richard Rose
Finance Director
CONDENSED CONSOLIDATED INCOME STATEMENT
Six months Six months
to 30 June to 30 June
2019 2018
Unaudited Unaudited
Note $ million $ million
============================================= ==== =========== ============
Continuing operations
Sales revenues 2 871.3 625.0
Other operating costs (4.4) (1.5)
Costs of operation 3 (183.4) (231.6)
Depreciation, depletion and amortisation 8 (346.5) (185.6)
Exploration and new venture costs 7 (8.7) (7.4)
Gain/(loss) on disposal of non-current
assets 2.5 (10.4)
General and administration costs (3.3) (3.0)
============================================= ==== =========== ============
Operating profit 327.5 185.5
Interest revenue, finance and other
gains 4 11.1 3.8
Finance costs, other finance expenses
and losses 4 (218.7) (214.0)
Profit/(loss) before tax 119.9 (24.7)
Tax (charge)/credit 5 (7.5) 114.8
============================================= ==== =========== ============
Profit for the period from continuing
operations 112.4 90.1
Discontinued operations
Profit for the period from discontinued
operations 11 8.2 8.3
============================================= ==== =========== ============
Profit after tax 120.6 98.4
============================================= ==== =========== ============
Earnings per share (cents):
From continuing operations
Basic 6 13.7 12.1
Diluted 6 12.4 10.4
From continuing and discontinued operations
Basic 6 14.7 13.2
Diluted 6 13.3 11.4
============================================= ==== =========== ============
Notes 1 to 13 form an integral part of these condensed financial
statements.
CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
Six months Six months
to 30 June to 30 June
2019 2018
Unaudited Unaudited
$ million $ million
======================================== =========== ===========
Profit for the period 120.6 98.4
----------------------------------------- ----------- -----------
Cash flow hedges on commodity swaps:
(Losses) arising during the period (78.9) (88.4)
Less: reclassification adjustments
for (gains)/losses in the period (8.8) 36.4
========================================= =========== ===========
(87.7) (52.0)
Cash flow hedges on interest rate
and foreign exchange swaps
Gains arising during the period 0.4 8.6
Less: reclassification adjustments
for (gains) in the period (2.0) (3.9)
========================================= =========== ===========
(1.6) 4.7
======================================== =========== ===========
Tax relating to components of other
comprehensive income 25.9 16.2
Exchange differences on translation
of foreign operations 11.2 (7.6)
Other comprehensive expense (52.2) (38.7)
Total comprehensive income for the
period 68.4 59.7
========================================= =========== ===========
All amounts to be reclassified to profit or loss in subsequent
periods.
All comprehensive income is attributable to the equity holders
of the parent.
CONDENSED CONSOLIDATED BALANCE SHEET
At At
30 June 31 December
2019 2018
Unaudited Audited
Note $ million $ million
======================================= ==== ========== =============
Non-current assets:
Intangible exploration and evaluation
assets 7 870.6 812.6
Property, plant and equipment 8 2,762.9 2,245.6
Goodwill 240.8 240.8
Long-term receivables 227.2 159.8
Deferred tax assets 1,483.9 1,434.1
======================================= ==== ========== =============
5,585.4 4,892.9
======================================= ==== ========== =============
Current assets:
Inventories 16.1 12.5
Trade and other receivables 393.1 282.3
Derivative financial instruments 10 39.2 127.4
Cash and cash equivalents 253.5 244.6
Assets held for sale 11 - 55.2
701.9 722.0
Total assets 6,287.3 5,614.9
======================================= ==== ========== =============
Current liabilities:
Trade and other payables (320.4) (375.6)
Lease liabilities 12 (161.6) -
Short-term provisions (57.2) (46.0)
Derivative financial instruments 10 (28.7) (41.4)
Deferred income (9.8) (11.0)
Liabilities directly associated with
assets held for sale 11 - (21.9)
(577.7) (495.9)
Net current assets 124.2 226.1
======================================= ==== ========== =============
Non-current liabilities:
Long-term debt 9 (2,386.4) (2,552.0)
Deferred tax liabilities (134.4) (139.5)
Lease liabilities 12 (711.5) -
Deferred income (73.5) (76.0)
Long-term provisions (1,160.5) (1,196.1)
Derivative financial instruments 10 (133.2) (129.4)
(4,599.5) (4,093.0)
Total liabilities (5,177.2) (4,588.9)
======================================= ==== ========== =============
Net assets 1,110.1 1,026.0
======================================= ==== ========== =============
Equity and reserves:
Share capital 155.5 154.2
Share premium account 494.8 491.7
Other reserves 459.8 380.1
======================================= ==== ========== =============
1,110.1 1,026.0
======================================= ==== ========== =============
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
Share premium
Share capital account Other reserves Total
$ million $ million $ million $ million
-----------------------------------
At 31 December 2018 154.2 491.7 380.1 1,026.0
Issue of Ordinary Shares 1.3 3.1 0.9 5.3
Net release of ESOP Trust shares - - 1.0 1.0
Provision for share-based payments - - 9.4 9.4
Profit for the period - - 120.6 120.6
Other comprehensive expense - - (52.2) (52.2)
At 30 June 2019 155.5 494.8 459.8 1,110.1
At 31 December 2017 109.0 284.5 223.4 616.9
Adjustment on adoption of IFRS
9(1) - - (82.0) (82.0)
At 1 January 2018 109.0 284.5 141.4 534.9
Issue of Ordinary Shares 38.5 178.4 (0.2) 216.7
Net release of ESOP Trust shares - - (1.0) (1.0)
Provision for share-based payments - - 8.2 8.2
Release of equity component
of convertible bonds - - (54.5) (54.5)
Profit for the period - - 98.4 98.4
Other comprehensive expense - - (38.7) (38.7)
------------- ------------- -------------- ----------
At 30 June 2018 147.5 462.9 153.6 764.0
------------- ------------- -------------- ----------
(1) Refer to the accounting policies in the Premier Oil 2018
Annual Report and Accounts for further information
CONDENSED CONSOLIDATED CASH FLOW STATEMENT
Six months Six months
to 30 June to 30 June
2019 2018
Unaudited Unaudited
Note $ million $ million
======================================= ==== ============ ============
Net cash from operating activities 9 544.6 224.6
======================================= ==== ============ ============
Investing activities:
Capital expenditure (103.3) (164.3)
Decommissioning pre-funding (5.2) (9.8)
Decommissioning expenditure (24.3) (45.1)
Disposal of oil and gas properties 11 3.1 22.8
Net cash used in investing activities (129.7) (196.4)
Financing activities:
Issuance of Ordinary Shares 3.8 8.0
Net release of ESOP Trust shares 1.0 (1.0)
Warrant cash consideration (11.9) -
Lease liability payments (98.1) -
Proceeds from drawdown of bank loans - 105.0
Repayment of bank loans (169.7) (199.1)
Interest paid (127.5) (125.5)
======================================= ==== ============ ============
Net cash used in financing activities (402.4) (212.6)
======================================= ==== ============ ============
Currency translation differences relating
to cash and cash equivalents (3.6) (1.0)
============ ============
Net increase/(decrease) in cash and
cash equivalents 8.9 (185.4)
Cash and cash equivalents at the
beginning of the period 244.6 365.4
======================================= ==== ============ ============
Cash and cash equivalents at the
end of the period 9 253.5 180.0
--------------------------------------- ---- ============ ============
NOTES TO THE CONDENSED FINANCIAL STATEMENTS
1. BASIS OF PREPARATION
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.
The condensed financial statements for the six months ended 30
June 2019 were approved for issue in accordance with a resolution
of a committee of the Board of Directors on 21 August 2019.
The information for the year ended 31 December 2018 contained
within the condensed financial statements does not constitute
statutory accounts within the meaning of Section 434 of the
Companies Act 2006. Statutory accounts for the year ended 31
December 2018 were approved by the Board of Directors on 6 March
2018 and delivered to the Registrar of Companies. The auditor
reported on those accounts; the report was unqualified and did not
contain any statement under Section 498(2) or 498(3) of the
Companies Act 2006.
The financial information contained in this report is unaudited.
The condensed consolidated income statement, condensed consolidated
statement of comprehensive income, condensed consolidated statement
of changes in equity and the condensed consolidated cash flow
statement for the six months to 30 June 2019, and the condensed
consolidated balance sheet as at 30 June 2019 and related notes,
have been reviewed by the auditors. The auditors' report to the
Company is attached.
Basis of preparation
The condensed financial statements for the six months ended 30
June 2019 have been prepared in accordance with IAS 34 - 'Interim
Financial Reporting', as adopted by the European Union and with the
requirements of the Disclosure Guidance and Transparency Rules
issued by the Financial Conduct Authority. These condensed
financial statements should be read in conjunction with the annual
financial statements for the year ended 31 December 2018, which
have been prepared in accordance with International Financial
Reporting Standards as adopted by the European Union.
The condensed financial statements have been prepared on the
going concern basis. Further information relating to the going
concern assumption is provided in the Financial Review.
1. BASIS OF PREPARATION (continued)
Accounting policies
The accounting policies applied in these condensed financial
statements are consistent with those of the annual financial
statements for the year ended 31 December 2018, as described in
those annual financial statements, except for the adoption of IFRS
16 Leases.
IFRS 16 'Leases'
Premier adopted IFRS 16 Leases ('IFRS 16') with effect from 1
January 2019. IFRS 16 was issued in January 2016 to replace IAS 17
Leases. Further information is included in Premier's 2018 Annual
Report and Financial Statements - Accounting Policies.
IFRS 16 sets out the principles for the recognition,
measurement, presentation and disclosure of leases and requires
lessees to account for all leases, with limited exceptions, under a
single on-balance sheet model similar to the accounting for finance
leases under IAS 17. Under IFRS 16, at the commencement date of a
lease, a lessee is required to recognise a liability to make lease
payments ('lease liability') and an asset representing the right to
use the underlying asset during the lease term ('right-of-use
asset'). Lease liabilities are measured at the present value of
future lease payments over the reasonably certain lease term.
Variable lease payments that do not depend on an index or a rate
are not included in the lease liability. Such payments are expensed
as incurred throughout the lease term.
In applying IFRS 16 for the first time the Group has applied the
short-term lease practical expedient by not recognising lease
liabilities in respect to lease arrangements with a remaining lease
term of less than 12 months as at 1 January 2019. The Group adopted
the modified retrospective approach to adoption on 1 January 2019,
measuring right-of-use assets at an amount based on their
respective lease liability on adoption, with the cumulative effect
of adopting the standard recognised at the date of initial
application without restatement of comparative information.
Lessees are required to separately recognise the interest
expense associated with the unwinding of the lease liability and
the depreciation expense on the right-of-use asset. These costs
replace amounts previously recognised as operating expenditure in
respect of operating leases in accordance with IAS 17. Principal
payments related to leases are now presented as financing cash
flows in the cashflow statement. The replacement of operating lease
expenditure with the recognition of interest expense and
depreciation in respect to leases liabilities and right-of-use
assets, respectively, will result in an increase in Group EBITDAX.
The adoption of IFRS 16 will not impact the calculation of the
Group's financial debt covenants.
1. BASIS OF PREPARATION (continued)
A matter finalised since the release of Premier's 2018 Annual
Report and Financial Statements is the determination of the
appropriate accounting for a lease arrangement entered into by a
lead operator as a sole signatory for the lease of equipment that
will be used in a joint operation. The IFRS Interpretations
Committee ('IFRIC') issued an agenda decision in respect to this
matter in March 2019. Where all partners of a joint operation are
considered to share the primary responsibility for lease payments
under a lease contract, the Group recognises its share of the
respective right-of-use asset and lease liability. This situation
is most common where the parties of a joint operation co-sign the
lease contract. The Group recognises a gross lease liability for
leases entered into on behalf of a joint operation where it has
primary responsibility for making the lease payments.
In such instances, if the arrangement between the Group and the
joint operation represents a finance sublease, the Group recognises
a net investment in sublease for amounts recoverable from
non-operators whilst derecognising the respective portion of the
gross right-of-use asset. The gross lease liability is retained on
the balance sheet. The net investment in sublease is classified as
either trade and other receivables or long-term receivables on the
balance sheet according to whether or not the amounts will be
recovered within 12 months of the balance sheet date.
The assessment as to whether a sublease exists predominantly
depends on whether the operator or the joint operation directs the
use of the respective right-of-use asset. Where the arrangement
between the operator and joint operation does not represent a
sublease or the sublease represents an operating sublease, the
Group retains the gross lease liability and right-of-use asset on
the balance sheet.
The following table provides a reconciliation of the Group's
operating lease commitments as at 31 December 2018 to the total
lease liability recognised on adoption of IFRS 16. The Group did
not recognise any finance leases under IAS 17.
$ million
Operating lease commitments at 31 December
2018 1,002.0
Contracts not in scope of IFRS 16(1) (85.6)
Effect of discounting(2) (189.9)
Short term leases (3.1)
Impact of leases in joint operations(3) 99.0
Lease extension options(4) 77.6
Other (0.4)
==========
Lease liabilities recognised on adoption of
IFRS 16 899.6
==========
Notes
(1) Contracts that were considered to be leases under IAS 17
which do not meet the definition of a lease under IFRS 16,
principally because the supplier is considered to have substantive
substitution rights over the associated assets.
(2) The previously disclosed lease commitments were
undiscounted, whilst the IFRS 16 obligations have been discounted
based on Premier's incremental borrowing rate.
(3) This represents the gross up of the lease obligations to
represent 100 per cent of the liability where the Group has entered
into a lease agreement on behalf of the joint operation and its
partners and has primary responsibility for lease payments.
(4) Previously, lease commitments only included non-cancellable
periods in the lease agreements. Under IFRS 16, the lease term
includes periods covered by options to extend the lease where the
Group is reasonably certain that such options will be
exercised.
A number of additional new standards, amendments to existing
standards and interpretations were effective from 1 January 2019.
The adoption of these amendments did not have a material impact on
the Group's condensed financial statements for the half-year ended
30 June 2019.
2. OPERATING SEGMENTS
The Group's operations are located and managed in five business
units; namely the Falkland Islands, Indonesia, the United Kingdom,
Vietnam and the Rest of the World. The results for Pakistan, the
disposal of which was completed in March 2019, are reported as a
discontinued operation. 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.
Six months Six months
to 30 June to 30 June
2019 2018
Unaudited Unaudited
$ million $ million
======================================== ============ ============
Revenue:
United Kingdom 673.7 395.7
Indonesia 88.8 87.6
Vietnam 108.8 140.9
Rest of the World - 0.8
Total Group sales revenue 871.3 625.0
Other operating costs - United Kingdom (4.4) (1.5)
Interest and other finance revenue 4.0 2.2
Total Group revenue from continuing
operations 870.9 625.7
Revenue from discontinued operations 11.8 18.3
============ ============
Group operating profit:
United Kingdom 225.7 74.6
Indonesia 56.5 42.1
Vietnam 57.7 77.5
Rest of the World (0.2) (3.5)
Unallocated(1) (12.2) (5.2)
--------------------------------------------- -------- --------
Group operating profit 327.5 185.5
Interest revenue, finance and other
gains 11.1 3.8
Finance costs and other finance expenses (218.7) (214.0)
Profit/(loss) before tax from continuing
operations 119.9 (24.7)
Tax (charge)/credit (7.5) 114.8
======== ========
Profit after tax from continuing operations 112.4 90.1
======== ========
Profit from discontinued operations 8.2 8.3
======== ========
(1) Unallocated expenditure include amounts of a corporate
nature and not specifically attributable to a geographical segment.
These items include corporate general and administration costs and
exploration and new venture costs.
2. OPERATING SEGMENTS (continued)
Of the Group's worldwide revenues of US$871.3 million (2018 1H:
US$625.0 million), revenues of US$861.6 million (2018 1H: US$661.4
million) were from contracts with customers. This was increased by
hedging gains in the period of US$9.7 million (2018 1H: loss of
US$36.4 million).
30 June 31 December
2019 2018
Unaudited Audited
$ million $ million
Balance sheet - Segment assets:
United Kingdom(1) 4,263.5 3,706.1
(3)
Indonesia 451.7 417.7
Vietnam 467.8 312.0
Falkland Islands 663.9 648.1
Rest of the World 147.7 103.8
Assets held for sale - 55.2
Unallocated(2) 292.7 372.0
-------------------------------- ----------- ------------
Total assets 6,287.3 5,614.9
-------------------------------- ----------- ------------
(1) Includes goodwill of US$240.8 million.
(2) Unallocated assets include cash and cash equivalents and mark-to-market
valuations of commodity contracts and interest rate swaps and
options.
3. COSTS OF OPERATION
Six months Six months
to 30 June to 30 June
2019 2018
Unaudited Unaudited
$ million $ million
===================================== ============ ============
Operating costs 154.5 232.5
Gas purchases 14.0 4.3
Stock overlift/(underlift) movement 10.0 (12.5)
Royalties 4.9 7.3
183.4 231.6
4. INTEREST REVENUE AND FINANCE COSTS
Six months Six months
to 30 June to 30 June
2019 2018
Unaudited Unaudited
$ million $ million
========================================== ============ ============
Interest revenue, finance and other
gains:
Lease finance income 2.8 -
Short-term deposits 1.1 0.6
Other interest received 0.4 1.6
Derivative gains 4.3 1.6
Exchange differences and others 2.5 -
11.1 3.8
Finance costs:
Bank loans, overdrafts and bonds (101.1) (86.7)
Payable in respect of convertible
bonds - (0.6)
Payable in respect of senior loan
notes (18.9) (18.9)
Long-term debt arrangement fees (5.0) (15.2)
Exchange differences and others (29.7) (6.6)
============ ============
(154.7) (128.0)
Other finance expenses:
Lease finance costs (22.6) -
Unwinding of discount on decommissioning
provision (26.2) (31.7)
Derivative losses (14.2) (51.6)
Finance expense on deferred income (2.6) (2.7)
============ ============
(65.6) (86.0)
Gross finance costs and other finance
expenses (220.3) (214.0)
Finance costs capitalised during the 1.6 -
period
============ ============
(218.7) (214.0)
------------------------------------------ ------------ ------------
5. TAX
Six months Six months
to 30 June to 30 June
2019 2018
Unaudited Unaudited
$ million $ million
======================================= ============ ============
Current tax:
UK corporation tax on profits - (9.5)
Overseas tax 49.6 56.0
Adjustments in respect of prior years (12.7) -
============ ============
Total current tax charge 36.9 46.5
============ ============
Deferred tax:
UK corporation tax (24.2) (146.4)
Overseas tax (5.2) (14.9)
============ ============
Total deferred tax credit (29.4) (161.3)
============ ============
Tax charge/(credit) on profit/(loss)
on ordinary activities 7.5 (114.8)
============ ============
5. TAX (continued)
The Group has a current tax charge for the period of US$36.9
million (2018 1H: US$46.5 million) and a non-cash deferred tax
credit for the period of US$29.4 million (2018 1H: US$161.3
million) which results in a total tax charge for the period of
US$7.5 million (2018 1H: US$114.8 million credit). The deferred tax
credit primarily arises due to ring fence expenditure supplement
which is claimed on UK tax losses.
The total tax charge for the period represents an effective tax
rate of 6.3 per cent (2018 1H: 464.8 per cent). The low effective
tax rate is predominantly driven by ring fence expenditure
supplement which continues to be claimed to uplift UK ring fence
tax losses carried forward and prior year adjustments relating to
overseas tax disputes found in Premier's favour. The Group has not
recognised any tax benefit for ongoing tax disputes where a ruling
in the Group's favour is not yet considered to be probable.
In addition, during the period, the Group recognised a deferred
tax asset and associated tax credit in relation to an expected
future tax deduction associated with decommissioning costs funded
by E.ON. An offsetting finance cost, which is classified within
exchange differences and others (see note 4), has also been
recognised as this tax deduction will be reimbursed to E.ON once
received by Premier. This finance cost represents the majority of
the increase in exchange differences and others when compared to
the prior period.
The Group continues to recognise its UK deferred tax assets in
respect of ring fence tax losses and investment allowances in full
in line with the assumptions taken at 31 December 2018 on the basis
that there have been no impairment indicators identified at the
balance sheet date of 30 June 2019.
The future effective tax rate for the Group is impacted by the
mix of jurisdictions in which the Group operates (with corporation
tax rates ranging from 20 per cent to 40 per cent), assumptions
around future oil prices and changes to tax rates and
legislation.
6. EARNINGS PER SHARE
The calculation of basic earnings per share is based on the
profit after tax and on the weighted average number of Ordinary
Shares in issue during the period. Basic and diluted earnings per
share are calculated as follows:
Six months Six months
to 30 June to 30 June
2019 2018
Unaudited Unaudited
Earnings ($ millions):
Earnings from continuing operations 112.4 90.1
Effect of dilutive potential Ordinary
Shares:
Interest on convertible bonds - 0.6
============ ============
Earnings for the purposes of diluted
earnings per share on continuing operations 112.4 90.7
Profit from discontinued operations 8.2 8.3
============================================== ============ ============
Earnings for the purpose of diluted
earnings per share on continuing and
discontinued operations 120.6 99.0
============================================== ============ ============
Number of shares (millions):
Weighted average number of Ordinary
Shares for the purpose of basic earnings
per share 821.6 745.0
Effects of dilutive potential Ordinary
Shares:
Contingently issuable shares - dilutive 83.0 127.2
============================================== ============ ============
Weighted average number of Ordinary
Shares for the purpose of diluted
earnings per share 904.6 872.2
============================================== ============ ============
Earnings per share (cents) from continuing
operations
Basic 13.7 12.1
Diluted 12.4 10.4
Earnings per share (cents) from discontinued
operations
Basic 1.0 1.1
Diluted 0.9 1.0
============ ============
Discontinued operations relate to the results of the Group's
Pakistan Business Unit, which was disposed of in March 2019.
7. INTANGIBLE EXPLORATION AND EVALUATION (E&E) ASSETS
Oil and
gas properties
$ million
-----------------------------
Cost:
At 1 January 2019 812.6
Exchange movements 1.5
Additions during the period 56.8
Exploration expense (0.3)
At 30 June 2019 870.6
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 reserves are established or the determination process is
not completed and there are no indications of impairment.
The outcome of ongoing exploration, and therefore whether the
carrying value of E&E assets will ultimately be recovered, is
inherently uncertain. To the extent that we have an active licence
to continue to explore for resources and have an intention to
continue exploration activity, the exploration cost associated with
the licence will remain capitalised as an E&E asset on the
balance sheet. Once exploration activity has completed and we have
no further intention to explore the licence for resources, costs
capitalised until that point will be expensed and no further costs
associated with the licence will be capitalised.
The balance carried forward is predominantly in relation to the
Sea Lion and Tuna projects, as well as our share of expenditure on
the Zama prospect in Mexico.
Oil and gas Right-of-use-assets Other
properties fixed assets Total
$ million $ million $ million $ million
=============================== ----------- -------------------- -------------- ----------
Cost:
At 1 January 2019 7,807.6 803.3 57.3 8,668.2
Exchange movements - (2.0) - (2.0)
Additions during the period (1.8) 64.6 1.0 63.8
Disposals (1.3) - - (1.3)
At 30 June 2019 7,804.5 865.9 58.3 8,728.7
Amortisation and depreciation:
At 1 January 2019 5,568.2 - 51.1 5,619.3
Charge for the period 222.9 121.4 2.2 346.5
At 30 June 2019 5,791.1 121.4 53.3 5,965.8
===============================
Net book value:
=============================== =========== ==================== ============== ==========
At 30 June 2019 2,013.4 744.5 5.0 2,762.9
=============================== ----------- -------------------- -------------- ----------
At 31 December 2018 2,239.4 - 6.2 2,245.6
=============================== ----------- -------------------- -------------- ----------
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 and 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.
Right-of-use-assets
There were no new leases entered into during the period. The
additions above represent the revision to the right-of-use asset
for the Catcher FPSO due to the assumed COP date being extended to
2028, given positive field performance.
In addition to the above, the Group has a net investment in
sublease of US$85.9 million (1 January 2019: US$96.3 million), of
which US$64.5 million is classified as a long-term receivable and
US$21.4 million as trade and other receivables. The net investment
in sublease represents our joint operation partners' share of lease
liabilities on lease arrangements for which Premier has entered
into in its role as operator as sole signatory on behalf of the
joint operation and the asset is jointly controlled by the joint
operation.
Income of US$2.8 million, which predominantly represents
unwinding of the net investment in sublease, has been recognised as
finance income in the year (see note 4).
9. NOTES TO THE CONDENSED CONSOLIDATED CASH FLOW STATEMENT
Six months Six months
to 30 June to 30 June
2019 2018
Unaudited Unaudited
Note $ million $ million
========================================== ===== ============ ============
Profit/(Loss) before tax for the
period 119.9 (24.7)
Adjustments for:
Depreciation, depletion and amortisation 346.5 185.6
Other operating costs 4.4 1.5
Exploration expense 7 0.3 5.2
Provision for share-based payments 6.0 4.2
Interest revenue and finance gains 4 (11.1) (3.8)
Finance costs and other finance
expenses 4 218.7 214.0
(Gain)/loss on disposal of non-current
assets (2.5) 10.4
========================================== ===== ============ ============
Operating cash flows before movements
in working capital 682.2 392.4
Increase in inventories (3.7) (4.6)
(Increase)/decrease in receivables (16.4) 48.3
Decrease in payables (81.4) (113.7)
========================================== ===== ============ ============
Cash generated by operations 580.7 322.4
Income taxes paid (42.1) (62.5)
Interest income received 4.6 1.8
========================================== ===== ============ ============
Net cash from continuing operating activities 543.2 261.7
============ ============
Net cash from discontinued operating
activities 11 7.2 14.9
========================================== ===== ============ ============
Net cash from operating activities 550.4 276.6
========================================== ===== ============ ============
Movement in joint venture cash (5.8) (52.0)
========================================== ===== ============ ============
Total net cash from operating activities 544.6 224.6
========================================== ===== ============ ============
9. NOTES TO THE CONDENSED CONSOLIDATED CASH FLOW STATEMENT
(continued)
Analysis of changes in net debt:
Six months Six months
to 30 June to 30 June
2019 2018
Unaudited Unaudited
$ million $ million
============================================== ============ ============
a) Reconciliation of net cash flow to
movement in net debt:
Movement in cash and cash equivalents 8.9 (185.4)
Proceeds from drawdown of bank loans - (105.0)
Repayment of bank loans 169.7 199.1
Partial conversion of convertible bonds - 154.0
Non-cash movements on debt and cash balances
(predominantly foreign exchange) 0.9 8.8
============ ============
Decrease in net debt in the period 179.5 71.5
Opening net debt (2,330.7) (2,724.2)
============ ============
Closing net debt (2,151.2) (2,652.7)
============ ============
b) Analysis of net debt:
Cash and cash equivalents 253.5 180.0
Borrowings(1) (2,404.7) (2,832.7)
========== ==========
Total net debt (2,151.2) (2,652.7)
========== ==========
(1) Borrowings consist of the convertible bonds and long-term
debt. The carrying amounts of the borrowings on the balance
sheet are stated net of the unamortised portion of the
refinancing fees of US$18.3 million (31 December 2018:
US$23.3 million) and the impact of the IFRS 9 adjustment
(see accounting policies in the Premier Oil 2018 Annual
Report and Accounts).
10. FINANCIAL INSTRUMENTS
Derivative financial instruments
The Group held the following financial instruments at fair value
at 30 June 2019. The fair values of all derivative financial
instruments are based on estimates from observable inputs and are
all level 2 in the IFRS 13 hierarchy, except for the Chrysaor
contingent consideration and the fair value of the equity and
synthetic warrants, which both include estimates based on
unobservable inputs and are level 3 in the IFRS 13 hierarchy. There
are no non-recurring fair value measurements.
The carrying value of the Group's derivative financial assets
and liabilities are:
At 30 June At 31 December
2019 2018
$ million $ million
=========================== ============ ===== ====
Financial assets:
Oil forward sales contracts 28.8 102.0
Gas forward sales contracts 10.4 23.4
Interest rate options - 1.1
Interest rate swaps - 0.9
Total 39.2 127.4
Financial liabilities:
Oil forward sales contracts 3.6 6.6
Gas forward sales contracts - 0.6
Cross currency swaps 131.7 125.6
Fair value of gas contract acquired from
E.ON 1.5 3.8
Forward foreign exchange contracts 0.5 2.4
Warrants 24.6 31.8
----------------------------------------- ---------- ----------- ---------------
Total 161.9 170.8
------------------------------------------------------ ----------- ---------------
Fair value is the amount at which a financial instrument could
be exchanged in an arm's length transaction, other than in a forced
or liquidated sale. Where available, market values have been used
to determine fair values. The estimated fair values have been
determined using market information and appropriate valuation
methodologies. Values recorded are as at the balance sheet date,
and will not necessarily be realised. Non-interest bearing
financial instruments, which include amounts receivable from
customers and accounts payable are also recorded materially at fair
value reflecting their short-term maturity.
Equity and synthetic warrants
The fair value of the warrants includes unobservable inputs and
is level 3 in the IFRS 13 hierarchy. The key assumptions
underpinning the fair value relate to the expected future share
price of the Company, US$:GBP exchange rates and the expected date
of exercise of the warrants. The fair value has been determined
using the Black-Scholes valuation model.
10. FINANCIAL INSTRUMENTS (continued)
The equity warrants have an exercise price of 41.80 pence and
are exercisable from their issuance until 31 May 2022, at the
option of the warrant holder, and are settled with Ordinary Shares
of the Company. The synthetic warrants are cash settled by the
Group when certain net debt and leverage conditions are achieved,
linked to the Group's market capitalisation, and expire in May
2021.
During the period, 5.3 million equity warrants were converted,
resulting in an allotment of 4.5 million shares. The closing fair
value of the open equity at 30 June 2019 was US$24.6 million,
resulting in a loss of US$3.4 million being expensed in the period
as derivative losses within other finance expenses (see note
4).
During the period, following the Group's leverage ratio being
below 3.0x for the 12 month period ended 31 March 2019, the Group
exercised its option to settle the synthetic warrants for a cash
consideration of GBP10.8 million. The fair value movement against
the opening balance sheet liability of US$4.7 million was expensed
as a derivative loss within other finance expenses in the period.
As at 30 June 2019, GBP9.3 million had been paid to warrant holders
with the remaining GBP1.5 million classified within other
payables.
Contingent consideration
The contingent consideration is the fair value of the royalty
stream payable to Chrysaor for the acquisition of 40 per cent of
the Solan asset in May 2015. The estimate of fair value of this
contingent consideration includes unobservable inputs and is level
3 in the IFRS 13 hierarchy and is held at fair value though profit
and loss. The movement in fair value for the period was US$4.4
million and has been recognised within other operating costs.
Fair value of financial assets and financial liabilities
The carrying values and fair values of the Group's
non-derivative financial assets and financial liabilities
(excluding current assets and current liabilities for which
carrying values approximate to fair values due to their short-term
nature) are shown below.
At 30 June 2019 At 31 December
2018
Fair value Carrying Fair value Carrying
amount amount amount amount
$ million $ million $ million $ million
=============================== =========== =========== ===========
Primary financial instruments
held or issued to finance
the Group's operations:
Retail bonds 193.6 190.4 181.6 190.5
================================ =========== =========== =========== ===========
The fair value for the bank loans and senior loan notes are
considered to be materially the same as the amortised costs of the
instruments.
11. DISCONTINUED OPERATIONS, DISPOSALS AND ASSETS HELD FOR
SALE
Disposals
In April 2017, Premier announced it had reached agreement and
signed an SPA with Al-Haj Energy Limited ('Al-Haj') for the sale of
Premier Oil Pakistan Holdings BV, which comprises Premier's
Pakistan Business Unit, for a cash consideration of US$65.6
million. The disposal completed March 2019, following receiving the
necessary government approvals and receipt by Premier of the full
consideration of US$65.6 million through deposits and completion
payments paid by the buyer; and, net cash flows collected by
Premier since the economic date of the transaction.
At 31 December 2018, the Pakistan Business Unit was classified
as a disposal group held for sale and the assets and liabilities
for this disposal group were presented separately in the balance
sheet.
The results of the disposal group, until completion, which have
been included as discontinued operations in the consolidated income
statement were as follows:
30 June 30 June
2019 2018
$ million $ million
====================================================
Revenue 11.8 18.3
Expenses (3.6) (7.4)
=========== ===========
Profit before tax 8.2 10.9
=========== ===========
Attributable tax charge (2.0) (2.6)
Gain on disposal 2.0 -
=========== ===========
Net profit attributable to discontinued operations 8.2 8.3
=========== ===========
During the period to completion, the Pakistan disposal group
contributed US$7.2 million (2018 1H: US$14.9 million) to the
Group's net operating cash flows and paid US$1.9 million (2018 1H:
US$1.5 million in respect of investing activities. There were no
financing cash flows in either the current or the prior period.
12. LEASES
Lease liabilities
$ million
======================================
At 1 January 2019 899.6
Revisions (note 8) 64.6
Finance costs 22.6
Cash outflows for lease arrangements (111.6)
Exchange differences (2.1)
At 30 June 2019 873.1
Classified as:
* Short-term 161.6
* Non-current 711.5
==================
Expenses related to both short-term and low value lease
arrangements are considered to be immaterial for reporting
purposes. During the period variable lease costs of US$7.6 million
were expensed. Lease liabilities have been classified as either
short-term or non-current in the balance sheet according to whether
they are expected to be settled within 12 months of the balance
sheet date.
The significant portion of the Group's lease liabilities
represent lease arrangements for FPSO vessels on the Catcher, Chim
Sáo and Huntington assets. The lease liabilities, and associated
right-of-use-assets have been calculated by reference to
in-substance fixed lease payments in the underlying agreements
incurred throughout the non-cancellable period of the lease along
with periods covered by options to extend the lease where the Group
is reasonably certain that such options will be exercised. When
assessing whether extension options were likely to be exercised,
assumptions were consistent with those applied when testing for
impairment.
Under the modified retrospective transition method, lease
payments were discounted at 1 January 2019 using an incremental
borrowing rate representing the rate of interest that Premier would
have to pay to borrow over a similar term, and with a similar
security, the funds necessary to obtain an asset of a similar value
to the right-of-use asset in a similar economic environment. The
incremental borrowing rate applied to each lease was determined by
taking into account the risk-free rate, adjusted for factors such
as the credit rating linked to the life of the underlying lease
agreement. The weighted average incremental borrowing rate applied
by Premier upon transition was 7.2 per cent. Incremental borrowing
rates applied to individual leases ranged between 5.4 per cent and
8.2 per cent.
13. SUBSEQUENT EVENTS
In July 2019, subsequent to the period end, the Group made a
further repayment of US$100 million of its RCF debt facility
reducing gross debt. The Group also cancelled US$233.5 million of
undrawn capacity of this facility, which will reduce commitment
fees going forward.
INDEPENT REVIEW REPORT TO PREMIER OIL PLC
Introduction
We have been engaged by the Company to review the condensed set
of financial statements in the half-yearly financial report for the
six months ended 30 June 2019 which comprises the interim condensed
consolidated income statement, the interim condensed consolidated
statement of comprehensive income, the interim condensed
consolidated balance sheet, the interim condensed consolidated
statement of changes in equity, the interim condensed consolidated
cash flow statement, and the related notes 1 to 13. We have read
the other information contained in the half-yearly financial report
and considered whether it contains any apparent misstatements or
material inconsistencies with the information in the condensed set
of financial statements.
This report is made solely to the Company in accordance with
guidance contained in International Standard on Review Engagements
2410 (UK and Ireland) "Review of Interim Financial Information
Performed by the Independent Auditor of the Entity" issued by the
Auditing Practices Board. To the fullest extent permitted by law,
we do not accept or assume responsibility to anyone other than the
Company, for our work, for this report, or for the conclusions we
have formed.
Directors' Responsibilities
The half-yearly financial report is the responsibility of, and
has been approved by, the Directors. The Directors are responsible
for preparing the half-yearly financial report in accordance with
the Disclosure Guidance and Transparency Rules of the United
Kingdom's Financial Conduct Authority.
As disclosed in note 1, the annual financial statements of the
Group are prepared in accordance with IFRSs as adopted by the
European Union. The condensed set of financial statements included
in this half-yearly financial report has been prepared in
accordance with International Accounting Standard 34, "Interim
Financial Reporting", as adopted by the European Union.
Our Responsibility
Our responsibility is to express to the Company a conclusion on
the condensed set of financial statements in the half-yearly
financial report based on our review.
Scope of Review
We conducted our review in accordance with International
Standard on Review Engagements (UK and Ireland) 2410, "Review of
Interim Financial Information Performed by the Independent Auditor
of the Entity" issued by the Auditing Practices Board for use in
the United Kingdom. A review of interim financial information
consists of making enquiries, primarily of persons responsible for
financial and accounting matters, and applying analytical and other
review procedures. A review is substantially less in scope than an
audit conducted in accordance with International Standards on
Auditing (UK) and consequently does not enable us to obtain
assurance that we would become aware of all significant matters
that might be identified in an audit. Accordingly, we do not
express an audit opinion.
Conclusion
Based on our review, nothing has come to our attention that
causes us to believe that the condensed set of financial statements
in the half-yearly financial report for the six months ended 30
June 2019 is not prepared, in all material respects, in accordance
with International Accounting Standard 34 as adopted by the
European Union and the Disclosure Guidance and Transparency Rules
of the United Kingdom's Financial Conduct Authority.
Ernst & Young LLP
London
21 August 2019
Glossary
Non-IFRS measures
The Group uses certain measures of performance that are not
specifically defined under IFRS or other generally accepted
accounting principles. These non-IFRS measures are EBITDAX, Cash
margin, Free cash flow, Operating cost per barrel, Depreciation,
depletion and amortisation per barrel, Net Debt and Liquidity and
are defined below.
-- EBITDAX: Earnings before interest, tax, depreciation,
amortisation, impairment, exploration expenditure and other one-off
items in the current period/year as allowed by the Group's
financing agreements. Determined by adjusting operating
profit/(loss) for the period/year. This is a useful indicator of
underlying business performance and is a key metric in the
calculation of one of our financial covenants.
-- Cash margin: Operating cash flow for the period/year divided
by working interest production. This is a useful indicator of cash
generation from the Group's producing assets.
-- Free cash flow: Positive cash flow generation from operating,
investing and financing activities excluding drawdowns from and
repayments of borrowing facilities.
-- Operating cost per barrel: Operating costs for the
period/year divided by working interest production. This is a
useful indicator of ongoing operating costs from the Group's
producing assets.
-- Depreciation, depletion and amortisation per barrel:
Amortisation and depreciation of oil and gas properties and
right-of-use assets for the period/year divided by working interest
production. This is a useful indicator of ongoing rates of
depreciation and amortisation of the Group's producing assets.
-- Net Debt: The net of cash and cash equivalents and long-term
debt recognised on the balance sheet. This is an indicator of the
Group's indebtedness and capital structure.
-- Liquidity: The sum of cash and cash equivalents on the
balance sheet, and the undrawn amounts available to the Group on
our principal facilities, including letter of credit facilities,
less our JV partners' share of cash balances. This is a key measure
of the Group's financial flexibility and ability to fund day to day
operations.
Each of the above non-IFRS measures are presented within the
Interim Report and Accounts with detail on how they are reconciled
to the statutory financial statements.
WORKING INTEREST PRODUCTION BY REGION (unaudited)
Six months Six months
to to
30 June 30 June
2019 2018
kboepd kboepd
UK:
Catcher 35.1 13.4
Balmoral Area(1) 1.5 1.6
Huntington 6.8 7.3
Solan 4.0 4.5
Kyle 1.4 1.6
Babbage(2) - 2.7
Elgin-Franklin 6.5 7.0
Other UK 2.8 3.2
============================= =============================
58.1 41.3
============================= =============================
Indonesia:
Natuna Sea Block A 11.1 12.8
Kakap(3) - 0.6
--------------------- ----------------------------- -----------------------------
11.1 13.4
--------------------- ----------------------------- -----------------------------
Vietnam:
Chim Sáo 12.4 16.2
12.4 16.2
Pakistan(4) :
Bhit/Badhra 0.8 1.8
Kadanwari 0.5 0.7
Qadirpur 1.0 2.0
Zamzama 0.2 0.8
============================= =============================
2.5 5.3
TOTAL 84.1 76.2
============================= =============================
(1) Includes Balmoral, Brenda, Nicol and Stirling fields.
(2) Babbage production included until completion of disposal
in December 2018.
(3) Kakap production included until completion of disposal in
April 2018.
(4) Pakistan production included until completion of disposal
in March 2019.
This information is provided by RNS, the news service of the
London Stock Exchange. RNS is approved by the Financial Conduct
Authority to act as a Primary Information Provider in the United
Kingdom. Terms and conditions relating to the use and distribution
of this information may apply. For further information, please
contact rns@lseg.com or visit www.rns.com.
END
IR CKDDNDBKBBFB
(END) Dow Jones Newswires
August 22, 2019 02:01 ET (06:01 GMT)
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