TIDMPMO
RNS Number : 6241Y
Premier Oil PLC
23 August 2018
Half-Year Results for the six months to 30 June 2018
Press Release
Tony Durrant, Chief Executive, commented:
"Premier met its operational targets for the period. The Catcher
Area is now at plateau production rates which, together with higher
commodity prices, is driving free cash flow generation and net debt
reduction. We have progressed our development projects while
maintaining strict capital discipline. We can also look forward to
a high-graded exploration and appraisal programme which has the
potential to deliver very significant value for the business."
Operational highlights
-- Production of 76.2 kboepd (2017 1H: 82.1 kboepd) reflecting
Catcher Area production ramp up offset by asset sales and natural
decline
-- Production averaged 86.2 kboepd in July (July 2017: 76.7
kboepd), despite ongoing summer maintenance
-- Catcher Area now at plateau production; day rates of up to 70 kboepd (gross) achieved
-- Tolmount project sanctioned post period end; key contracts awarded
-- Exploration acreage significantly enhanced with new licence awards in Mexico and Indonesia
-- Sale of Babbage Area announced; ETS (UK) and Kakap (Indonesia) disposals completed
Financial highlights
-- Profit after tax more than doubled to US$98.4 million (2017 1H: US$40.7 million)
-- EBITDA of US$388.9 million (2017 1H: US$325.9 million), up 19 per cent
-- Cash flows from operations of US$276.6 million (2017 1H: US$282.7 million)
-- Opex of US$17.2/boe, 5 per cent below budget
-- Net debt reduced to US$2.65 billion (2017: US$2.72 billion)
2018 Outlook
-- Production guidance unchanged at 80-85 kboepd
-- Forecast opex of US$17-US$18/boe and capex of US$380 million unchanged
-- Tolmount platform construction to start in December
-- Zama appraisal programme to commence in Q4
-- Completion of Pakistan and Babbage Area sales transactions
-- Forecast full year net debt reduction of US$300 to US$400
million with covenant leverage ratio expected to fall to 2.5x by
end Q1 2019, in line with previous guidance
Enquiries
Premier Oil plc Tel: 020 7730 1111
Tony Durrant, Chief Executive
Richard Rose, Finance Director
Camarco Tel: 020 3757 4980
Billy Clegg
Georgia Edmonds
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 again delivered a strong operational performance in the
first half of the year. The ramp up in production from the Catcher
Area (Catcher, Varadero and Burgman) and high uptime across our
other producing assets enabled us to maintain production at
year-end levels despite material asset sales. At the same time, we
remain focused on maintaining our low cost base and continued to
secure savings against budgeted expenditure.
The Catcher Area has been producing at plateau rates since May
which, along with higher commodity prices, resulted in a step
change in our production and our free cash flow generation,
substantially de-risking our debt reduction forecasts. We also see
the potential for considerable upside from the Catcher Area as a
result of better than expected initial production rates and the
opportunity to maintain and extend plateau production through
infill drilling and the tie-back of near field discoveries.
Premier remains focused on delivering the highest return
projects from its portfolio. The sanction of our operated Tolmount
Main gas project marks a major milestone. It secures our
medium-term UK production profile and realises further value from
the 2016 E.ON transaction. Tolmount Main is one of the largest
undeveloped gas discoveries in the Southern North Sea and, in
barrel of oil equivalent terms, is of similar size to our Catcher
Area. We have also secured an innovative financing structure for
the project which minimises our capital expenditure whilst
maintaining our exposure to the upside in the Greater Tolmount
Area. The development of the Bison, Iguana and Gajah Puteri (BIG-P)
gas fields, an incremental gas project in Indonesia, is also
proceeding well, on budget, and scheduled to deliver first gas next
year.
Beyond Tolmount Main and BIG-P, the portfolio contains a number
of projects to maintain and grow our production, delivering value
over the longer term. The first half saw us award Letters of Intent
(LOIs) to the key contractors for our Sea Lion project which, at
220 mmboe (gross) of reserves in Phase 1 alone, represents a
material opportunity for Premier. The focus for the second half
remains on securing senior debt funding for the project. In Mexico,
the programme for appraisal of our world-class Zama discovery is
scheduled to start later this year while in Indonesia we are
seeking to farm-down our interest in the Tuna discoveries ahead of
a two well appraisal programme. The majority of the spend for these
projects will be from 2020 by which time we will have restored
balance sheet strength after a period of forecast material free
cash flow generation.
Over the last few years we have re-focused our exploration
portfolio on high-graded proven petroleum systems in emerging
basins. This resulted in the Zama discovery last year and will see
us drill the high value Tolmount East well in 2019 and two
potential high impact wells in the Ceará Basin, offshore Brazil,
targeted for 2020. We have also continued to enhance and replenish
our exploration portfolio for future drilling. We were particularly
excited to capture Block 30, south west of our Zama discovery, in
Mexico's Round 3.1, and the Andaman II licence offshore Indonesia
where we see the potential for over 2 TCF of gas.
Potential acquisition opportunities that enhance our asset base
and create synergies with our existing core businesses continue to
be evaluated while our non-core disposal programme progressed over
the period. In April we announced the sale of our interests in the
Babbage Area which will immediately reduce our net debt and our
committed exploration spend in 2019. We also completed the disposal
of our interests in Kakap, offshore Indonesia, and the Esmond
Transportation System (ETS) in the North Sea.
Debt reduction remains our key corporate priority in the
near-term. We anticipate considerable debt reduction for the full
year 2018 of US$300 to US$400 million, driven by increasing cash
flow generation from our producing portfolio, cash proceeds from
announced disposals and the early exchange of the convertible bond.
As a result, at current oil prices, we anticipate our covenant
leverage ratio falling to 3x EBITDA by the year-end and to 2.5x by
the end of the first quarter of 2019.
Health, Safety, Environment and Security (HSES) matters will
always be of paramount importance to us. We will not compromise on
the integrity and safety of our people and our operations and we
continue to set ourselves challenging HSES targets to drive
continuous improvement.
OPERATIONAL REVIEW
GROUP PRODUCTION
Group production for the first half averaged 76.2 kboepd (2017
1H: 82.1 kboepd) with new production from the Catcher Area and
outperformance from the Chim Sáo field in Vietnam offset by asset
sales, natural decline and the re-phasing of planned maintenance
into the first half. Post period end, production averaged 86.2
kboepd in July (2017 July: 76.7 kboepd) reflecting strong
production from the Catcher Area and despite ongoing summer
maintenance elsewhere in the portfolio.
Premier's full year production guidance of 80-85 kboepd remains
unchanged with completion of the sale of the Pakistan business and
the Babbage Area assets expected later this year.
kboepd 2018 1H 2017 1H
Indonesia 13.4 14.2
Pakistan 5.3 6.8(1)
UK 41.3 45.6
Vietnam 16.2 15.5
Total 76.2 82.1
(1) Includes 335 boepd from the Chinguetti field in Mauritania
which ceased production in December 2017
UNITED KINGDOM
Premier's UK operations delivered increasing operating cash
flows in the first half of the year driven by new Catcher Area
production and higher commodity prices. The Catcher Area reached
contracted plateau production rates in May, increasing delivery
capacity from Premier's UK assets to in excess of 60 kboepd (net).
Post period end, the Tolmount project was sanctioned with first gas
scheduled for 2020. Production from the UK is expected to average
around 50 kboepd (net) over the next five years with new Catcher
Area and Tolmount production offsetting natural decline from
elsewhere in the UK portfolio.
Catcher Area
Premier's operated Catcher Area averaged 26.6 kboepd (gross) for
the first half, reflecting constrained production as commissioning
of the gas and the water injection plants was completed. The
Catcher Area reached contracted plateau production rates of 60
kbopd (gross) in May with day rates of up to 70 kboepd (gross)
having been achieved post period end. Plant availability has
continued to increase as commissioning of the secondary systems
completes.
Production data from the Catcher Area continues to demonstrate
good pressure support and connectivity between the reservoirs.
Delivery potential from the available wells remains significantly
in excess of the FPSO design capacity. As a result, preliminary
discussions have started with the FPSO provider BW Offshore about
sustaining production rates above the currently contracted 60 kbopd
(gross).
Post period end, the DSV Falcon successfully tied into
production four additional wells, further increasing deliverability
from the Catcher Area. The 17th well, a Burgman producer, was
completed in August with the 18th well, also a Burgman producer,
scheduled to complete in October. These two wells will be available
for production by November. This will mark completion of the
current phase of the Catcher Area development.
Premier has identified several near field discoveries as
potential high value subsea tie-backs to the Catcher Area FPSO to
maintain and extend plateau production. In particular, the
development concepts for the Laverda and Catcher North oil
accumulations have been selected and will comprise two development
wells drilled from a common drill centre tied back to the Varadero
manifold. Project sanction is targeted for the first quarter of
2019.
In addition, Premier has identified potential infill well
locations targeting resources beyond the reach of the initial
production wells. Premier also plans to acquire 4D seismic to help
define future infill drilling locations.
In February, Premier was awarded two blocks adjacent to the
Catcher Area in the UK 30th Offshore Licensing Round. One of the
blocks lies to the south of the Catcher field and contains the
Bonneville discovery, a potential future tie-back to the Catcher
Area infrastructure.
Other UK producing fields
Huntington production averaged 7.3 kboepd during the period,
reflecting natural decline in line with expectations and planned
shutdowns. Post period end, a light well intervention vessel was
mobilised in field to carry out the first phase of converting a
former production well into a water injection well to increase
reservoir pressure and enhance recovery from the field. The
conversion will be finalised with modifications to the subsea
pipework in the fourth quarter of this year. This, together with
the underlying reservoir performance of the field, has resulted in
Premier agreeing commercial terms with Teekay to extend the
Huntington Voyageur FPSO contract by a further year to mid-April
2020. At the end of July the field closed for summer maintenance.
The programme includes modifications to the FPSO to enable gas
import to increase operational efficiency. Production is on track
to restart at the end of August.
The Elgin-Franklin Area produced 7 kboepd during the first six
months of the year. This was ahead of expectations as the area
benefited from a new production well coming on-stream in January
and flush production following the extended Forties Pipeline System
shutdown at the end of 2017.
Production from Premier's operated Solan field averaged 4.5
kboepd. This was driven by high operating efficiency offset by a
planned shutdown being accelerated from July to June. Premier
continues to plan for a 2020 infill drilling programme to improve
recovery of reserves from the Central Northern part of the Solan
field. The programme will entail a new producer-injector pair
targeting known thicker sands in the adjacent Northern Fault
Terrace, up dip from an existing water injector (W1). The new
producer (P3) will be tied back to existing subsea infrastructure
while the injector will be drilled as a side track from W1.
Alternative financing strategies for this programme are under
consideration and an investment decision is scheduled for the
fourth quarter of 2018.
As a result of higher commodity prices, cost control and asset
performance, field life has been extended at Premier's operated
Balmoral Area as well as at the Kyle field where Premier has a
non-operated 40 per cent interest. Premier anticipates that
cessation of production from the Balmoral Area will now be no
earlier than 2021 while at the Kyle field CNR and Teekay have
agreed to extend the lease of the Banff FPSO, which handles Kyle's
production, to August 2019.
The Greater Tolmount Area
Post period end, the development of the initial phase of the
Greater Tolmount Area (Tolmount Main) in the Southern Gas Basin was
sanctioned by the joint venture and infrastructure partners. The
Premier-operated Tolmount Main field will produce around 500 Bcf
(96 mmboe) (gross) of gas with peak production of up to 300 mmscfd
(58 kboepd) (gross).
The Tolmount Main development will entail a minimal facilities
platform and a new gas export pipeline to shore. The EPCIC
(Engineering, Procurement, Construction, Installation and
Commissioning) contract was awarded to Rosetti Marino, who are now
placing the contracts for the long lead items. This includes the
award of the contract for the transportation and installation of
the platform to Heerema. First steel for the platform will be cut
in December 2018. Sailaway of the platform from Rosetti's Ravenna
yard in Italy is scheduled for the second quarter of 2020 with
offshore installation of the platform planned for mid-2020.
Commercial agreements have been signed with Centrica Storage
Limited for upgrades to the Easington terminal and for the
processing of Tolmount gas. The Easington terminal was selected as
the host facility after the reclassification of Rough as a
producing field, rather than a storage facility, resulted in gas
processing capacity being made available at Easington on
competitive terms. Saipem has been selected as the pipeline EPCI
contractor. Landfall construction will start over the winter of
2019/2020 in anticipation of the offshore pipelay campaign in the
second half of 2020. Ensco has been awarded an LOI for the
development drilling programme comprising four development wells
with the first well scheduled to come on-stream in the fourth
quarter of 2020.
In an innovative financing structure, Premier's share of the
capex required to develop this large gas field is estimated at only
US$120 million, comprising project management and development
drilling costs. The infrastructure joint venture between Humber
Gathering System Limited (a member of the CATS Management Limited
group of companies) and Dana Petroleum will own and pay for the
platform and pipeline capex as well as pay for upgrades to the
onshore terminal. In return, Premier will pay a tariff for the
transportation and processing of Tolmount gas through the
infrastructure. This arrangement significantly enhances Premier's
future returns from the project.
Significant upside exists within the Greater Tolmount Area.
Premier plans to drill the Tolmount East appraisal well, which is
targeting 220-400 Bcf (Pmean to P10) (gross) of additional gas
resource, in mid-2019. The aim of the well is to test the Eastern
extension of the Tolmount field area that sits above the gas water
contact but is structurally separated from Tolmount Main and viewed
as low risk. It is anticipated that the well will be suspended for
use as a future producer which would be tied back to Tolmount Main
infrastructure. Furthermore, a successful Tolmount East appraisal
could facilitate the tie-back of the existing Mongour discovery, in
which Premier also has a 50 per cent interest.
Premier plans to acquire 3D seismic across the Greater Tolmount
Area in 2019 to enable maturation of the Tolmount Far East well
location with a view to drilling the prospect in 2021. This could
potentially add a further 150 Bcf (gross) of resource and would
likely be developed as a subsea tie-back to the Tolmount Main field
facilities via Tolmount East.
Portfolio management
In April, Premier announced the sale of its interests in the
Babbage Area to Verus Petroleum. Production from the Babbage Area
averaged 2.7 kboepd during the period. Premier expects to receive
net cash proceeds of US$64.3 million, before customary working
capital adjustments. Verus will also take on exploration
commitments estimated at US$23.8 million. Completion of the
transaction is expected in the fourth quarter of 2018. In addition,
Premier completed the previously announced sale of its 30 per cent
non-operated interest in ETS for total cash proceeds of US$22.9
million (after working capital adjustments). There is also a future
potential payment of up to US$3.5 million linked to the achievement
of certain key milestones in respect of any future development of
the nearby Pegasus field.
INDONESIA
Production from Premier's operated Natuna Sea Block A fields
averaged 12.8 kboepd (net), in line with the prior period and
expectations. The development of BIG-P continues and remains on
budget and to schedule for first gas in 2019. Continued low
operating costs resulted in the Indonesian Business Unit generating
material positive net cash flows for the Group.
Production
Production from Indonesia in the first half of 2018 was 13.4
kboepd (net) (2017 1H: 14.2 kboepd). The Premier-operated Natuna
Sea Block A delivered 12.8 kboepd (net) (2017 1H: 12.9 kboepd)
while production from the non-operated Kakap field (now sold)
averaged 0.6 kboepd (net).
Singapore demand for gas sold under GSA1 averaged 269 BBtud
(gross) (2017 1H: 301 BBtud), a reduction on the prior
corresponding period as a result of the re-phasing of end-buyer
maintenance into the first half of the year from the second half.
Premier's Anoa and Pelikan fields delivered 144 BBtud (gross) (2017
1H: 149 BBtud (gross)) during the period and accounted for 53 per
cent of GSA1 deliveries (2017 1H: 49 per cent), an increased market
share on the prior period and above Natuna Sea Block A's
contractual share of 52 per cent.
Sales of Gajah Baru and Naga gas dedicated to GSA2 averaged 88
BBtud (gross) (2017 1H: 85 BBtud). Gross liquids production from
the Anoa field was 1.2 kbopd (2017 1H: 1.1 kbopd).
Gas sales from the non-operated Kakap field averaged 7 BBtud
(gross) (2017 1H: 18 BBtud (gross)) while gross liquids production
was 1.4 kbopd (2017 1H: 2.6 kbopd). The reduction on the prior
corresponding period reflects the sale of Kakap to Batavia Oil for
US$3.2 million, before working capital adjustments, which completed
in April.
Premier continues to benefit from a low cost base in Indonesia
with operating costs averaging US$6.8/boe for the period.
Development
The development of BIG-P is proceeding to schedule and on
budget. Onshore fabrication of the Naga and Pelikan deck extensions
and the Pelikan and AGX platform spools was completed in the Batam
yard in July and offshore installation has commenced with numerous
service vessels in field.
The offshore installation campaign, including the installation
of the deck extensions at Naga and Pelikan and the topsides
components of the subsea control system at Gajah Baru and Anoa,
will be completed by the end of the third quarter.
Fabrication of the subsea structures will commence in September.
They will be installed along with the flowlines, flexible risers
and umbilicals during the second offshore installation campaign
planned to begin in the second quarter of 2019. A DSV will then
complete the final hook up and tie-ins over the summer of 2019.
Drilling of the BIG-P development wells will commence in the
first half of 2019 ahead of first gas which remains on schedule for
the third quarter of 2019. Once on-stream, the BIG-P gas fields
will help backfill the Group's contracts into Singapore and
maintain production from Natuna Sea Block A.
Exploration and appraisal
Premier and its joint venture partners have agreed, subject to
contract, a farm-in offer to the Tuna PSC ahead of a two well
appraisal campaign targeted for 2019. In addition, further seismic
evaluation of the associated prospects and leads on the remainder
of the Tuna PSC provide an opportunity to add further value once
the Tuna field is developed.
In January 2018, Premier was awarded a 40 per cent operated
interest in the Andaman II licence in North Sumatra basin offshore
Aceh, Indonesia. Premier has identified numerous prospects and
leads which exhibit direct hydrocarbon indicators on existing 2D
seismic across the licence. Premier is in discussions with seismic
contractors with a view to initiating the acquisition of 1,850
square kilometres of 3D seismic across the licence. The forward
plan is to mature these prospects, ahead of possible drilling in
2021. The licence has the potential to deliver significant gas
volumes into North Sumatra and adds a potentially material new gas
play to Premier's Indonesian portfolio.
On Natuna Sea Block A, the exploration team is reprocessing
existing Anoa 3D datasets and analysing production data from the
WL-5X well to assess the ultimate potential of the Lama play
beneath the Anoa field and also to identify potential infill
drilling locations within the Anoa main field.
VIETNAM
Chim Sáo has maintained high levels of production during the
period averaging 16.2 kboepd and generating material free cash flow
for the Group. Post period end, the Chim Sáo field lifted its 200th
cargo of oil, with every cargo since first oil having been sold at
a premium to Brent.
Production
Production from the Premier-operated Block 12W, which contains
the Chim Sáo and Dua fields, averaged 16.2 kboepd (2017 1H: 15.5
kboepd) net to Premier, up on the prior corresponding period and
ahead of budget. This strong performance was underpinned by the
successful infill drilling campaign in 2017, which completed in
December, and a two well intervention programme during the first
six months of the year which brought on-stream new reservoir zones
within existing wells adding over 1 kboepd (gross) of production.
Two more well intervention campaigns are planned for the third
quarter aimed at offsetting the natural decline from the existing
wells. Operating efficiency was also high for the period at 94 per
cent while underlying reservoir performance continues to exceed
expectations.
Vietnam operating costs remain low and stable at US$9.6/boe
(2017 1H: US$9.0/boe) and below budget. This, together with the
robust production performance and the continuing premiums to the
Brent oil price commanded by Chim Sáo crude, resulted in the
Vietnam Business Unit contributing gross operating cash flow of
over US$100 million during the period.
THE FALKLAND ISLANDS
The focus for the period has been on securing LOIs with key
contractors and progressing the funding structure for the
project.
Sea Lion
The Sea Lion project represents a material opportunity for the
Group with around 400 mmboe (net to Premier) to be developed over
several phases. The initial phase, Sea Lion Phase 1, will
commercialise 220 mmbbls (gross) in PL032. The development concept
entails subsea wells tied back to a leased FPSO. Premier plans to
leverage the knowledge and skills successfully deployed on the
Catcher Area project, as well as more generally its track record of
developing medium sized offshore oil fields using FPSOs, to deliver
the Sea Lion project.
Premier is in the process of completing the selection of
contractors and has put in place LOIs for the provision of key
services, including an FPSO, the drilling rig, well services, SURF,
subsea production systems and installation services and helicopter
services, as well as vendor funding.
The focus for the second half of the year remains on securing
senior debt funding for the project, ahead of a final investment
decision.
PAKISTAN
Premier's Pakistan business continued to generate positive net
cash flow during the period. The average realised gas price was
US$3.2/mscf while operating costs remained low at US$0.78/mscf
(US$4.9/boe).
Net production averaged 5.3 kboepd (33.4 mmscfd) (2017 1H: 6.5
kboepd (40.1 mmscfd)) from Premier's six non-operated producing gas
fields. The fall in production reflects natural decline in all of
the gas fields.
Completion of the US$65.6 million sale of Premier's Pakistan
business to Al-Haj Group remains subject to final approvals from
the Pakistan authorities. To date, Al-Haj has paid deposits of
US$25 million and Premier continues to collect the positive cash
flows generated from these assets.
EXPLORATION AND APPRAISAL
Premier's exploration team continues to focus its efforts on
high-graded proven petroleum systems in emerging basins which have
the potential to deliver material resource additions for the Group
whilst maintaining strict capital discipline.
MEXICO
In Mexico, pre-unitisation terms have been agreed by all
potential partners in the field. The Block 7 appraisal programme
has also been agreed with final government approval expected
shortly. As a result, the appraisal of the Zama discovery in Block
7 is scheduled to commence in the fourth quarter of this year. The
appraisal programme will comprise two back-to-back wells and one
side track with the objective to confirm the oil water contact as
defined by the seismic flat spot and to prove the detailed
distribution of the reservoir. Premier also plans to carry out a
comprehensive logging and coring programme as well as to flow test
the side track of the first Zama appraisal well. Maturation of low
risk, high value tie-back opportunities elsewhere on Block 7
remains ongoing.
In March, Premier successfully participated in Mexico's Round
3.1. Premier, together with its joint venture partners (DEA and
Sapura), secured Block 30 which is directly to the south west of
Premier's Zama discovery in the prolific, shallow water Sureste
Basin. The forward plan includes block wide 3D seismic acquisition,
including across the Wahoo prospect, which exhibits a flat spot
analogous to the Zama discovery, and the Cabrilla prospect.
Drilling activities are targeted to start before the end of
2020.
In Round 3.1, Premier also secured Blocks 11 and 13 in the
Burgos Basin, which is directly inshore from the deep water Perdido
fold belt. Premier will undertake an environmental base line study
across its two new blocks prior to reprocessing the existing 3D
seismic data during 2019.
On Block 2 in the Sureste Basin, Premier's option to participate
and convert to a paying interest of up to 25 per cent equity or to
withdraw was triggered in May 2018. Premier has decided to exit the
block ahead of drilling.
BRAZIL
In Brazil, Premier is focussed on the Ceará Basin where it has
developed an industry leading database and knowledge to maximise
its chances of delivering a significant discovery. During the
period, the ANP approved a revised well plan for Block 717
(Premier, 50 per cent operator), comprising a single deeper
dual-target well to test the Berimbau and deeper Maraca prospects.
This replaces the original two well commitments associated with
Block 717. On Block 661, the joint venture partnership (Premier, 30
per cent) plans to target the stacked reservoir Itarema/Tatajuba
prospect. The forward plan is to fulfil the remaining single well
commitments on Blocks 717 and 661 via a two well drilling programme
in the first half of 2020. The two wells will test an aggregate
mean resource estimate in excess of 500 mmbbls (gross,
unrisked).
FINANCIAL REVIEW
Context
2018 has seen a general improvement in the macro-economic
environment for the sector, albeit with continued oil price
volatility being observed in the period. Brent crude opened the
year at US$66.9/bbl before closing at US$77.9/bbl on 30 June 2018.
The average for 2018 1H was US$70.6/bbl compared to US$51.7/bbl for
the corresponding period in 2017.
Against this economic backdrop our production averaged 76.2
kboepd in the period, (2017 1H: 82.1 kboepd), representing a
reduction when compared to the corresponding prior period due to
asset sales, natural field decline and planned shutdowns, partially
offset by production from the Catcher field. This has resulted in
total sales revenue from all operations of US$643.3 million
compared with US$566.3 million in 2017 1H. Following the ramp up of
Catcher production, recent Group production rates have been in
excess of 90 kboepd.
Business performance
EBITDA for the period from continuing operations was US$388.9
million compared to US$325.9 million for 2017 1H. The increased
EBITDA is mainly due to higher average oil and gas prices realised
during the period offsetting lower production. With higher
production forecast in 2018 2H as Catcher production reaches
plateau, at current oil prices EBITDA is expected to increase
significantly in the second half of this year.
Business performance (continuing operations) 2018 2017
Half-year Half-year
$ million $ million
Operating profit 185.5 141.4
Add: Amortisation and depreciation 185.6 180.5
Add: Exploration expense and pre-licence
costs 7.4 4.0
Add: Loss on disposal of assets 10.4 -
EBITDA 388.9 325.9
Income statement
Production and revenue
Group production on a working interest basis averaged 76.2
kboepd for the period compared to 82.1 kboepd in 2017 1H, due to
asset sales and natural field decline. First half production was
also impacted by planned shutdowns at the Huntington and Solan
fields and lower Singapore gas demand due to end-buyer maintenance.
This was offset by the ramp up of Catcher production and
outperformance from the Chim Sáo field. Entitlement production for
the period was 69.2 kboepd (2017 1H: 76.1 kboepd). Post hedging,
Premier realised an average price for the period of US$61.6/bbl
(2017 1H: US$49.9/bbl) vs a Brent average price of US$70.6/bbl
(2017 1H: US$51.7/bbl).
In the UK, Premier achieved average natural gas prices of 49
pence/therm (2017 1H: 46 pence/therm), which included 39.4 million
therms which were sold under fixed price master sales agreements.
Gas prices in Singapore, indirectly linked with crude oil pricing,
averaged US$9.7/mscf (2017 1H: US$8.6/mscf) post hedging.
Total sales revenue from all operations (including Pakistan)
increased to US$643.3 million (2017 1H: US$566.3 million),
primarily due to the increase in realised oil and gas prices in the
period offsetting lower production. From continuing operations
(excluding Pakistan), revenue increased to US$625.0 million
compared to US$546.1 million in the prior period.
Operating costs
Cost of operations comprise operating costs, changes in lifting
positions, inventory movement and royalties. Cost of operations for
the Group was US$231.6 million for 2018 1H, compared to US$218.8
million for 2017 1H.
2018 2017
Half-year Half-year
$ million $ million
Operating costs
Continuing operations 232.5 214.0
Discontinuing operations (Pakistan) 4.7 4.4
------------------------------------- ----------- -----------
Operating costs (US$ million) 237.2 218.4
=========== ===========
Operating cost per barrel (US$ per
barrel) 17.2 14.7
------------------------------------- ----------- -----------
Amortisation and depreciation of
oil and gas properties
=========== ===========
Continuing operations 180.8 177.3
Discontinuing operations (Pakistan) - 7.3
------------------------------------- ----------- -----------
Total (US$ million) 180.8 184.6
DD&A per barrel (US$ per barrel) 13.1 12.4
------------------------------------- ----------- -----------
The increase in absolute operating costs reflects commencement
of production from the Catcher field towards the end of 2017. On a
per barrel basis, operating costs increased compared to the prior
period but were 5 per cent lower than budget. The increase was
primarily due to the commencement of FPSO payments for Catcher
whilst production was constrained in the period as final facilities
commissioning was being completed.
Exploration expenditure and pre-licence costs
Exploration expense and pre-licence expenditure costs amounted
to US$7.4 million (2017 1H: US$4.0 million) primarily relating to
historical costs incurred on the Block 2 licence in Mexico and the
Sunbeam prospect in the UK. After recognition of these
expenditures, the exploration and evaluation asset remaining on the
balance sheet at 30 June 2018 amounts to US$1,081.3 million (31
December 2017: US$1,061.9 million) which includes the Sea Lion,
Tolmount and Tuna projects, as well as our share of expenditure on
the Zama prospect in Mexico.
General and administrative expenses
Net G&A costs have fallen for 2018 1H to US$3.0 million
(2017 1H: US$4.0 million) due to ongoing cost control and overhead
allocation.
Finance gains and costs
Net finance costs of US$210.2 million have increased compared to
the prior year (US$145.0 million), principally due to a step up in
the interest margin on our financing facilities following the
completion of the refinancing in July 2017 and an increase in the
fair value of the Group's outstanding equity and synthetic warrants
to US$100.7 million from US$59.8 million at 31 December 2017 as a
result of strong share price performance. Cash interest expense in
the period was US$125.5 million (2017 1H: US$89.7 million).
Taxation
The Group has a current tax charge for the period of US$46.5
million (2017 1H: charge of US$28.7 million) and a non-cash
deferred tax credit for the period of US$161.3 million (2017 1H:
credit of US$68.9 million) which results in a total tax credit for
the period of US$114.8 million, from continuing operations (2017
1H: credit of US$40.2 million).
The total tax credit for the period represents an effective tax
rate of 464.8 per cent (2017 1H: negative 1,116.7 per cent). The
high 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.
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 2017 on the basis
that there have been no impairment triggers identified at the
balance sheet date of 30 June 2018.
Profit after tax
Profit after tax for the period was US$98.4 million (2017 1H:
profit of US$40.7 million), including US$8.3 million from the
Pakistan Business Unit which is classified as a discontinued
operation at the balance sheet date, resulting in a basic earnings
per share of 13.2 cents (2017 1H: 8.0 cents).
Cash flow
Cash flow from operating activities was US$224.6 million (2017
1H: US$292.0 million) after accounting for tax payments of US$62.5
million (2017 1H: US$44.0 million) and movement in joint venture
cash balances in the period of US$52.0 million. Before the movement
in the joint venture cash balances, underlying operating cash flows
were US$276.6 million.
Capital expenditure in the period to 30 June 2018 totalled
US$164.3 million (2017 1H: US$129.8 million).
Capital expenditure 2018 2017
Half-year Half-year
$ million $ million
Field/development projects 137.9 106.6
Exploration and evaluation 25.8 22.9
Other 0.6 0.3
Total 164.3 129.8
The principal development project was the Catcher field in the
UK. The largest part of the E&E capital expenditure in the
period was the signature bonus for the Block-30 exploration licence
in Mexico. In addition, cash expenditure for decommissioning
activity in the period was US$45.1 million (2017 1H: US$6.3
million). Further to this, US$9.8 million of cash was funded into
long-term abandonment accounts for future decommissioning
activities (2017 1H: US$7.8 million).
Discontinued operations, disposals and assets held for sale
In April 2018, Premier entered into a sale and purchase
agreement (SPA) to sell its interest in the Babbage Area to Verus
Petroleum SNS Limited (Verus) for GBP62.9 million (US$88.1
million). In addition, Verus will take on exploration commitments
valued at GBP17 million (US$23.8 million), resulting in net cash
proceeds of GBP45.9 million (US$64.3 million) to Premier, before
customary working capital adjustments. Further cash payments of up
to GBP5.5 million (US$7.7 million) are due to Premier if the Cobra
discovery is developed. The effective date of the transaction is 1
January 2018. Disposal proceeds will be used to pay down Premier's
existing debt. Completion of the transaction is expected in 2018
2H. Accordingly, the assets and liabilities of the Babbage Area
interests have been classified as assets held for sale on the
balance sheet at 30 June 2018.
During the period, Premier completed the previously announced
sales of its interests in the Kakap field and its 30 per cent
non-operated interest in the Esmond Transportation System (ETS) for
total cash proceeds of US$22.8 million (after working capital
adjustments).
Completion of the sale of Premier's Pakistan business to Al-Haj
Group remains subject to final approvals from the Pakistan
authorities. In the meantime, Premier continues to collect the
positive cash flows generated from these assets. The disposal of
the Pakistan Business Unit is expected to complete in the second
half of 2018 and, as this is within 12 months of the balance sheet
date, the business unit remains classified as a disposal group held
for sale and presented separately in the balance sheet. Results for
the disposal group in both the current and prior periods have been
presented as a discontinued operation.
Balance sheet position
Net Debt
Accounting net debt at 30 June 2018 amounted to US$2,652.7
million (31 December 2017: US$2,724.2 million), with cash resources
of US$180.0 million (31 December 2017: US$365.4 million).
Following completion of the Wytch Farm disposal in December
2017, net cash proceeds received of US$176 million were used to pay
down and cancel the equivalent value of the RCF debt facility in
January 2018. This reduced the total available RCF facility from
US$2,050 million to US$1,874 million.
In January 2018, Premier invited convertible bondholders to
exercise their exchange rights in respect of any and all of their
bonds. 87.5 per cent or US$205.8 million of the US$235.2 million
bonds outstanding were accepted for early exchange with an
incentive amount of US$50 per US$1,000 in principal of bonds. The
exchange resulted in the issue of 231,882,091 Ordinary Shares,
which included 7,578,343 incentive shares. This resulted in a
convertible bond liability of US$27.8 million on the balance sheet
at 30 June 2018.
Subsequent to the period end, Premier announced its intention to
exercise the mandatory conversion option in its convertible bonds.
The exercise of such option will automatically and mandatorily
convert all of the US$28.8 million outstanding convertible bonds
into approximately 31.4 million new Ordinary Shares of Premier.
Premier retains significant cash at 30 June 2018 of US$147.6
million and undrawn facilities of US$156.1 million, giving
Liquidity of US$303.7 million (31 December 2017: US$541.2 million)
when excluding cash of US$32.4 million held on behalf of joint
venture partners.
Provisions
Total decommissioning provisions excluding those associated with
assets held for sale at 30 June 2018 are US$1,339.1 million (31
December 2017: US$1,432.1 million). The reduction is driven by
decommissioning expenditure during the period and the
reclassification of the decommissioning provision associated with
the Babbage Area.
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
Financial Review are EBITDA, Operating cost per barrel, DD&A
per barrel, Net Debt and Liquidity and are defined in the
glossary.
Financial risk management
Commodity prices
Premier continues to take advantage of the improved oil price
environment to increase its hedging position in 2019 to protect
future free cash flows and covenant compliance. The Company's
current hedge position to the end of 2019 is as follows:
Oil swaps/forwards 2018 2H 2019 1H 2019 2H
-------- --------
Volume (mmbbls) 4.0 2.6 1.5
Average price $60/bbl $66/bbl $69/bbl
-------------------- -------- -------- --------
At 30 June 2018, the fair value of the open oil swaps was a
liability of US$81.8 million (31 December 2017: liability of
US$31.7 million), which is expected to be released to the income
statement during 2018 2H and 2019 as the related barrels are
lifted.
Furthermore, the Group has open oil put option agreements for
0.7 mmbbls at an average price of US$60.5/bbl. These options will
be settled during 2018 2H. Included within physically delivered oil
sales contracts are 0.8 mmbbls of oil that will be sold for an
average fixed price of US$51.2/bbl during 2018 2H and 2019 as these
barrels are delivered (these volumes are included in the above
table). In addition, the Group currently has forward UK gas sales
of 46 mm therms at an average price of 51 pence/therm that will be
physically settled during 2018 2H and 2019 1H.
After the period end, Premier hedged part of its Indonesian gas
production through the sale of 120,000 MT of HSFO Sing 180 in 2019
at an average price of US$394/MT.
Foreign exchange
Premier's functional and reporting currency is US dollars.
Exchange rate exposures relate only to local currency receipts and
local currency 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 loss of US$3.7 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, convertible bonds, UK retail bonds, term loans and
revolving credit facilities. As 30 June 2018, approximately 49 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
7.1 per cent. Mark-to-market gains on interest rate swaps amounted
to US$1.0 million.
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.
At 30 June 2018 the Group continued to have significant headroom
on its financing facilities and cash on hand. The Group's forecasts
show that, at currently observed oil and gas prices and prevailing
production, the Group will have sufficient financial headroom for
the 12 months from the date of approval of the 2018 Interim Report
and Accounts. In downside scenarios where oil and gas prices were
to remain materially below those currently being realised and if
production levels were to be significantly below current
performance then, in the absence of any mitigating actions, a
breach of one or more of the financial covenants may arise during
the 12 month going concern assessment period. Potential mitigating
actions could include further non-core asset disposals, additional
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 has identified its principal risks, which have not
changed since 31 December 2017, for the remaining 6 months of the
year as being:
-- Oil price weakness and volatility.
-- Underperformance of existing assets.
-- Failure of new Catcher asset to fully deliver to
expectations.
-- Execution of planned corporate actions.
-- Ability to fund existing and planned growth projects.
-- Breach of new banking covenants if oil prices fall or assets
underperform.
-- Ability to maintain core competencies.
-- Timing and uncertainty of decommissioning liabilities.
-- Political and security instability in countries of current
and planned activity.
-- Rising costs if oil prices recover could limit access to
services.
Further information detailing the way in which these risks are
mitigated is provided on pages 22 to 29 of the 2017 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
2018 2017
Unaudited Unaudited
Note $ million $ million
============================================= ==== =========== ============
Continuing operations
Sales revenues 2 625.0 546.1
Other operating (costs)/income (1.5) 2.6
Costs of operation 3 (231.6) (218.8)
Depreciation, depletion and amortisation (185.6) (180.5)
Exploration expense and pre-licence
costs 7 (7.4) (4.0)
Loss on disposal of non-current assets 11 (10.4) -
General and administration costs (3.0) (4.0)
============================================= ==== =========== ============
Operating profit 185.5 141.4
Interest revenue, finance and other
gains 4 3.8 9.2
Finance costs, other finance expenses
and losses 4 (214.0) (154.2)
Loss before tax (24.7) (3.6)
Tax 5 114.8 40.2
============================================= ==== =========== ============
Profit for the period from continuing
operations 90.1 36.6
Discontinued operations
Profit for the period from discontinued
operations 11 8.3 4.1
============================================= ==== =========== ============
Profit after tax 98.4 40.7
============================================= ==== =========== ============
Earnings per share (cents):
From continuing operations
Basic 6 12.1 7.2
Diluted 6 10.4 7.0
From continuing and discontinued operations
Basic 6 13.2 8.0
Diluted 6 11.4 7.8
============================================= ==== =========== ============
Notes 1 to 12 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
2018 2017
Unaudited Unaudited
$ million $ million
======================================== =========== ===========
Profit for the period 98.4 40.7
----------------------------------------- ----------- -----------
Cash flow hedges on commodity swaps:
(Losses)/gains arising during the
period (88.4) 9.9
Less: reclassification adjustments
for losses in the period 36.4 6.7
========================================= =========== ===========
(52.0) 16.6
Cash flow hedges on interest rate
and foreign exchange swaps
Gains/(losses) arising during the
period 8.6 (19.6)
Less: reclassification adjustments
for (gains)/losses in the period (3.9) 21.0
========================================= =========== ===========
4.7 1.4
======================================== =========== ===========
Tax relating to components of other
comprehensive income 16.2 (6.6)
Exchange differences on translation
of foreign operations (7.6) (1.1)
Other comprehensive (expense) / income (38.7) 10.3
Total comprehensive income for the
period 59.7 51.0
========================================= =========== ===========
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
2018 2017
Unaudited Audited
Note $ million $ million
======================================= ==== ========== =============
Non-current assets:
Intangible exploration and evaluation
assets 7 1,081.3 1,061.9
Property, plant and equipment 8 2,177.5 2,381.0
Goodwill 240.8 240.8
Long-term receivables 165.1 160.8
Deferred tax assets 1,619.9 1,461.5
======================================= ==== ========== =============
5,284.6 5,306.0
======================================= ==== ========== =============
Current assets:
Inventories 18.5 13.5
Trade and other receivables 307.0 340.6
Derivative financial instruments 10 14.3 14.5
Cash and cash equivalents 180.0 365.4
Assets held for sale 11 64.8 96.6
584.6 830.6
Total assets 5,869.2 6,136.6
======================================= ==== ========== =============
Current liabilities:
Trade and other payables (310.7) (572.9)
Short-term provisions (61.9) (91.2)
Derivative financial instruments 10 (209.4) (99.8)
Deferred income (14.4) (13.1)
Liabilities directly associated with
assets held for sale 11 (58.3) (46.6)
(654.7) (823.6)
Net current (liabilities)/assets (70.1) 7.0
======================================= ==== ========== =============
Non-current liabilities:
Long-term debt 9 (2,802.3) (2,972.6)
Deferred tax liabilities (148.6) (164.0)
Deferred income (72.7) (80.3)
Long-term provisions (1,306.2) (1,370.9)
Derivative financial instruments 10 (120.7) (108.3)
(4,450.5) (4,696.1)
Total liabilities (5,105.2) (5,519.7)
======================================= ==== ========== =============
Net assets 764.0 616.9
======================================= ==== ========== =============
Equity and reserves:
Share capital 147.5 109.0
Share premium account 462.9 284.5
Other reserves 153.6 223.4
======================================= ==== ========== =============
764.0 616.9
======================================= ==== ========== =============
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
Share premium
Share capital account Other reserves Total
$ million $ million $ million $ million
-----------------------------------
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
------------- ------------- -------------- ----------
At 1 January 2017 106.7 275.4 427.0 809.1
Provision for share-based payments - - 9.0 9.0
Profit for the period - - 40.7 40.7
Other comprehensive income - - 10.3 10.3
At 30 June 2017 106.7 275.4 487.0 869.1
(1) Refer to note 1 for detail on IFRS 9 adjustment.
CONDENSED CONSOLIDATED CASH FLOW STATEMENT
Six months Six months
to 30 June to 30 June
2018 2017
Unaudited Unaudited
Note $ million $ million
======================================= ==== ============ ============
Net cash from operating activities 9 224.6 292.0
======================================= ==== ============ ============
Investing activities:
Capital expenditure (164.3) (129.8)
Decommissioning pre-funding (9.8) (7.8)
Decommissioning expenditure (45.1) (6.3)
Disposal of oil and gas properties 11 22.8 30.0
Net cash used in investing activities (196.4) (113.9)
Financing activities:
Issuance of Ordinary Shares 8.0 -
Net release of ESOP Trust shares (1.0) -
Proceeds from drawdown of bank loans 105.0 -
Repayment of bank loans (199.1) -
Debt arrangement fees - (34.9)
Interest paid (125.5) (89.7)
======================================= ==== ============ ============
Net used in financing activities (212.6) (124.6)
======================================= ==== ============ ============
Currency translation differences relating
to cash and cash equivalents (1.0) (1.9)
============ ============
Net (decrease)/increase in cash and
cash equivalents (185.4) 51.6
Cash and cash equivalents at the
beginning of the period 365.4 255.9
======================================= ==== ============ ============
Cash and cash equivalents at the
end of the period 9 180.0 307.5
--------------------------------------- ---- ============ ============
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 2018 were approved for issue in accordance with a resolution
of a committee of the Board of Directors on 22 August 2018.
The information for the year ended 31 December 2017 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 2017 were approved by the Board of Directors on 7 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 2018, and the condensed
consolidated balance sheet as at 30 June 2018 and related notes,
have been reviewed by the auditors and their report to the Company
is attached.
Basis of preparation
The condensed financial statements for the six months ended 30
June 2018 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 2017, 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.
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 2017, as described in
those annual financial statements, except for the adoption of IFRS
9 Financial Instruments and IFRS 15 Revenue from Contracts with
Customers.
IFRS 9 'Financial Instruments'
The overall impact on transition to IFRS 9 was an US$82 million
increase in long-term debt and corresponding reduction in net
assets. This adjustment relates entirely to an adjustment to the
Group's accounting for its refinancing that completed in July 2017.
On adoption of IFRS 9, additional interest charges for facilities
that were not deemed to be substantially modified have been
expensed at the point of completion of the refinancing. Under the
previous accounting policies these additional interest charges had
been expected to be amortised to the income statement on an
effective interest rate basis over the life of the facilities.
Under IFRS 9, this would have increased the interest charge
recognised in 2017 by US$82 million, with a corresponding reduction
in net assets at 31 December 2017. Going forward, this reduces
Premier's forecast interest charges by c.US$20 million per annum.
The impact on the current period balance sheet is to increase
long-term debt and reduce retained earnings by US$82 million. As
permitted by IFRS 9 comparatives have not been restated.
For certain line items in the balance sheet the closing balance
at 31 December 2017 as previously reported and the opening balance
at 1 January 2018 therefore differ (see statement of changes in
equity). The Group's accounting policy has been revised to reflect
the requirements of IFRS 9. However, excluding the impact on the
accounting treatment applied to the Group's 2017 refinancing, the
standard has not had a significant impact. The Group's accounting
policy for IFRS 9 is set out below:
(a) Classification of financial assets and financial
liabilities
IFRS 9 requires the use of two criteria to determine the
classification of financial assets: the entity's business model for
the financial assets and the contractual cash flow characteristics
of the financial assets. The Standard goes on to identify three
categories of financial assets - amortised cost; fair value through
profit or loss (FVTPL); and fair value through other comprehensive
income (FVOCI). The accounting for the Group's financial
liabilities remains largely the same as it was under IAS 39.
Similar to the requirements of IAS 39, IFRS 9 requires contingent
consideration liabilities to be treated as financial instruments
measured at fair value, with the changes in fair value recognised
in the statement of profit or loss.
1. BASIS OF PREPARATION (continued)
Under IFRS 9, embedded derivatives are no longer separated from
a host financial asset. Instead, financial assets are classified
based on their contractual terms and the Group's business model.
The accounting for derivatives embedded in financial liabilities
and in non-financial host contracts has not changed from that
required by IAS 39.
(b) Impairment
IFRS 9 mandates the use of an expected credit loss model to
calculate impairment losses rather than an incurred loss model, and
therefore it is not necessary for a credit event to have occurred
before credit losses are recognised. The new impairment model
applies to the Group's financial assets and loan commitments. No
changes to the impairment provisions were made on transition to
IFRS 9.
The IFRS 9 impairment model requiring the recognition of
'expected credit losses', in contrast to the requirement to
recognise 'incurred credit losses' under IAS 39, has not had a
material impact on the Group's financial statements.
Trade receivables are generally settled on a short time frame
and the Group's other financial assets are due from counterparties
without material credit risk concerns at the time of
transition.
(c) Hedge accounting
The hedge accounting requirements of IFRS 9 have been simplified
and are more closely aligned to an entity's risk management
strategy. Under IFRS 9 all existing hedging relationships will
qualify as continuing hedging relationships and the group also
intends to apply hedge accounting prospectively to certain of its
commodity price risk management activities for which hedge
accounting was not possible under IAS 39. This had no impact on the
2018 opening balance sheet.
IFRS 15 'Revenue from Contracts with Customers'
Premier has elected to apply the 'modified retrospective'
approach to transition permitted by IFRS 15 under which comparative
financial information is not restated. The standard did not have a
material effect on the Group's financial statements as at 1 January
2018 and so no transition adjustment has been made. The standard
has not had a material impact on the Group's accounting policy in
respect to revenue as previously disclosed in the 2017 financial
statements.
1. BASIS OF PREPARATION (continued)
Revenue from contracts with customers for the 2018 1H period is
presented in Note 2. Amounts presented for comparative periods in
2017 include revenues determined in accordance with the Group's
previous accounting policies relating to revenue. The total amounts
presented do not, therefore, represent the revenue from contracts
with customers that would have been reported for those periods had
IFRS 15 been applied using a fully retrospective approach to
transition but the differences are not material.
The Group's accounting policy for IFRS 15 is set out below:
Under IFRS 15, revenue from contracts with customers is
recognized when or as the group satisfies a performance obligation
by transferring a promised good or service to a customer. A good or
service is transferred when the customer obtains control of that
good or service. The transfer of control of oil, natural gas,
natural gas liquids, and other items sold by the group usually
coincides with title passing to the customer and the customer
taking physical possession. The group principally satisfies its
performance obligations at a point in time and the amounts of
revenue recognized relating to performance obligations satisfied
over time are not significant.
A number of additional new standards, amendments to existing
standards and interpretations were effective from 1 January 2018.
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 2018.
Changes to accounting policies and the impact on financial
statements resulting from new accounting standards and amendments
to existing standards that have been issued, but are not yet
effective, including IFRS 16, are currently being assessed. IFRS 16
is likely to require a number of significant changes to the
treatment of the Group's lease arrangements, in particular the FPSO
lease arrangements for Catcher and Chim Sáo. We expect to recognise
right of use assets and liabilities associated with the leased
FPSOs on our balance sheet from 1 January 2019, with a
consequential impact on the profile and phasing of income statement
recognition.
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, which
remains classified as an asset held for sale, are reported as a
discontinued operation. The results from Mauritania continue to be
included in the Rest of the World Business Unit.
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
2018 2017
Unaudited Unaudited
$ million $ million
========================================= ============ ============
Revenue:
United Kingdom 395.7 362.6
Indonesia 87.6 84.7
Vietnam 140.9 97.0
Rest of the World 0.8 1.8
Total Group sales revenue 625.0 546.1
Other operating (costs)/income - United
Kingdom (1.5) 2.6
Interest and other finance revenue 2.2 0.6
Total Group revenue from continuing
operations 625.7 549.3
Revenue from discontinued operations 18.3 20.2
============ ============
Group operating profit:
United Kingdom 74.6 75.8
Indonesia 42.1 37.7
Vietnam 77.5 38.9
Rest of the World (3.5) (4.1)
Unallocated(1) (5.2) (6.9)
--------------------------------------------- -------- --------
Group operating profit 185.5 141.4
Interest revenue, finance and other
gains 3.8 9.2
Finance costs and other finance expenses (214.0) (154.2)
Loss before tax from continuing operations (24.7) (3.6)
Tax 114.8 40.2
======== ========
Profit after tax from continuing operations 90.1 36.6
======== ========
Profit from discontinued operations 8.3 4.1
======== ========
(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
pre-licence exploration costs.
2. OPERATING SEGMENTS (continued)
Of the Group's worldwide revenues of US$625.0 million (2017 1H:
US$546.1 million), revenues of US$661.4 million (2017 1H: US$552.7
million) were from contacts with customers. This was offset by
hedging losses in the period of US$36.4 million (2017 1H: US$6.6
million).
30 June 31 December
2018 2017
Unaudited Audited
$ million $ million
Balance sheet - Segment assets:
United Kingdom(1) 4,097.7 4,116.2
Indonesia 428.6 440.4
Vietnam 340.9 374.4
Falkland Islands 635.6 633.1
Rest of the World(2) 107.3 96.0
Assets held for sale 64.8 96.6
Unallocated(3) 194.3 379.9
--------------------------------- ----------- ------------
Total assets 5,869.2 6,136.6
--------------------------------- ----------- ------------
(1) Includes goodwill of US$240.8 million.
(2) Segmental assets for Mauritania have been included within
Rest of the World.
(3) Unallocated assets include cash and cash equivalents and mark-to-market
valuations of commodity contracts and interest rate swaps.
3. COSTS OF OPERATION
Six months Six months
to 30 June to 30 June
2018 2017
Unaudited Unaudited
$ million $ million
========================== ============ ============
Operating costs 232.5 214.0
Gas purchases 4.3 3.4
Stock underlift movement (12.5) (2.7)
Royalties 7.3 4.1
231.6 218.8
4. INTEREST REVENUE AND FINANCE COSTS
Six months Six months
to 30 June to 30 June
2018 2017
Unaudited Unaudited
$ million $ million
========================================== ============ ============
Interest revenue, finance and other
gains:
Short-term deposits 0.6 0.2
Other interest received 1.6 0.4
Derivative gains 1.6 8.6
3.8 9.2
Finance costs:
Bank loans, overdrafts and bonds (86.7) (72.7)
Payable in respect of convertible
bonds (0.6) (5.5)
Payable in respect of senior loan
notes (18.9) (14.7)
Long-term debt arrangement fees (15.2) (5.2)
Exchange differences and others (6.6) (12.2)
============ ============
(128.0) (110.3)
Other finance expenses:
Unwinding of discount on decommissioning
provision (31.7) (29.9)
Derivative losses (51.6) (4.7)
Refinancing fees - (15.7)
Finance expense on deferred income (2.7) (6.0)
============ ============
(86.0) (56.3)
Gross finance costs and other finance
expenses (214.0) (166.6)
Finance costs capitalised during the
period - 12.4
============ ============
(214.0) (154.2)
------------------------------------------ ------------ ------------
5. TAX
Six months Six months
to 30 June to 30 June
2018 2017
Unaudited Unaudited
$ million $ million
=========================================== ============ ============
Current tax:
UK corporation tax on profits (9.5) (0.2)
UK petroleum revenue tax - (0.1)
Overseas tax 56.0 36.9
Adjustments in respect of prior years - (7.9)
============ ============
Total current tax charge 46.5 28.7
============ ============
Deferred tax:
UK corporation tax (146.4) (53.9)
Overseas tax (14.9) (15.0)
============ ============
Total deferred tax credit (161.3) (68.9)
============ ============
Tax credit on loss on ordinary activities (114.8) (40.2)
============ ============
5. TAX (continued)
The Group has a current tax charge for the period of US$46.5
million (2017: charge of US$28.7 million) and a non-cash deferred
tax credit for the period of US$161.3 million (2017: US$68.9
million) which results in a total tax credit for the period of
US$114.8 million (2017: credit of US$40.2 million). The deferred
tax credit primarily arises due to ring fence expenditure
supplement which is claimed on UK tax losses.
The Group's full year forecast effective tax rate (ETR), which
was applied to the half-year results to calculate the interim tax
credit, is heavily impacted by the effect of the ring fence
expenditure supplement (RFES) to be claimed in the UK. Removing the
impact of RFES from the full year ETR calculation would reduce the
Group's half-year ETR to 172 per cent and would therefore, reduce
the tax credit recognised by the Group for the six months ended 30
June 2018. With higher production forecast in the second half of
2018 as Catcher production reaches plateau, at current oil prices
EBITDA is expected to increase significantly in the second half of
the year, which is likely to result in a partial release of the tax
credit recognised at 30 June 2018 by the end of 2018.
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 2017 on the basis
that there have been no impairment triggers identified at the
balance sheet date of 30 June 2018.
The weighted average rate is calculated based on the tax rates
weighted according to the profit or loss before tax earned by the
Group in each jurisdiction. The change in the weighted average rate
year-on-year relates to the mix of profit and loss in each
jurisdiction.
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 55 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
2018 2017
Unaudited Unaudited
Earnings ($ millions):
Earnings from continuing operations 90.1 36.6
Effect of dilutive potential Ordinary
Shares:
Interest on convertible bonds - (2017 0.6 -
anti-dilutive)
============ ============
Earnings for the purposes of diluted
earnings per share on continuing operations 90.7 36.6
Profit from discontinued operations 8.3 4.1
============================================== ============ ============
Earnings for the purpose of diluted
earnings per share on continuing and
discontinued operations 99.0 40.7
============================================== ============ ============
Number of shares (millions):
Weighted average number of Ordinary
Shares for the purpose of basic earnings
per share 745.0 510.8
Effects of dilutive potential Ordinary
Shares:
Contingently issuable shares - dilutive 127.2 12.1
============================================== ============
Weighted average number of Ordinary
Shares for the purpose of diluted
earnings per share 872.2 522.9
============================================== ============ ============
Earnings per share (cents) from continuing
operations
Basic 12.1 7.2
Diluted 10.4 7.0
Earnings per share (cents) from continuing
and discontinued operations
Basic 13.2 8.0
Diluted 11.4 7.8
============ ============
Discontinued operations in 2018 relate to the results of the
Group's Pakistan Business Unit which continue to be classified as a
held for sale asset.
7. INTANGIBLE EXPLORATION AND EVALUATION (E&E) ASSETS
Oil and
gas properties
$ million
------------------------------------
Cost:
At 1 January 2018 1,061.9
Exchange movements (6.7)
Additions during the period 32.9
Exploration expense (5.2)
Assets classified as held for sale (1.6)
At 30 June 2018 1,081.3
At 31 December 2017 1,061.9
------------------------------------
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, Tolmount and Tuna projects, as well as our share of
expenditure on the Zama prospect in Mexico.
8. PROPERTY, PLANT AND EQUIPMENT
Oil and gas Other
properties fixed assets Total
Note $ million $ million $ million
=============================== ----------- -------------- ----------
Cost:
At 1 January 2018 7,589.4 66.7 7,656.1
Exchange movements 0.5 (1.1) (0.6)
Additions during the period (2.6) 0.7 (1.9)
Disposals (0.1) (0.1) (0.2)
Assets classified as held for
sale 11 (20.6) - (20.6)
----------- -------------- ----------
At 30 June 2018 7,566.6 66.2 7,632.8
----------- -------------- ----------
Amortisation and depreciation:
At 1 January 2018 5,220.3 54.8 5,275.1
Exchange movements 1.1 (0.6) 0.5
Charge for the period 180.8 4.8 185.6
Disposals - (0.1) (0.1)
Assets classified as held for
sale 11 (5.8) - (5.8)
----------- -------------- ----------
At 30 June 2018 5,396.4 58.9 5,455.3
=============================== ----------- -------------- ----------
Net book value:
=============================== =========== ============== ==========
At 30 June 2018 2,170.2 7.3 2,177.5
=============================== ----------- -------------- ----------
At 31 December 2017 2,369.1 11.9 2,381.0
=============================== ----------- -------------- ----------
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.
9. NOTES TO THE CONDENSED CONSOLIDATED CASH FLOW STATEMENT
Six months Six months
to 30 June to 30 June
2018 2017
Unaudited Unaudited
Note $ million $ million
========================================== ===== ============ ============
Loss before tax for the period (24.7) (3.6)
Adjustments for:
Depreciation, depletion and amortisation 185.6 180.5
Other operating costs/(income) 1.5 (2.6)
Exploration expense 7 5.2 1.1
Provision for share-based payments 4.2 5.0
Interest revenue and finance gains 4 (3.8) (9.2)
Finance costs and other finance
expenses 4 214.0 154.2
Loss on disposal of non-current 10.4 -
assets
========================================== ===== ============ ============
Operating cash flows before movements
in working capital 392.4 325.4
Increase in inventories (4.6) (6.3)
Decrease in receivables 48.3 26.7
Decrease in payables (113.7) (33.3)
========================================== ===== ============ ============
Cash generated by operations 322.4 312.5
Income taxes paid (62.5) (44.0)
Interest income received 1.8 0.3
========================================== ===== ============ ============
Net cash from continuing operating activities 261.7 268.8
============ ============
Net cash from discontinued operating
activities 11 14.9 13.9
========================================== ===== ============ ============
Net cash from operating activities 276.6 282.7
========================================== ===== ============ ============
Movement in joint venture cash (52.0) 9.3
========================================== ===== ============ ============
Total net cash from operating activities 224.6 292.0
========================================== ===== ============ ============
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
2018 2017
Unaudited Unaudited
$ million $ million
============================================== ============ ============
a) Reconciliation of net cash flow to
movement in net debt:
Movement in cash and cash equivalents (185.4) 51.6
Proceeds from drawdown of bank loans (105.0) -
Repayment of bank loans 199.1 -
Partial conversion of convertible bonds 154.0 -
Non-cash movements on debt and cash balances
(predominantly foreign exchange) 8.8 (24.9)
============ ============
Decrease in net debt in the period 71.5 26.7
Opening net debt (2,724.2) (2,765.2)
============ ============
Closing net debt (2,652.7) (2,738.5)
============ ============
b) Analysis of net debt:
Cash and cash equivalents 180.0 307.5
Borrowings(1) (2,832.7) (3,046.0)
========== ==========
Total net debt (2,652.7) (2,738.5)
========== ==========
(1) Borrowings consist of the convertible bonds, short-term
debt 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$101.8 million (31
December 2017: US$117.0 million) and the impact of the
IFRS 9 adjustment (see note 1).
10. FINANCIAL INSTRUMENTS
Derivative financial instruments
The Group held the following financial instruments at fair value
at 30 June 2018. 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
2018 2017
$ million $ million
======================== =========== ===== ====
Financial assets:
Oil put options - 0.2
Fair value of gas contracts acquired
from E.ON 8.7 9.1
Forward foreign exchange contracts - 0.6
Interest rate swaps 5.6 4.6
Total 14.3 14.5
Financial liabilities:
Oil forward sales contracts 105.9 36.1
Gas forward sales contracts 1.8 -
Cross currency swaps 114.8 108.4
Forward foreign exchange contracts 6.9 3.8
Warrants 100.7 59.8
------------------------------------- ---------- ----------- ---------------
Total 330.1 208.1
-------------------------------------------------- ----------- ---------------
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 (2017:
42.75 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.
As at 31 December 2017, 75.2 million equity warrants and 21.4
million synthetic warrants were recognised on the balance sheet as
derivative financial instruments. During the period, 14.5 million
equity warrants were converted, resulting in an allotment of 14.3
million shares. The closing fair value of the open equity and
synthetic warrants at 30 June 2018 was US$74.5 million and US$26.2
million respectively, giving a total of US$100.7 million after the
exercise of warrants and resulting in a loss of US$40.9 million
being expensed in the period as derivative losses within other
finance expenses (see note 4).
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$1.5
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 2018 At 31 December
2017
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 201.6 198.0 196.1 202.5
Convertible bonds 53.2 27.8 266.9 180.5
================================ =========== =========== =========== ===========
10. FINANCIAL INSTRUMENTS (continued)
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.
Convertible bonds
In January 2018, Premier invited convertible bondholders to
exercise their exchange rights in respect of any and all of their
bonds. 87.5 per cent or US$205.8 million of the US$235.2 million
bonds outstanding were accepted for early exchange with an
incentive amount of US$50 per US$1,000 in principal of bonds. The
exchange resulted in the issue of 231,882,091 Ordinary Shares,
which included 7,578,343 incentive shares. This resulted in a
reduction in the convertible bond liability from US$180.5 million
to US$27.8 million on the balance sheet at 30 June 2018. The
exchange also resulted in a release of US$54.5m from other reserves
in the period to 30 June 2018.
11. DISCONTINUED OPERATIONS, DISPOSALS AND ASSETS HELD FOR
SALE
30 June 2018 31 December 2017
$ million $ million
----------------------------------------------
Assets held for:
- Pakistan Business Unit 49.2 52.2
- Babbage 15.6 -
- Esmond Transportation System (ETS) - 27.0
- Kakap field - 17.4
------------ ----------------
Total assets classified as held for sale 64.8 96.6
------------ ----------------
Liabilities held for:
- Pakistan Business Unit (26.8) (25.4)
- Babbage (31.5) -
- Esmond Transportation System (ETS) - (7.0)
- Kakap field - (14.2)
------------ ----------------
Total liabilities classified as held for sale (58.3) (46.6)
------------ ----------------
Disposals
During the period, Premier completed the previously announced
sales of its interests in the Kakap field and its 30 per cent
non-operated interest in the Esmond Transportation System (ETS) for
total cash proceeds of US$22.8 million (after working capital
adjustments). A net loss on disposal of US$4.8 million had been
recognised in the income statement for the period. In addition,
US$5.6m contingent consideration receivable from Kris Energy in
relation to the Aceh disposal by Premier in 2014 has been written
off in the period.
11. DISCONTINUED OPERATIONS, DISPOSALS AND ASSETS HELD FOR SALE
(continued)
Assets held for sale - Babbage interests
In April 2018, Premier entered into a sale and purchase
agreement (SPA) to sell its interest in the Babbage Area to Verus
Petroleum SNS Limited (Verus) for GBP62.9 million (US$88.1
million). In addition, Verus will take on exploration commitments
valued at GBP17 million (US$23.8 million), resulting in net cash
proceeds of GBP45.9 million (US$64.3 million) to Premier, before
customary working capital adjustments. Further cash payments of up
to GBP5.5 million (US$7.7 million) are due to Premier if the Cobra
discovery is developed. The effective date of the transaction is 1
January 2018. Disposal proceeds will be used to pay down Premier's
existing debt. Completion of the transaction is expected in 2018
2H. Accordingly, the assets and liabilities of the Babbage Area
interests have been classified as assets held for sale in the
balance sheet at 30 June 2018.
The consideration to be received for the Babbage interests is
greater than the carrying value of the net assets of Babbage.
Therefore, no impairment has been recognised on reclassification of
the asset and a profit on disposal is expected to be recognised
when the transaction completes.
Discontinued operations
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. During 2017 Al-Haj paid a deposit to Premier of US$25
million.
The disposal of the Pakistan Business Unit is expected to
complete by the end of 2018 and, as this is within 12 months of the
balance sheet date, the business unit continues to be classified as
a disposal group held for sale and presented separately in the
balance sheet.
The results of the disposal group which have been included as
discontinued operations in the consolidated income statement were
as follows:
30 June 30 June
2018 2017
$ million $ million
============================================
Revenue 18.3 20.2
Expenses (7.4) (14.0)
=========== ===========
Profit before tax 10.9 6.2
=========== ===========
Attributable tax charge (2.6) (2.1)
=========== ===========
Net profit for the period from assets held
for sale 8.3 4.1
=========== ===========
11. DISCONTINUED OPERATIONS, DISPOSALS AND ASSETS HELD FOR SALE
(continued)
During the period to 30 June 2018, the Pakistan disposal group
contributed US$14.9 million (2017 1H: US$13.9 million) to the
Group's net operating cash flows and paid US$1.5 million (2017 1H:
US$1.9 million in respect of investing activities. There were no
financing cash flows in either the current or the prior period.
The major classes of assets and liabilities comprising the
disposal group classified as held for sale are as follows:
30 June 2018 31 December
2017
$ million $ million
Property, plant and equipment 23.4 23.3
Long-term receivables 0.3 0.4
Deferred tax asset 1.2 0.8
Inventory 8.3 9.0
Trade and other receivables 15.3 17.8
Cash 0.7 0.9
------------- ------------
Pakistan assets classified as held
for sale 49.2 52.2
------------- ------------
Trade and other payables (10.3) (7.8)
Long-term provisions (16.5) (17.6)
------------- ------------
Pakistan liabilities classified as
held for sale (26.8) (25.4)
------------- ------------
Net assets of disposal group 22.4 26.8
------------- ------------
Contingent liabilities
At 30 June 2018, the Group had a contingent liability for a
potential contractual payment of GBP13.3 million (US$17.6 million)
payable in relation to an overseas tax matter. Whilst there is a
possible risk that a cash payment may be required in 2018 2H, the
Group continues to engage with the overseas tax authorities and is
confident that no payment will be made.
12. SUBSEQUENT EVENTS
In July 2018, Premier announced its intention to exercise the
mandatory conversion option in its convertible bonds. The exercise
of such option will automatically and mandatorily convert all of
the remaining US$28.8 million outstanding convertible bonds into
approximately 31.4 million new Ordinary Shares of Premier.
In August 2018, the joint venture and the Group's infrastructure
partners on the Tolmount project sanctioned the development of the
gas field.
INDEPENT REVIEW REPORT TO PREMIER OIL PLC
Introduction
We have been engaged by Premier Oil plc (the 'Company') to
review the condensed set of financial statements in the half-yearly
financial report for the six months ended 30 June 2018 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 12. 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 International Financial
Reporting Standards (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 2018 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
22 August 2018
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 EBITDA,
Operating cost per barrel, Depreciation, depletion and amortisation
per barrel, Net Debt and Liquidity are defined below.
-- EBITDA: 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.
-- 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 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
Financial Review 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
2018 2017
kboepd kboepd
UK:
Catcher 13.4 -
Balmoral Area(1) 1.6 2.6
Huntington 7.3 15.6
Solan 4.5 7.3
Wytch Farm(2) - 4.5
Kyle 1.6 1.9
Babbage 2.7 3.2
Elgin-Franklin 7.0 6.5
Other UK 3.2 4.0
============================= =============================
41.3 45.6
============================= =============================
Indonesia:
Natuna Sea Block A 12.8 12.9
Kakap(3) 0.6 1.3
--------------------- ----------------------------- -----------------------------
13.4 14.2
--------------------- ----------------------------- -----------------------------
Vietnam:
Chim Sáo 16.2 15.5
16.2 15.5
Pakistan:
Bhit/Badhra 1.8 2.1
Kadanwari 0.7 0.8
Qadirpur 2.0 2.3
Zamzama 0.8 1.3
Mauritania:
Chinguetti - 0.3
============================= =============================
5.3 6.8
============================= =============================
TOTAL 76.2 82.1
============================= =============================
(1) Includes Balmoral, Brenda, Nicol and Stirling fields.
(2) Disposal of Wytch Farm completed in December 2017.
(3) Kakap production included until completion of disposal on
10 April 2018.
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 FKBDPCBKDOFB
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