TIDMPMO
RNS Number : 4947H
Premier Oil PLC
18 August 2016
Half-Yearly Results for the six months to 30 June 2016
Tony Durrant, Chief Executive, commented:
"Delivery of a step change in production levels and a leaner
operating cost base has addressed the lower commodity price
environment. Full year production guidance is now increased, which
will drive free cash flow generation. We have made substantial
progress with our lending group on the principal terms of a
refinancing. Our project portfolio has been expanded, positioning
Premier for future growth at lower cost."
Entering new phase
-- Moving to positive cash flow following a period of substantial investment
-- E.On UK acquisition brings portfolio and financial benefits
-- Full year production guidance raised to 68-73 kboepd
-- Cost base reset
-- Progress being made with lending group to amend financial
covenants and to revise debt maturities
Strong operational performance
-- Production averaged 61.0 kboepd (2015 H1: 60.4 kboepd)
-- 93 per cent production efficiency
-- Recent record production rates above 95 kboepd
-- Solan on-stream
Solid financial performance
-- Profit after tax of US$167.1 million, including E.On negative
goodwill credit of US$106.9 million (2015 H1: loss of US$375.2
million)
-- Operating cash flow of US$108.7 million (2015 H1: US$513.0 million)
-- H1 operating costs of US$16.5/boe, 14 per cent below budget
-- Weaker sterling exchange rate positively impacts forward opex, capex and debt
-- Net debt slightly lower on end Q1 position at US$2.63 billion
(31 December 2015: US$2.2 billion)
Future growth
-- Catcher on schedule for 2017 first oil, capex 20 per cent lower than at sanction
-- High return infill drilling in UK and Asia
-- New development projects benefitting from improved economics
-- Exploration prospects in Mexico, Brazil and UK Southern Gas Basin
ENQUIRIES
Premier Oil plc Tel: + 44 (0)20 7730 1111
Tony Durrant
Richard Rose
Bell Pottinger Tel: + 44 (0)20 3772 2500
Gavin Davis
Henry Lerwill
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 our website at www.premier-oil.com.
This announcement has been determined to contain inside
information
CHAIRMAN'S STATEMENT
Industry context
Volatility in the oil markets persisted into the first half of
2016. Brent dropped to US$26/bbl in January but subsequently almost
doubled to close the period at US$48/bbl. Post period end, the
price of Brent weakened, driven primarily by a strengthening US
dollar and fears that a product oversupply could delay any further
crude price recovery. Nonetheless, sentiment has become more
positive with consensus expectations of a rebalanced market and
higher prices during the second half of 2016 and 2017. Against this
backdrop, we remain focussed on maximising value from existing
production and sanctioned projects whilst maintaining asset
integrity and controlling operating costs.
Premier's performance
Operationally Premier has performed strongly. Production for the
period averaged 61.0 kboepd. This was due to high production
efficiency across the Group and, in particular, outperformance from
the Huntington field, where we have increased our interest and
managed reservoir decline. Record Group production rates of over 95
kboepd were achieved post period end which is a testament to the
skill and focus of our production and development teams in what has
been a challenging environment.
At the same time as increasing our production, we have continued
to secure sustainable savings in our underlying operating costs, by
implementing more efficient working practices and removing costs
from our supply chain. A number of collaboration initiatives with
other operators should lead to further cost reductions being
realised over time.
During the first half the Solan field, which has been a
challenging project since sanction, came on-stream and the field is
now set to produce at plateau rates. With low operating costs and
our tax advantaged position in the UK, the field generates
important cash flows for the Group. These will be prioritised
towards reducing debt and completing the Catcher project, which
underpins further growth in our production profile. The Catcher
project is our only significant capital commitment going forward
and our team has continued to secure material savings with latest
capital expenditure forecasts 20 per cent below the original
sanctioned estimates.
We have preserved considerable optionality within our portfolio
to maintain and grow our production beyond current firm plans. Our
unsanctioned projects range from low cost, high return infill
drilling programmes in the UK North Sea and Asia to incremental
developments to backfill our gas contracts in Asia and new projects
such as Tolmount in the Southern Gas Basin, Tuna in Indonesia and
Sea Lion in the Falkland Islands. Premier also has the potential
for material value creation in future years through its exploration
acreage in Mexico, Brazil and tight gas plays in the UK Southern
Gas Basin. We intend to only sanction those projects which deliver
clear value for our shareholders and where our exposure is
appropriate given our funding position and capital structure.
The most significant opportunity to realise capital expenditure
savings exists in our unsanctioned projects where we have yet to
commit to firm contracts. It is here that we can look to capitalise
on weak order backlogs and innovative contractual arrangements
driven by the current commodity background. FEED on the Sea Lion
project is progressing well in this respect with material cost
reductions identified to further lower the breakeven oil price of
the project. Meanwhile, our team is working hard to progress the
development concept for the UK Tolmount gas field which, even in a
low gas price environment, will deliver a high return and
significant value. The opportunity of course is to secure lower
costs for these pre-development projects at the bottom of the cycle
and to bring them on-stream in a rising oil and gas price
environment.
We continue to manage our portfolio actively and to focus on
those core areas where we have a strategic or operational
advantage. The acquisition of E.ON's UK North Sea assets was
consistent with this strategy: it has enhanced our UK asset base,
created considerable operating and cost synergies with our existing
UK business and accelerates the use of our UK tax losses. It is a
reflection of the hard work and skill of the Premier team that we
were able to complete this acquisition when the oil price was at a
cyclical low and thereby building on our proven track record of
adding long term value through acquisitions.
I noted in February that, if low oil prices persisted, then a
further relaxation of our main financing covenants would be
required, which we would take pre-emptive action to address. We are
currently in discussions with our lending group in respect of
amending financial covenants and resetting debt maturities. Given
the unsecured nature of our debt arrangements and the number of
parties involved it is not surprising that negotiations will take
time to conclude but I am encouraged by the progress that has been
made to date. In the meantime, we have been receiving deferrals in
respect of tests to our financial covenants and expect further
deferrals to be forthcoming until the process is completed. Debt
reduction remains a priority for the Company going forward.
Increasing production levels coupled with reducing capital
commitments mean that we expect to deliver that from the fourth
quarter onwards.
Health, safety and environmental (HSE) matters continue to be of
paramount importance to us and, critically in the current
environment, we will not compromise on the integrity and safety of
our people and our operations. We continue to set ourselves
challenging HSE targets to drive continuous improvement in all
these areas and our HSE performance, as measured against our Group
aggregated HSE target, improved in the first six months of the
year. In addition, all of our production and drilling operations
retain their OHSAS 18001 and ISO 14001 certifications. To reinforce
the Company's HSE policy commitments with our operating teams, our
executive management have committed to a structured programme of
HSE-focused visits to our facilities throughout 2016.
In summary, during the first half, production commenced from the
Solan field, the acquisition of the E.ON UK portfolio was completed
and our legacy production assets delivered a robust performance. We
have also continued to capture sustainable savings both in our
operating costs and our capital expenditure. Good progress has also
been made with our lending groups to refinance our debt portfolio,
amend our covenants and to extend maturities to ensure that we have
the financial flexibility to deliver the Catcher project to
completion.
Board changes
In light of both planned retirements and the current price
environment, the Board determined that a reduction in the number of
non-executive members was appropriate. Accordingly, David Bamford
and Michel Romieu agreed to stand down from the Board with effect
from the AGM on 11 May 2016. I would like to thank them for their
significant contribution to the Board and wish them well for the
future. It is anticipated that David Lindsell will retire after
more than nine years of service at the Company's 2017 Annual
General Meeting.
I am delighted to welcome Iain Macdonald, formerly Deputy Group
CFO for BP, to the Board. Iain will take over the role of Chairman
of the Audit and Risk Committee upon David's retirement.
I would also like to thank Neil Hawkings who has been an
Executive Director for over ten years and who has retired from the
Board. We are delighted, however, to retain Neil's services on key
projects where his knowledge and experience are most valuable.
Outlook
We now look forward to a rising production profile delivered
from a leaner operating cost base and with significantly lower
committed capital expenditure. The second half of the year will see
Premier transition from a period of heavy investment to one where
at oil prices above $45/bbl we can generate free cash flow. Our
priority for that cash flow is to deleverage our balance sheet
while continuing to ensure the integrity of our assets and to
deliver our Catcher project. We will invest in new development
projects within a strict disciplined framework such that we are in
a position to execute those projects which deliver the highest
value for our stakeholders.
Mike Welton
Chairman
OPERATIONAL REVIEW
GROUP PRODUCTION
Group production for the first half averaged 61.0 kboepd (2015
H1: 60.4 kboepd) with record rates of over 95 kboepd achieved post
period end. This was driven by high production efficiency from our
existing assets, outperformance from the newly acquired E.ON UK
portfolio and new production from the Solan field. As a result of
this robust production performance, Premier has revised upwards its
production guidance for the full year to 68-73kboepd.
kboepd 2016 H1 2015 H1
----------------------- -------- --------
Indonesia 13.8 13.2
Pakistan & Mauritania 8.3 10.7
UK 22.2 16.9
Vietnam 16.7 19.6
----------------------- -------- --------
Total 61.0 60.4
----------------------- -------- --------
INDONESIA
Production from Indonesia averaged 13.8 kboepd, up five per cent
on the prior period driven by increased market share within
Premier's principal gas sales agreement (GSA1), strong Singapore
demand for gas deliveries under GSA2 and higher liquids production
from the Anoa field following well intervention work.
Production & Development
Production from Indonesia in the first six months was 13.8
kboepd (2015 H1: 13.2 kboepd). The Premier operated Natuna Sea
Block A delivered 12.5 kboepd while production from the
non-operated Kakap field averaged 1.3 kboepd.
Singapore demand for gas sold under GSA1 remained robust,
averaging 297 BBtud (2015 H1: 312 BBtud). Premier's Anoa and
Pelikan fields delivered 131 BBtud (2015 H1: 133 BBtud) and
accounted for 44 per cent of GAS1 deliveries (2015 H1: 43 per
cent), against a contractual share of 40.9 per cent. Sales of Gajah
Baru and Naga gas dedicated to GSA2 averaged 96 BBtud (2015 H1: 70
BBtud), up 33 per cent on the prior period, representing 100 per
cent nomination delivery by Premier. There were no deliveries from
Gajah Baru and Naga under the Domestic Swap Agreement (DSA) in the
first half. Delivery is expected to resume in the third quarter
following an extension of the DSA to end December 2016.
Gas sales from the non-operated Kakap field averaged 19 BBtud
(gross) (2015 H1: 26 BBtud) over the period. Gross liquids
production from the Kakap field averaged 3.0 kbopd (2015 H1: 3.7
kbopd) reflecting natural decline, while gross liquids production
from the Anoa field averaged 1.5 kbopd (2015 H1: 1.4 kbopd), up on
the prior period due to successful well intervention work.
The next generation of developments in Natuna Sea Block A to
backfill our existing Singapore and domestic market contracts
continue to progress. FEED has been completed on the Bison, Iguana
and Gajah Puteri projects and a final investment decision on these
projects is targeted for early 2017. Premier has also identified
several infill drilling candidates at Gajah Baru and is in the
early stages of evaluating other incremental developments,
including the deeper Lama play discoveries and water handling and
gas compressor reconfiguration projects at both Anoa and Gajah
Baru.
Evaluation of potential development scenarios for the 2014 Kuda
and Singa Laut discoveries on the Premier operated Tuna Block is
ongoing and an application has been made to the regulator to extend
the exploration period of the licence for an additional two
years.
VIETNAM
A robust production performance, combined with substantially
reduced operating costs, resulted in the Vietnam business
generating strong operating cash flows over the period.
Production
Production from the Premier-operated Block 12W, which contains
the Chim Sáo and Dua fields, averaged 16.7 kboepd (2015 H1: 19.6
kboepd) net to Premier over the period, in line with expectations.
Production efficiency at Block 12W remained high at 90 per cent
over the period with good reservoir performance. The fall in
production compared to the prior corresponding period reflects
natural decline from the existing wells. However, a number of
successful well stimulations were carried out during the period and
further well stimulations are planned to help offset natural
decline. Premier has also identified two infill drilling candidates
on Block 12W to add incremental production from 2017 onwards.
Unit operating costs for the period have been maintained at
$9/boe, despite the lower production. This reflects further cost
savings realised through renegotiation of vessel and helicopter
contracts as well as lower fuel and insurance costs. In addition
Premier, in its capacity as Block 12W operator, is in advanced
discussions with PetroFirst regarding revision of the FPSO charter
party, including reductions in the cost of the lease rate. Final
documentation and government approvals are expected to be completed
during the third quarter. This will further reduce operating costs
going forward.
UNITED KINGDOM
The UK business delivered a strong production performance from
its existing asset base whilst securing significant operating cost
reductions. The acquisition of E.ON UK completed on 28 April 2016
and asset performance from that portfolio has exceeded
expectations. This, together with new Solan production, will see
production from the UK increase to over 50 kboepd in the second
half, generating material cash flow for the Company. With Solan on
stream, the focus of the development activity now turns to the
delivery of the Catcher project in 2017.
Production
Production from Premier's UK fields averaged 22.2 kboepd (2015
H1: 16.9 kboepd), up 31 per cent on the prior period. This higher
production was driven by the new contribution from the E.ON UK
assets from 29 April, high production efficiency across the
portfolio of 87 per cent and strong performance from the Huntington
field. Production in the second half of the year will benefit from
the ramp up of Solan and a full contribution from the E.ON UK
portfolio.
The operated Huntington field outperformed over the period,
producing at consistent rates of 14 kboepd (gross) prior to summer
maintenance restrictions. This was as a result of high uptime and
positive reservoir management offsetting the impact of natural
decline.
Production from the non-operated Elgin Franklin area, which was
acquired as part of the E.ON UK acquisition, has been strong. Post
period end, the field has delivered rates of over 130 kboepd gross
(Premier 5.2 per cent), levels not seen since 2011. This has been
driven by a successful on-going well intervention and infill
drilling programme. Separately, the non-operated Glenelg field
(Premier 18.57 per cent), a satellite field within the
Elgin-Franklin area, came back on-stream at the end of May
following a successful well workover of the G10 well and has been
producing over 20 kboepd (gross).
Production from the non-operated Kyle field performed as
anticipated delivering 1.8 kboepd (2015: 1.8 kboepd) while
production from the Premier-operated Balmoral area averaged 1.7
kboepd (2014: 3.4 kboepd), impacted by a commercial disagreement
between partners at the start of the year resulting in a temporary
shutdown of production.
Production from the non-operated Wytch Farm field averaged 5.1
kboepd for the first six months of the year (2015 H1: 5.4 kboepd),
benefitting from the well maintenance work carried out in the
second half of 2015. Production from the operated Babbage field,
which was acquired as part of the E.ON UK acquisition, also
exceeded expectations. The field is currently producing over 3
kboepd net to Premier as a result of continued high demand for the
field's gas coupled with high uptime at the onshore facility.
Planning is underway to complete transition of the Babbage platform
to being unmanned. This should result in considerably reduced
operating costs.
First oil from the Solan field was achieved on 12 April. Premier
subsequently carried out a planned production shut down focused on
the final commissioning of the topsides, taking advantage of the
availability of the flotel utilised for pre-first oil hook up and
commissioning. Production from the Solan field recommenced on 22
June and the first tanker offload from the subsea oil storage tank
was successfully undertaken at the end of July with a cargo size of
over 250,000 barrels of oil. Drilling activities on the second
production well (P2Y) have been completed and the well was tied in
by DSV during August. Production from the second well is expected
to start later today (18 August) and, together with production from
the first well which is producing at 14 kboepd, the field is
expected to reach plateau rates of 20-25 kboepd within the next few
days. Solan's untaxed production will generate material cash flow
with operating costs of less than US$10/bbl while the field is on
plateau production.
UK unit operating costs for the period were US$31/boe (2015 H1:
US$29/boe), driven by natural decline from Premier's UK legacy
assets and higher equity in the Huntington field offset by cost
reductions, particularly at Balmoral and Wytch Farm. Going forward,
UK unit operating costs are expected to reduce significantly
towards $20/boe with new production from the Solan field and as
Premier benefits from a full contribution from the lower opex
Elgin-Franklin field.
Developments
The Premier-operated Catcher project remains on schedule to
deliver first oil in 2017. Significant cost savings have been
realised against the original development budget with total project
capex now forecast at US$1.8bn, a reduction of 20 per cent. The
2016 subsea installation campaign is ahead of plan with the
bundles, towhead, midwater arches and gas export pipeline along
with the buoy and mooring system for the FPSO installed. The buoy
has also been ballasted down, thereby completing the most
weather-sensitive part of this phase. Post period end eight of the
nine risers were installed and hung off the buoy and the first
umbilical connected. Support vessels are currently in field
completing the installation of the last riser and the remaining two
umbilicals.
Drilling activities have continued to yield very positive
results. All six wells drilled to date have met or exceeded
pre-drill predictions for reservoir quality while flow rates have
been at or above prognosis. The drilling programme also remains
significantly below the original cost budget. During the period
production wells CCP3 and CTP1 on the Catcher template and BP3 and
BP5 on the Burgman template were completed. The rig is now
preparing to move to the Varadero template to commence operations.
Work continues to assess the possibility of reducing the overall
well count reducing costs without impacting production delivery.
Fabrication of the FPSO hull and topsides continued in Asia in the
first half of 2016. The Stern Terra Block and Forward Terra Block
were delivered to the Keppel yard in Singapore in June and July,
respectively. The hull mating operation was carried out
successfully and the welding of the two blocks completed.
Fabrication of the topside modules at the DynaMac and AOS yards in
Singapore and the Profab yard in Batam continues to progress with
first module lift targeted for September. The sail-away date of the
FPSO from Singapore for a 2017 field start up remains on track.
Work is ongoing on the Tolmount gas field development in the
Southern Gas Basin in which Premier acquired a 50 per cent operated
interest through its acquisition of E.ON UK in April. Premier is
progressing a number of options for the initial phase of the
development which will target the main Tolmount structure. Concept
selection is targeted for the second half of the year with a view
to taking a final investment decision in 2017. Further upside at
Tolmount includes the subsequent development of Tolmount East and
the potential for further gas production utilising the Tolmount
infrastructure from both Premier's and third party discoveries and
prospects nearby.
Exploration
The Ensco 100 rig spudded the Laverda/Slough prospect, near the
Catcher area in the UK North Sea, in April. This commitment well
encountered 13 feet of net oil bearing Tay sands at Laverda, in
line with pre-drill expectations, but did not encounter any
indications of hydrocarbons in the deeper, high risk Slough
prospect. The well was subsequently plugged and abandoned.
The Ocean Valiant rig spudded the Bagpuss prospect in the Outer
Moray Firth in July. The well encountered 41 feet of
hydrocarbon-bearing sands within a 68 feet hydrocarbon column, in
line with pre-drill estimates. The sands have between 25 per cent
and 33 per cent porosity and indications are that the oil is heavy.
The well has been plugged and abandoned.
As a result of the E.ON UK acquisition, Premier has a carried
five per cent interest in the Ravenspurn North Deep well to be
drilled later this year. This well has the potential to open up a
significant new tight gas play within the Southern Gas Basin which,
if successful, will provide material follow-on opportunities for
Premier within its existing portfolio. It also has the potential to
defer the abandonment date of the Ravenspurn North facilities.
Premier also acquired ten greenfield and six near-field exploration
licences, close to either the Babbage or Tolmount areas, through
the E.ON acquisition. Premier's exploration focus is on
high-grading and maturing this acreage within the lightly explored
tight gas plays in the area. Away from the Southern Gas Basin,
Premier has relinquished six UK exploration licences with a further
eight targeted for divestment, a saving of approximately US$2
million per year in licence costs alone.
PAKISTAN
Premier's Pakistan business has continued to generate positive
and stable net cash flows for the Group. During the first six
months of the year, the average realised gas price was US$3.1/mscf
while operating costs remained low at US$0.52/mscf.
Production and Development
Production in Pakistan averaged 7.9 kboepd (2015 H1: 10.3
kboepd), from Premier's six non-operated producing gas fields. The
fall in production reflects natural decline in all of the gas
fields, partially offset by a successful well intervention campaign
at the Zamzama field.
Production from the Zamzama gas field exceeded expectations over
the period, averaging 1.9 kboepd (2015 H1: 2.2 kboepd), with the
well intervention campaign yielding better than anticipated results
and helping to arrest the decline rate of this field.
Production from the Qadirpur, Bhit/Badhra and Zarghun South gas
fields was in line with expectations averaging 2.6 kboepd (2015 H1:
2.8 kboepd), 2.4 kboepd (2015 H1: 3.3 kboepd) and 63 boepd (2015
H1: 86 boepd) respectively.
Portfolio management
Premier has agreed terms with a preferred bidder for the sale of
its Pakistan business. Completion of the transaction remains
subject to the purchaser putting in place the necessary funding
arrangements.
MAURITANIA
Production and development
Production from the Chinguetti field averaged 356 barrels bopd
(2015 H1: 400 bopd) net to Premier during the first six months of
the year. In view of the low oil price and resulting marginal cash
flows, the joint venture partners are targeting cessation of
production from the field by year-end. To this end, the operator
submitted the Abandonment and Decommissioning Plan to the
Government of Mauritania on 29 June.
FALKLAND ISLANDS
In the Falkland Islands, FEED on the Premier operated Sea Lion
Phase 1 project is progressing well and identified cost reductions
have lowered the current break-even oil price estimate for the
project to $45/bbl.
Development
In January, Premier commenced FEED on its operated Sea Lion
Phase 1 project, which comprises the development of the reserves in
the north-east and north-west of Sea Lion oilfield in licence
PL032. FEED contracts were awarded to a group of world-class
contractors comprising SBM Offshore for the FPSO, Subsea 7 for the
subsea installation, NOV for the flexible flowlines and One Subsea
for the subsea production system. The four contractors are working
collaboratively with Premier to optimise the facilities design and
installation methodology and to reduce project costs.
Engagement with the drilling and logistics services markets is
progressing well, with alternative commercial models being
discussed and cost estimates reducing. Tender packages for these
services are expected to be prepared by year end.
Current estimated capex to first oil is now US$1.5 billion while
current project breakeven price estimate has reduced to US$45/bbl.
Further cost reductions are being targeted.
The Falkland Islands Government (FIG) has confirmed to Premier
that it has secured approval from the Secretary of State for an
extension to the Sea Lion Discovery Area licence to April 2020.
Premier continues to work closely with FIG in progressing the
project to a final investment decision, subject to securing
acceptable project economics and the conclusion of a successful
farm down process.
Exploration
In January 2016, Premier completed its exploration programme in
the North Falklands Basin with the successful re-drill of the
Isobel Deep well. The well confirmed the oil discovery encountered
in the original Isobel Deep well and, in addition, discovered new
hydrocarbons in additional sandstones.
NEW COUNTRY ENTRY - EXPLORATION
Premier has rebalanced its exploration portfolio away from
traditional but now mature areas towards under-explored but proven
hydrocarbon basins that have the potential to transform the
company's resource base and to develop into new business units.
Mexico
Premier was awarded a non-operated 10 per cent interest in
Blocks 2 and 7 at no upfront cost in July 2015 and is carried on
each of the blocks up to the point of the first well. The Blocks,
located in the shallow water Sureste Basin, a proven and prolific
hydrocarbon province in the Gulf of Mexico, contain numerous leads
in established and emerging plays. Existing 3D seismic has been
reprocessed across the two blocks and is on track for delivery in
Q3 this year. This data will be used to confirm final drilling
candidates with the first exploration well expected to spud on
Block 7 in 2017 and Block 2 in 2018. It is anticipated that the
joint venture will go out to tender for a moored, semi-submersible
rig for Block 7 in Q4 2016. Premier has the option to increase its
interest in the blocks up to 25 per cent prior to drilling in
payment for past costs.
Brazil
The multi-client seismic survey across Premier's acreage in the
Ceará Basin, our top ranked basin in Brazil, was successfully
completed in early 2016. Premier has subsequently received
fast-track and final PSTM data and fast-track PSDM data across both
its operated CE-M-665 and CE-M-717 concessions as well as across
its non-operated CE-M-661 and data interpretation is underway. The
final PSDM seismic product is on track to be delivered in Q1 2017.
To date, several promising plays have been identified and final
data will be used to identify drilling targets. Meanwhile, we are
working with other operators to evaluate rig sharing options as
well as the possibility of shared onshore services. Simultaneously,
along with other operators, Premier is seeking licence extensions
from the government such that the Company has sufficient time to
conclude such a rig sharing agreement and to drill our wells prior
to licence expiry.
In the Foz do Amazonas Basin where Premier holds a 35 per cent
non-operated interest in block FZA-M-90, interpretation of the new
3D seismic data has been completed and is being evaluated by the
joint venture partnership.
Portfolio management
During the period, Premier exited its licence position in the
Saharawi Arab Democratic Republic and is in the process of
finalising its exit from its Iraq licence.
FINANCIAL REVIEW
Financial overview
Following the sharp fall in crude oil prices in 2015, prices
continued to fall in the opening months of 2016 before stabilising
and recovering to improved levels by 30 June 2016. Brent crude
opened the year at US$35.7/bbl and, after dropping to US$26/bbl in
January 2016, increased to US$48.4/bbl at 30 June 2016. The average
for 2016 H1 was US$39.8/bbl against US$57.8/bbl for the prior half
year.
Against this economic backdrop our production averaged 61.0
kboepd, (2015 H1: 60.4 kboepd), resulting in revenue of US$393.8
million compared with US$577.0 million in 2015 H1. Revenue for the
period includes US$54.8 million (2015 H1: US$145.0 million) for
forward sales of oil and gas which have settled in the year.
EBITDAX for the period was US$182.2 million compared to US$446.7
million for 2015 H1 (as previously reported). The lower EBITDAX is
mainly due to lower oil prices realised during the period.
Business performance 2016 2015
Half-year Half-year
$ million $ million
============================================== =========== ===========
Operating profit / (loss) 197.0 (167.0)
Amortisation and depreciation 156.8 176.1
Impairment charge on oil and gas properties - 385.3
Reduction in decommissioning estimates (100.8) -
Exploration expense and pre-licence
costs 14.5 52.3
Acquisition of subsidiaries:
- Excess of fair value over consideration (106.9) -
- Costs of the acquisition 5.6 -
- Settlement provision for E.On acquisition 16.0 -
EBITDAX 182.2 446.7
============================================== =========== ===========
Net debt at 30 June 2016 amounted to US$2,634.6 million (31
December 2015: US$2,242.2 million), with cash resources of US$207.7
million (31 December 2015: US$401.3 million).
2016 2015 2015
Half-year Half-year Year-end
$ million $ million $ million
--------------------------- ----------- ----------- -----------
Cash and cash equivalents 207.7 372.4 401.3
Convertible bonds (235.2) (230.3) (232.9)
Other long-term debt (2,607.1) (2,234.6) (2,410.6)
--------------------------- ----------- ----------- -----------
Net debt (2,634.6) (2,092.5) (2,242.2)
--------------------------- ----------- ----------- -----------
Long-term borrowings consist of convertible bonds, UK retail
bonds, senior loan notes and bank debt.
Premier's principal financing facilities include a leverage
cover ratio and an interest cover ratio, that are measured every
six months for the previous 12 month period. Under the current
financial agreements, the leverage cover ratio is 4.75 times for
the 12 month period to 30 June 2016 and 31 December 2016, whilst
the interest cover ratio is 3 times for the same testing
periods.
Premier is currently in negotiations with its lending group to
modify the terms of its existing financial facilities. As part of
these negotiations the testing of the 30 June 2016 financial
covenants has been waived, and replaced with a test for the 12
month period ending 31 August 2016. Good progress is being made
with the company's lending group over amendments to the medium term
covenant profile and resetting of debt maturities. Premier expects
negotiations to conclude and revised agreements to be implemented
during H2 2016. Further deferral of the covenant test date will be
sought if required during this period.
Premier retained significant cash and undrawn facilities of
c.US$800 million at 30 June 2016.
Acquisition of E.On's UK North Sea assets
In April 2016 Premier completed the acquisition of E.ON's UK
North Sea assets for cash consideration of US$135.0 million. The
acquisition has been accounted for as a business combination under
the requirements of IFRS 3 Business Combinations and the assets and
liabilities acquired have been fair valued on the date of
completion utilising Premier's corporate assumptions for oil and
gas prices, reserves estimates and discount rates. The fair value
of the net assets acquired was US$241.9 million resulting in an
excess of fair value over consideration of US$106.9 million
recorded as a credit in the income statement. Separately, costs
related to the acquisition of US$21.6 million have been recognised
in the period. This is made up acquisition costs of US$5.6 million
and the recognition of a settlement provision of US$16.0 million in
respect of employee costs.
Results for the E.On assets acquired have been consolidated into
the Premier group results from the date of completion, which has
resulted in an increase to Premier's group revenue of US$44.2
million and an increase in Premier's group profit before tax of
US$5.0 million.
Income statement
Production and revenue
Group production on a working interest basis averaged 61.0
kboepd for the period compared to 60.4 kboepd in 2015 H1. This was
driven by high operating efficiency, better than predicted
reservoir performance on certain fields and a contribution from the
E.On portfolio from the acquisition date. These were offset by
natural decline in the portfolio. Entitlement production for the
period was 57.0 kboepd (2015 H1: 55.7 kboepd). Post hedging,
Premier realised an average price for the period of US$48.6/bbl
(2015 H1: US$83.7/bbl) vs a Brent average price of US$39.8/bbl
(2015 H1: US$57.8/bbl).
Gas prices in Singapore, linked to high sulphur fuel oil (HSFO)
pricing and in turn, therefore, linked to crude oil pricing,
averaged US$5.8/mscf (2015 H1: US$12.3/mscf) post hedging. The
average price for Pakistan gas (where only a portion of the
contract formulae is linked to energy prices) was US$3.1/mscf (2015
H1: US$4.4/mscf).
Total sales revenue from all operations fell to US$393.8 million
(2015 H1: US$577.0 million), due to the fall in average realised
prices and lower volumes of hedged production realised in the
period.
Operating costs
Cost of sales comprise cost of operations, changes in lifting
positions, inventory movement, royalties and amortisation and
depreciation of property plant and equipment ("PP&E"). Cost of
sales for the group was US$355.2 million for 2016 H1, compared to
US$298.8 million for 2015 H1.
Operating costs 2016 2015
Half-year Half-year
$ million $ million
======================================== =========== ===========
Cost of operations (US$ million) 183.7 149.8
Unit cost of operations (US$ per
barrel) 16.5 13.8
======================================== =========== ===========
Amortisation of oil and gas properties
(US$ million) 152.8 170.6
Unit amortisation rate (US$ per
barrel) 13.7 15.7
---------------------------------------- ----------- -----------
The increase in absolute operating costs on the prior period
reflects the operating costs associated with the E.ON UK assets,
the start-up of the Solan field and the Company's higher equity
interest in the Huntington field partially offset by further
savings in underlying opex from contract renegotiations and
operational efficiencies across the Company's asset base.
Underlying unit amortisation fell to US$13.7/boe (2015 H1:
US$15.7/boe).
Revision in decommissioning estimates
The weakness in GBP:USD exchange rate at 30 June has been the
principal cause of a US$100.8 million gain being credited to the
Income statement in respect of revised decommissioning estimates.
Whilst any positive foreign exchange revision would generally have
been credited to the decommissioning asset in the balance sheet,
the majority relates to late life UK assets which have previously
been fully provided for. As such, this revision has been taken as a
credit to the Income Statement in the period.
Exploration expenditure and pre-licence costs
Exploration expense and pre-licence expenditure costs amounted
to US$14.5 million (2015 H1: US$51.5 million). This predominantly
relates to the write off of the Laverda and Slough prospects in the
UK. After recognition of these expenditures, the exploration and
evaluation asset remaining on the balance sheet at 30 June 2016,
including goodwill attributable to the Catcher asset, is US$1,169.8
million (31 December 2015: US$990.5 million) with the increase
driven primarily by the acquisition of the Tolmount asset as part
of the E.On portfolio.
General and Administrative Expenses
Net G&A costs have increased for H1 2016 to US$13.4 million
(2015 H1: US$8.4 million) due to the inclusion of E.On's
unallocated G&A for the two month period since the completion
of the acquisition. Underlying G&A, without the acquisition,
would have fallen period on period. Unallocated G&A is expected
to fall in the second half of the year, following the integration
of E.On's assets into Premier's UK business unit with effect from 1
July 2016.
Finance gains and charges
Interest revenue and finance gains reduced to US$10.3 million
from US$47.4 million in 2015 H1. The principal reason for this
reduction is the fall in accrued interest receivable from the
former JV partner in the Solan development following the
acquisition of the JV partner interest in Solan in May 2015. Gross
finance costs, before interest capitalisation, which include the
unwinding of the discount on decommissioning, of US$122.1 million
were broadly consistent with costs of US$120.1 million in 2015 H1.
Interest costs continue to be capitalised for the Catcher
development but ceased on the Solan development from the
achievement of first oil.
Taxation
The group has a current tax charge for the period of US$12.3
million (2015 H1: US$61.7 million) and a non-cash deferred tax
credit for the period of US$75.4 million (2015 H1: charge of
US$98.8 million) which results in a total tax credit for the period
of US$63.1 million (2015 H1: charge of US$160.5 million).
The negative effective tax rate for the period is a result of
the recognition of UK tax losses and allowances in the period,
driven by anticipated future profitability from the acquisition of
E.ON's UK North Sea assets.
The effects of the UK Supplementary Charge to Tax rate reduction
from 20 per cent to 10 per cent from 1 January 2016 on opening
deferred tax balances (charge of US$183.9 million) has not been
included in the tax charge for the period as the legislation
enacting the rate reduction is not expected to be substantially
enacted until September 2016.
Profit after tax
Profit after tax is US$167.1 million (2015 H1: loss of US$375.2
million) resulting in a basic profit per share of 33.9 cents (2015
H1: loss of 73.5 cents).
Cash flow
Cash flow from operating activities was US$108.7 million (2015
H1: US$513.0 million) after accounting for tax payments of US$37.0
million (2015 H1: US$58.0 million).
Capital expenditure in the period to 30 June 2016 totalled
US$318.3 million (2015 H1: US$517.6 million).
Capital expenditure (US$ million) 2016 2015
Half-year Half-year
$ million $ million
=================================== =========== ===========
Fields/development projects 259.3 379.7
Exploration and evaluation 57.7 137.0
Other 1.3 0.9
Total 318.3 517.6
=================================== =========== ===========
The principal development projects were the Solan and Catcher
fields in the UK.
In addition, expenditure related to decommissioning in the
period was US$55.8 million and included a one off US$53 million
catch up payment into escrow for future decommissioning of Chim
Sao, the balance of which is held within non-current other
receivables.
Balance sheet position
Decommissioning Funding
As part of the E.On acquisition, Premier entered into a separate
Decommissioning Liability Agreement with E.On, whereby E.On agreed
to part fund Premier's share of decommissioning the Johnston and
Ravenspurn North assets. Under the terms of the agreement, E.On
will provide 70 per cent of the decommissioning costs between a
range of GBP 40 million to GBP 130 million based on Premier's net
share of the total decommissioning cost of the two assets. This
results in maximum possible funding of GBP 63.0 million from
Eon.
At 30 June 2016, a long term decommissioning funding asset of
US$78.8 million has, therefore, been recognised within other
non-current receivables utilising the period end GBP:USD exchange
rate.
Provisions
The group's long term provisions increased to US$1,456.7 million
at 30 June 2016, up from US$1,065.7 million at 31 December 2015.
The increase is driven by the recognition of a long term provision
for decommissioning related to E.On assets acquired in the period
of US$565.9 million, which has been partially offset by a reduction
for the UK assets driven by the weakening of the GBP:USD exchange
rate at 30 June 2016.
Financial risk management
Commodity hedge position 2016 H2 2017 2018 H1
============================== ========== ========== ========
Oil hedges
Volume (bopd) 3,310,787 1,530,000 -
Average price (US$/bbl) 65.22 45.82 -
Production hedged (per cent) 37 9 -
============================== ========== ========== ========
Indonesian gas
Indonesian gas (mt) 36,000 - -
Average price (US$/mt) 400.00 - -
Production hedged (per cent) 16 - -
============================== ========== ========== ========
UK natural gas
UK natural gas (mm therms) 30.55 36.58 4.50
Average price (pence/therm) 62.00 55.70 57.32
Production hedged (per cent) 29 21 6
============================== ========== ========== ========
The fair value of the commodity swaps at 30 June 2016 was an
asset of US$70.9 million (2015: US$114.3 million), which is
expected to be released to the income statement by 2018 H1 as the
related barrels are lifted and gas volumes sold.
During the first half of 2016 , forward oil sales of 1.9 mmbbls,
and forward fuel oil sales of 36,000 mt expired resulting in a net
credit of US$54.8 million (2015 H1: US$145.0 million) which has
been included within sales revenue for the period.
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. At 30 June 2016,
the fair value of the outstanding foreign exchange contracts was a
liability of US$2.6 million. 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 and which at 30 June 2016 had a fair
value liability of US$110.0 million. Post the period-end, Premier
has taken advantage of the recent weakness in the sterling dollar
exchange rate to lock in GBP140 million of forward expenditure in
the second half of the year at an average rate of 1.31.
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 2016, approximately 55 per
cent of total borrowings is fixed or has been fixed using the
interest rate swap markets, with a fair value liability at that
date of US$6.6 million. On average, the cost of drawn funds for the
year was 4.0 per cent. Mark-to-market losses on interest rate swaps
amounted to US$6.6 million, which are recorded as movements in
other comprehensive income.
Insurance
The Group undertakes a significant insurance programme to reduce
the potential impact of physical risks associated with its
exploration, development and production activities. Business
interruption cover is purchased for a proportion of the cash flow
from producing fields for a maximum period of 18 months. During
2016, Premier have received cash of US$17.9 million for insurance
claims made.
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 2016, the Group continued to have significant
headroom on its borrowing facilities. However, whilst the Group
expects to have sufficient liquidity available under these existing
facilities during the next 12 months, the Group's projections
currently indicate that a breach of one of the financial covenants
within the Group's borrowing facilities is likely to arise in
respect of the next covenant testing period which, as part of the
lender discussions outlined below, has been revised from the 12
months ending 30 June 2016 to the 12 months ending 31 August
2016.
Discussions with Premier's lending group are ongoing and
management expect the testing date for the financial covenants to
continue to be deferred until modified terms for the financing
facilities are agreed. Management also expect, based on the
discussions held to date, that the modified terms will involve a
relaxation of financial covenants such that there is a reasonable
expectation that the Group will be able to live within the terms of
the amended facilities for the foreseeable future. However, in the
event that the testing of the financial covenants is not deferred
or if a suitable agreement cannot be reached with the lending group
and a breach of a financial covenant were to arise, under the
existing terms of the group's financing facilities, the Group's
debt holders on all of the Group's facilities will have the right
to request re-payment of the outstanding debt and to cancel the
relevant facilities.
The risk that the Group will be unable to defer the testing of
the current financial covenants until appropriate modification of
the terms of its financing facilities is agreed with the lending
group in order to avoid a breach of covenant or that such
appropriate modification of the terms cannot be agreed is a
material uncertainty which the Financial Reporting Council Guidance
on Risk Management, Internal Control and Related Financial and
Business Reporting requires us to report may cast significant doubt
upon the Company's ability to continue to apply the going concern
basis of accounting.
Nevertheless, after making enquiries and considering the
uncertainties described above, the Directors have a reasonable
expectation that the Group will be able to secure an appropriate
modification to the terms of its financing facilities to avoid a
covenant breach. Therefore, the Group and Company are expected to
have adequate resources to continue in operational existence for
the foreseeable future, being at least the next 12 months from the
date of approval of the 2016 Interim Report and Accounts.
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 business unit
management to 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 2015, for the remaining 6 months of the
year as being:
-- Commodity price volatility;
-- Production and development delivery;
-- Financial discipline and governance;
-- Health, safety, environment and security (HSES);
-- Joint venture partner alignment;
-- Host government - political and fiscal risks;
-- Organisational capability; and,
-- Exploration success and reserves addition.
Further information detailing the way in which these risks are
mitigated is provided on pages 30 to 36 of the 2015 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' 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 Year to
to 30 June to 30 June 31 December
2016 2015 2015
Unaudited Unaudited Audited
Note $ million $ million* $ million
============================================== ==== =========== =========== =============
Sales revenues 2 393.8 577.0 1,067.2
Other operating income 0.2 - 31.9
Cost of sales 3 (355.2) (298.8) (661.0)
Impairment charge on oil and gas properties - (385.3) (1,023.7)
Reduction in decommissioning estimates 13 100.8 - -
Exploration expense (9.5) (45.3) (95.4)
Pre-licence exploration costs (5.0) (6.2) (13.6)
Excess of fair value over cost 12 106.9
Costs related to the acquisition of
subsidiaries 12 (21.6) - -
Profit on disposal of assets - - 1.2
General and administration costs (13.4) (8.4) (14.4)
============================================== ==== =========== =========== =============
Operating profit/(loss) 197.0 (167.0) (707.8)
Share of profit in associate - - (1.9)
Interest revenue, finance and other
gains 4 10.3 47.4 40.7
Finance costs and other finance expenses 4 (97.3) (95.0) (160.6)
Profit/(loss) before tax 110.0 (214.6) (829.6)
Tax 5 63.1 (160.5) (241.1)
============================================== ==== =========== =========== =============
Profit/(loss) for the period/year
from continuing operations 173.1 (375.1) (1,070.7)
Discontinued operations
(Loss) for the period/year from discontinued
operations 7 (6.0) (0.1) (33.1)
============================================== ==== =========== =========== =============
Profit/(loss) after tax 167.1 (375.2) (1,103.8)
============================================== ==== =========== =========== =============
Earnings/(losses) per share (cents):
From continuing operations
Basic 7 33.9 (73.4) (209.6)
Diluted 7 32.2 (73.4) (209.6)
From continuing and discontinued operations
Basic 7 32.7 (73.5) (216.1)
Diluted 7 31.1 (73.5) (216.1)
============================================== ==== =========== =========== =============
* restated for discontinued operations.
Notes 1 to 13 form an integral part of these condensed financial
statements.
CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
Six months Six months Year to
to 30 June to 30 June 31 December
2016 2015 2015
Unaudited Unaudited Audited
Note $ million $ million $ million
============================================= ==== =========== =========== ============
Profit/(loss) for the period/year 167.1 (375.2) (1,103.8)
--------------------------------------------- ---- ----------- ----------- ------------
Cash flow hedges on commodity swaps:
Gains/(losses) arising during the
period/year (36.9) 4.8 164.4
Less: reclassification adjustments
for (gains)/ losses in the period/year (47.5) (145.0) (278.9)
============================================= ==== =========== =========== ============
(84.4) (140.2) (114.5)
Tax relating to components of other
comprehensive income 6 54.3 80.9 76.0
Cash flow hedges on interest rate and
foreign exchange swaps (14.6) (2.8) 19.8
Exchange differences on translation
of foreign operations (10.1) (13.4) (37.0)
Losses on long-term employee benefit
plans* - - (0.1)
============================================= ==== =========== =========== ============
Other comprehensive expense (54.8) (75.5) (55.8)
============================================= ==== =========== =========== ============
Total comprehensive income/(expense)
for the period/year 112.3 (450.7) (1,159.6)
============================================= ==== =========== =========== ============
* Not expected to be reclassified subsequently to profit and loss
account
All comprehensive income is attributable to the equity holders
of the parent.
CONDENSED CONSOLIDATED BALANCE SHEET
At At At 31 December
30 June 30 June 2015
2016 2015 Audited
Unaudited Unaudited
Note $ million $ million $ million
============================================ ==== ========== =========== ===============
Non-current assets:
Goodwill 240.8 240.8 240.8
Intangible exploration and evaluation
assets 8 929.0 910.3 749.7
Property, plant and equipment 9 3,320.4 2,946.9 2,611.7
Investments 4.9 7.7 5.3
Long-term employee benefit plan surplus 0.5 0.8 0.5
Other receivables 148.1 9.1 11.5
Deferred tax assets 6 935.5 945.3 871.6
============================================ ==== ========== =========== ===============
5,579.2 5,060.9 4,491.1
============================================ ==== ========== =========== ===============
Current assets:
Inventories 22.9 29.8 20.8
Trade and other receivables 345.4 344.4 240.8
Tax recoverable 21.5 41.1 33.6
Derivative financial instruments 11 81.1 96.5 118.3
Cash and cash equivalents 207.7 372.4 401.3
678.6 884.2 814.8
============================================ ==== ========== =========== ===============
Total assets 6,257.8 5,945.1 5,305.9
============================================ ==== ========== =========== ===============
Current liabilities:
Trade and other payables (583.4) (469.2) (407.4)
Current tax payable (45.6) (74.5) (64.6)
Provisions 13 (37.1) (11.8) (24.8)
Derivative financial instruments 11 (129.4) (53.2) (76.5)
Deferred income (37.5) (17.3) (20.9)
(838.0) (626.0) (594.2)
============================================ ==== ========== =========== ===============
Net current assets (159.4) 258.2 220.6
============================================ ==== ========== =========== ===============
Non-current liabilities:
Convertible bonds (235.0) (230.3) (232.6)
Other long-term debt (2,583.9) (2,211.3) (2,382.5)
Deferred tax liabilities 6 (192.8) (244.3) (193.3)
Deferred income (80.1) (82.7) (87.6)
Long-term provisions 13 (1,456.3) (1,100.2) (1,065.7)
Long-term employee benefit plan deficit (16.3) (17.2) (15.2)
(4,564.4) (3,886.0) (3,976.9)
============================================ ==== ========== =========== ===============
Total liabilities (5,402.4) (4,512.0) (4,571.1)
============================================ ==== ========== =========== ===============
Net assets (855.4) 1,433.1 734.8
============================================ ==== ========== =========== ===============
Equity and reserves:
Share capital 106.7 106.7 106.7
Share premium account 275.4 275.4 275.4
Merger reserve 374.3 374.3 374.3
Retained earnings 179.3 718.8 46.3
Other reserves (80.3) (42.1) (67.9)
============================================ ==== ========== =========== ===============
855.4 1,433.1 734.8
================================================= ========== =========== ===============
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
____________Attributable to the equity holders
of the parent___________
Other reserves
========= ========= ========== ---------- =================================== ==========
Share Capital
Share premium Retained Merger redemption Translation Equity
capital account earnings reserve reserve reserves reserve Total
$ million $ million $ million $ million $ million $ million $ million $ million
----------------------- --------- --------- ---------- ---------- ----------- ----------- --------- ----------
At 1 January 2015 106.7 275.4 1,142.3 374.3 8.1 (48.7) 14.1 1,872.2
Purchase of ESOP
Trust shares - - (0.9) - - - - (0.9)
Provision for
share-based
payments - - 23.0 - - - - 23.0
Transfer between
reserves* - - 4.5 - - - (4.5) -
Total comprehensive
expense - - (1,122.6) - - (37.0) - (1,159.6)
----------------------- --------- --------- ---------- ---------- ----------- ----------- --------- ----------
At 31 December 2015 106.7 275.4 46.3 374.3 8.1 (85.7) 9.6 734.8
ESOP Trust shared - - 0.2 - - - - 0.2
Provision for
share-based
payments - - 8.2 - - - - 8.2
Transfer between
reserves* - - 2.2 - - - (2.2) -
Total comprehensive
expense - - 122.4 - - (10.1) - 112.3
----------------------- --------- --------- ---------- ---------- ----------- ----------- --------- ----------
At 30 June 2016 106.7 275.4 179.3 374.3 8.1 (95.8) 7.4 855.4
----------------------- --------- --------- ---------- ---------- ----------- ----------- --------- ----------
At 1 January 2015 106.7 275.4 1,142.3 374.3 8.1 (48.7) 14.1 1,872.2
Provision for
share-based
payments - - 11.6 - - - - 11.6
Transfer between
reserves* - - 2.2 - - - (2.2) -
Total comprehensive
income - - (437.3) - - (13.4) - (450.7)
----------------------- --------- --------- ---------- ---------- ----------- ----------- --------- ----------
At 30 June 2015 106.7 275.4 718.8 374.3 8.1 (62.1) 11.9 1.433.1
----------------------- --------- --------- ---------- ---------- ----------- ----------- --------- ----------
* The transfer between reserves relates to the non-cash interest
on the convertible bonds, less the amortisation of the issue
costs that were charged directly against equity.
CONDENSED CONSOLIDATED CASH FLOW STATEMENT
Six months Six months Year to
to 30 June to 30 June 31 December
2016 2015 2015
Unaudited Unaudited Audited
Note $ million $ million $ million
======================================= ==== ============ ============ =============
Net cash from operating activities 10 108.7 513.0 809.5
======================================= ==== ============ ============ =============
Investing activities:
Capital expenditure (318.3) (439.7) (992.2)
Acquisition of subsidiaries 12 (135.0) - -
Cash balance acquired in the period 12 24.9 - -
Decommissioning funding (55.8) - -
Proceeds from disposal of oil and
gas properties - 82.7 219.6
Loan to joint venture partner* - (77.9) (77.9)
======================================= ==== ============ ============ =============
Net cash used in investing activities (484.2) (434.9) (850.5)
======================================= ==== ============ ============ =============
Financing activities:
Net purchases of ESOP Trust shares - - (0.9)
Proceeds from drawdown of bank loans 230.0 550.0 775.0
Debt arrangement fees - - (9.6)
Repayment of long term bank loans - (500.8) (300.0)
Repayment of senior loan notes - - (209.4)
Interest paid (55.3) (48.7) (91.6)
======================================= ==== ============ ============ =============
Net cash from financing activities 174.7 0.5 163.5
======================================= ==== ============ ============ =============
Currency translation differences relating
to cash and cash equivalents 7.2 2.0 (13.0)
============================================= ============ ============ =============
Net (decrease)/increase in cash and
cash equivalents (193.6) 80.6 109.5
Cash and cash equivalents at the
beginning of the period/year 401.3 291.8 291.8
======================================= ==== ============ ============ =============
Cash and cash equivalents at the
end of the period/year 10 207.7 372.4 401.3
--------------------------------------- ---- ============ ============ =============
*Funding provided to the former Joint Venture partner on the
Solan field until the completion of the asset acquisition of their
40 per cent interest.
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 2016 were approved for issue in accordance with a resolution
of a committee of the Board of Directors on 17 August 2016.
The information for the year ended 31 December 2015 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 2015 were approved by the Board of Directors on 24
February 2016 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. However, an emphasis of matter with regards to
a material uncertainty in the application of the going concern
basis of accounting was included in the audit report.
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 2016, and the condensed
consolidated balance sheet as at 30 June 2016 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 2016 have been prepared in accordance with IAS 34 - 'Interim
Financial Reporting', as adopted by the European Union and with the
requirements of the Disclosure 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 2015, 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 including details of a material uncertainty due
to the risk of a covenant breach 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 2015, as described in
those annual financial statements. A number of new standards,
amendments to existing standards and interpretations were
applicable from 1 January 2016. 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 2016.
2. OPERATING SEGMENTS
The group's operations are located and managed in six business
units; namely the Falkland Islands, Indonesia, Pakistan (including
Mauritania), the United Kingdom, Vietnam and the Rest of the
World.
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 Year to
to 30 June to 30 June 31 December
2016 2015 2015
Unaudited Unaudited Audited
$ million $ million $ million
===================================== ============ ============ =============
Revenue:
Indonesia 68.0 124.1 215.4
Pakistan (including Mauritania) 29.2 52.1 88.9
Vietnam 91.9 142.5 227.8
United Kingdom 204.7 258.3 535.1
===================================== ============ ============ =============
Total group sales revenue 393.8 577.0 1,067.2
Other operating income 0.2 - 31.9
Interest and other finance revenue 0.5 28.5 29.3
Total group revenue from continuing
operations 394.5 605.5 1,128.4
===================================== ============ ============ =============
Group operating profit/(loss):
Indonesia 7.5 59.1 62.0
Pakistan (including Mauritania) 12.2 17.9 12.2
Vietnam 14.0 37.1 27.0
United Kingdom 97.2 (236.9) (721.9)
Rest of the World (0.8) (29.5) (59.1)
Unallocated* 66.9 (13.4) (28.0)
------------------------------------------ ------- -------- ----------
Group operating profit/(loss) 197.0 (165.7) (707.8)
Share of profit in associate - - (1.9)
Interest revenue, finance and other
gains 10.3 47.6 40.7
Finance costs and other finance expenses (97.3) (94.9) (160.6)
Profit/(loss) before tax 110.0 (213.0) (829.6)
Tax 63.1 (162.1) (241.1)
========================================== ======= ======== ==========
Profit/(loss) after tax from continuing
operations 173.1 (375.1) (1,070.7)
========================================== ======= ======== ==========
Loss from discontinued operations (6.0) (0.1) (33.1)
========================================== ======= ======== ==========
Six months Six months Year to
to 30 June to 30 June 31 December
2016 2015 2015
Unaudited Unaudited Audited
$ million $ million $ million
Balance sheet - Segment assets:
Falkland Islands 655.3 553.0 591.4
Indonesia 542.4 653.2 560.3
Norway - 189.9 -
Pakistan (including Mauritania) 53.5 85.2 59.3
Vietnam 400.7 476.3 388.2
United Kingdom** 4,236.97 3,442.6 3,122.5
Rest of the World 80.2 76.1 64.6
Unallocated* 288.8 468.8 519.6
--------------------------------- ------------ ------------ -------------
Total assets 6,257.8 5,945.1 5.305.9
--------------------------------- ------------ ------------ -------------
* Unallocated expenditure and assets 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, cash and cash equivalents
and mark-to-market valuations of commodity contracts and interest
rate swaps.
** Includes goodwill of US$240.8 million.
3. COST OF SALES
Six months Six months Year to
to 30 June to 30 June 31 December
2016 2015 2015
Unaudited Unaudited Audited
$ million $ million* $ million
============================================ ============ ============ =============
Operating costs 183.7 149.8 323.6
Stock overlift/underlift movement 7.8 (39.7) (11.4)
Royalties 6.9 12.6 22.1
Amortisation and depreciation of property,
plant and equipment
and equipment:
- Oil and gas properties 152.8 170.6 315.9
- Other fixed assets 4.0 5.5 10.8
============================================ ============ ============ =============
355.2 298.8 661.0
============================================ ============ ============ =============
* Restated for discontinued operations
4. INTEREST REVENUE AND FINANCE COSTS
Six months Six months Year to
to 30 June to 30 June 31 December
2016 2015 2015
Unaudited Unaudited Audited
$ million $ million* $ million
========================================== ============ ============ =============
Interest revenue, finance and other
gains:
Short-term deposits 0.5 0.7 0.8
Gain on forward contracts - 9.9 3.8
Gain on extinguishment of debt - 4.1 3.8
Loan to joint venture partner - 27.9 27.9
Exchange differences and others 9.8 5.0 4.4
========================================== ============ ============ =============
10.3 47.6 40.7
========================================== ============ ============ =============
Finance costs:
Bank loans, overdrafts and bonds (40.4) (28.9) (68.1)
Payable in respect of convertible
bonds (5.4) (5.3) (10.7)
Payable in respect of senior loan
notes (14.0) (15.6) (23.4)
Long-term debt arrangement fees (5.8) (4.4) (8.8)
Loss of valuation of cross currency
swap (0.5) (11.3) (20.6)
Loss on forward contracts (0.5) - -
Loss of valuation of oil and gas hedges (16.9) - -
Exchange differences and others (0.8) - -
========================================== ============ ============ =============
(84.3) (65.4) (131.6)
Other finance expenses
Unwinding of discount on decommissioning
provision (28.7) (21.5) (46.1)
Impairment of loan to joint venture
partner - (33.2) (33.2)
Finance expense on deferred income (9.1) - (8.5)
========================================== ============ ============ =============
(37.8) (54.7) (87.8)
Gross finance costs and other finance
expenses (122.1) (120.2) (219.4)
Finance costs capitalised during the
period/year 24.8 25.2 58.8
========================================== ============ ============ =============
(97.3) (95.0) (160.6)
------------------------------------------ ------------ ------------ -------------
* Restated for discontinued operations
5. TAX
Six months Six months Year to
to 30 June to 30 June 31 December
2016 2015 2015
Unaudited Unaudited Audited
$ million $ million $ million
============================================= ============ ============ =============
Current tax:
UK corporation tax on profits (1.0) - (2.3)
UK petroleum revenue tax 0.1 21.3 19.4
Overseas tax 15.4 40.9 80.1
Adjustments in respect of prior years (2.2) (0.4) 1.4
============================================= ============ ============ =============
Total current tax 12.3 61.7 98.6
============================================= ============ ============ =============
Deferred tax:
UK corporation tax (68.5) 117.5 187.4
UK petroleum revenue tax 1.2 (10.1) (10.6)
Overseas tax (8.1) (8.6) (34.3)
============================================= ============ ============ =============
Total deferred tax (75.4) 98.8 142.5
============================================= ============ ============ =============
Tax on profit/(loss) on ordinary activities (63.1) 160.5 241.1
============================================= ============ ============ =============
The group has a current tax charge for the period of US$12.3
million (2015: US$61.7 million) and a non-cash deferred tax credit
for the period of US$75.4 million (2015: charge of US$98.8 million)
which results in a total tax credit for the period of US$63.1
million (2015: charge of US$160.5 million).
The deferred tax credit arises largely as a result of the
recognition of UK tax losses and allowances in the period, as a
result of anticipated future profitability from the acquisition of
E.On's UK North Sea assets.
6. DEFERRED TAX
30 June 30 June 31 December
2016 2015 2015
Unaudited Unaudited Audited
$ million $ million $ million
========================== =========== =========== =============
Deferred tax assets 935.5 945.3 871.6
Deferred tax liabilities (192.8) (244.3) (193.3)
========================== =========== =========== =============
742.7 701.0 678.3
========================== =========== =========== =============
(Charged)/
At credited Credit At
1 January Acquisition to income to retained 30 June
2016 of subsidiary statement earnings 2016
$ million $ million $ million $ million $ million
=============================== ========== ============== ========== ============= =========
UK deferred corporation
tax:
Fixed assets and allowances (581.0) (323.8) 61.8 - (843.0)
Decommissioning 378.8 246.9 60.5 - 686.2
Deferred petroleum revenue
tax 7.2 - 0.6 - 7.8
Tax losses and allowances 1,129.4 41.2 (64.3) - 1,106.3
Other - (8.4) 5.0 - (3.4)
Derivative financial
instruments (49.1) (21.2) 4.8 54.3 (11.2)
Total UK deferred corporation
tax 885.3 (65.3) 68.5 54.3 942.8
=============================== ========== ============== ========== ============= =========
UK deferred petroleum
revenue tax(1) (14.4) - (1.2) - (15.6)
=============================== ========== ============== ========== ============= =========
Overseas deferred tax(2) (192.6) - 8.1 - (184.5)
=============================== ========== ============== ========== ============= =========
Total 678.3 (65.3) 75.4 54.3 742.7
=============================== ========== ============== ========== ============= =========
1 The UK deferred petroleum revenue tax relates mainly to temporary
differences associated with fixed assets.
2 The overseas deferred tax relates mainly to temporary differences
associated with fixed asset balances.
The group's deferred tax assets at 30 June 2016 are recognised
to the extent that taxable profits are expected to arise in the
future against which the ring fence tax losses and allowances can
be utilised. In accordance with paragraph 37 of IAS 12 - 'Income
Taxes' the group re-assessed its deferred tax assets at 30 June
2016 with respect to ring fence tax losses and allowances. The
corporate model used to assess whether it is appropriate to
recognise all of the group's deferred tax assets was re-run, using
an oil price assumption of Dated Brent forward curve in 2H 2016,
2017 and H1 2018, then 2H 2018 and H1 2019 at US$65/bbl followed by
US$80/bbl in 'real' terms thereafter. The results of the corporate
model demonstrated that as a result of an increase in the group's
estimated future UK profitability arising from the acquisition of
subsidiaries in the period, a net amount of US$66.3 million in
respect of the group's UK ring fence deferred tax assets relating
to tax losses and allowances that was previously de-recognised,
could be recognised.
In addition to the above, there are carried forward non-ring
fence UK tax losses of approximately US$364.8 million (2015:
US$283.2 million) for which a deferred tax asset has not been
recognised.
None of the UK tax losses (ring fence and non-ring fence) have a
fixed expiry date for tax purposes.
No deferred tax has been provided on unremitted earnings of
overseas subsidiaries, following a change in UK tax legislation in
2009 which exempted foreign dividends from the scope of UK
corporation tax, where certain conditions are satisfied.
During the period it was announced that the rate of
supplementary tax charge on UK ring fence profits is to be further
reduced from 20 per cent to 10 per cent with effect from 1 January
2016. This rate reduction was not substantially enacted at the 30
June 2016 balance sheet date and therefore has not been reflected
in the calculation of the group's tax charge for the period. Once
enacted, the group's deferred UK tax balances at 31 December 2015
will be recognised at the reduced rate which will give rise to a
deferred tax charge of US$183.9 million in the income statement to
reflect the decrease in the opening deferred tax assets at 1
January 2016.
7. EARNINGS PER SHARE
The calculation of basic earnings per share is based on the
profit after tax and on the weighted average number of Ordinary
Shares in issue during the period. Basic and diluted
earnings/(loss) per share are calculated as follows:
Six months Six months Year to
to 30 June to 30 June 31 December
2016 2015 2015
Unaudited Unaudited Audited
Earnings/(loss) ($ millions):
Earnings/(loss) from continuing operations 173.1 (375.1) (1070.7)
Effect of dilutive potential Ordinary
Shares:
Interest on convertible bonds - dilutive 5.4 - -
============================================ ============ ============ =============
Earnings/(loss) for the purposes of
diluted earnings/(loss) per share
on continuing operations 178.5 (375.1) (1,070.7)
Profit/(loss) from discontinued operations (6.0) (0.1) (33.1)
============================================ ============ ============ =============
Earnings/(loss) for the purpose of
diluted earnings/(loss) per share
on continuing and discontinued operations 172.5 (375.2) (1,103.8)
============================================ ============ ============ =============
Number of shares (millions):
Weighted average number of Ordinary
Shares for the purpose of basic earnings
per share 510.8 510.8 510.8
Effects of dilutive potential Ordinary
Shares:
Contingently issuable shares -dilutive 43.6 - -
============================================ ============
Weighted average number of Ordinary
Shares for the purpose of diluted
earnings per share 554.4 510.8 510.8
============================================ ============ ============ =============
Earnings/(loss) per share (cents)
from continuing operations
Basic 33.9 (73.4) (209.6)
Diluted 32.2 (73.4) (209.6)
Earnings/(loss) per share (cents)
from discontinued operations
Basic (1.2) (0.1) (6.5)
Diluted (1.1) (0.1) (6.5)
============================================ ============ ============ =============
Discontinued operations in all periods relate to the results of
the Group's former Norwegian business, which was sold in December
2015 (results for 2015 H1 have been restated accordingly).
8. INTANGIBLE EXPLORATION AND EVALUATION (E&E) ASSETS
Oil and
gas properties
$ million
----------------------------- ----------------
Cost:
At 1 January 2016 749.7
Exchange movements 8.1
Additions during the period 105.7
Acquisition (see note 12) 75.0
Exploration expense (9.5)
At 30 June 2016 929.0
----------------------------- ----------------
At 30 June 2015 910.3
----------------------------- ----------------
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.
9. PROPERTY, PLANT AND EQUIPMENT
Oil and gas Other
properties fixed assets Total
$ million $ million $ million
=============================== ----------- ------------- ----------
Cost:
At 1 January 2016 7,025.7 61.4 7.087.1
Exchange movements - (2.8) (2.8)
Acquisition (see note 12) 600.0 7.1 607.1
Additions during the period 257.9 1.3 259.2
----------- ------------- ----------
At 30 June 2016 7,883.6 67.0 7,950.6
=============================== ----------- ------------- ----------
Amortisation and depreciation:
At 1 January 2016 4,430.9 44.5 4,475.4
Exchange movements - (2.0) (2.0)
Charge for the period 152.8 4.0 156.8
----------- ------------- ----------
At 30 June 2016 4,583.7 46.5 4,630.2
=============================== ----------- ------------- ----------
Net book value:
At 31 December 2015 2,594.8 16.9 2,611.7
=============================== ----------- ------------- ----------
At 30 June 2016 3,299.9 20.5 3,320.4
=============================== ----------- ------------- ----------
At 30 June 2015 2,929.0 17.9 2,946.9
------------------------------- ----------- ------------- ----------
In April 2016, Premier completed the acquisition of E.ON E&P
UK Ltd for cash consideration of US$135.0 million. For further
details of the assets and liabilities acquired see note 12.
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 or 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.
10. NOTES TO THE CONDENSED CONSOLIDATED CASH FLOW STATEMENT
Six months Six months Year to
to 30 June to 30 June 31 December
2016 2015 2015
Unaudited Unaudited Audited
Note $ million $ million $ million
========================================= ===== ============ ============ =============
Profit/(loss) before tax for
the period/year 110.0 (214.7) (829.6)
Adjustments for: -
Depreciation, depletion, amortisation
and impairment 156.8 561.4 1,350.4
Other operating income (0.2) - (31.9)
Exploration expense 9.5 45.3 95.4
Excess of fair value over consideration 12 (106.9) - -
Settlement provision 12 16.0 - -
Reduction in decommissioning
estimates 13 (100.8) - -
Provision for share-based payments 8.2 5.9 7.2
Share of profit in associate - - 1.9
Interest revenue and finance
gains (10.3) (47.4) (40.7)
Finance costs and other finance
expenses 97.3 95.0 160.6
Loss/(profit) on disposal of
non-current assets - - (1.2)
Deferred income - 100.0 100.0
========================================= ===== ============ ============ =============
Operating cash flows before movements
in working capital 179.6 545.6 812.1
(Increase)/decrease in inventories (2.1) (3.7) 5.3
Decrease/(increase) in receivables (74.3) 15.8 382.1
Increase/(decrease) in payables 42.0 12.6 (297.6)
========================================= ===== ============ ============ =============
Cash generated by operations 145.2 570.3 901.9
Income taxes paid (37.0) (58.0) (94.0)
Interest income received 0.5 0.7 1.6
========================================= ===== ============ ============ =============
Net cash from operating activities 108.7 513.0 809.5
========================================= ===== ============ ============ =============
Analysis of changes in net debt:
Six months Six months Year to
to 30 June to 30 June 31 December
2016 2015 2015
Unaudited Unaudited Audited
$ million $ million $ million
======================================= ============ ============ =============
a) Reconciliation of net cash flow
to movement in net debt:
Movement in cash and cash equivalents (193.6) 80.6 109.5
Proceeds from drawdown of bank loans
and senior loan notes (230.0) (550.0) (775.0)
Repayment of long-term bank loans - 500.8 300.0
Repayment of senior loan note - - 209.4
Non-cash movements on debt and cash
balances 31.2 (1.7) 36.1
======================================= ============ ============ =============
Decrease/(increase) in net debt in
the period/year (392.4) 29.7 (120.0)
Opening net debt (2,242.2) (2,122.2) (2,122.2)
======================================= ============ ============ =============
Closing net debt (2,634.6) (2,092.5) (2,242.2)
======================================= ============ ============ =============
b) Analysis of net debt:
Cash and cash equivalents 207.7 372.4 401.3
Borrowings(*) (2,842.3) (2,464.9) (2,643.5)
=========================== ========== ========== ==========
Total net debt (2,634.6) (2,092.5) (2,242.2)
=========================== ========== ========== ==========
* Borrowings consist of the convertible bonds and the other long-term
debt. The carrying values of the convertible bonds and the other
long-term debt on the balance sheet are stated net of the unamortised
portion of the issue costs of US$0.2 million (December 2015:
US$0.3 million) and debt arrangement fees of US$23.2 million
(December 2015: US$28.1 million) respectively.
11. FINANCIAL INSTRUMENTS
Derivative financial instruments
The group held the following financial instruments at fair value
at 30 June 2016. The group has no financial instruments with fair
values that are determined by reference to significant unobservable
inputs i.e. those that would be classified as level 3 in the fair
value hierarchy, nor have there been any transfers of assets or
liabilities between levels of the fair value hierarchy.
There are no non-recurring fair value measurements.
At 30 June At 31 December
2016 2015
Level 2 Level 2
$ million $ million
=========================== ======== === === ============ ===============
Financial assets:
Gas forward sale contracts 28.3 16.0
Oil forward sales contracts 52.8 98.2
Interest rate swaps - 4.1
========================================== === ============ ===============
Total 81.1 118.3
=============================================== ============ ===============
Financial Liabilities:
Oil forward sales contracts 10.2 -
Forward foreign exchange contracts 2.6 2.2
Cross currency
swaps 110.0 74.3
Interest rate 6.6 -
swaps
------------------------------------- --- --- ------------ ---------------
Total 129.4 76.5
----------------------------------------------- ------------ ---------------
The fair values were determined from counterparties with whom
the trades have been entered into. 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.
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 2016 At 31 December
2015
------------------------
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:
Bank loans 1,913.0 1,913.0 1,697.0 1,697.0
Senior loan notes 494.6 494.6 493.1 493.1
Retail bond 140.5 199.5 108.8 220.5
Convertible bonds 163.6 235.2 191.1 232.9
-------------------------------- ----------- ----------- ----------- -----------
12. ACQUISITION OF SUBSIDIARIES
On 28 April 2016 (the acquisition date) the Group acquired 100
per cent of the share capital of E.ON E&P UK Ltd ("EPUK"), a
wholly owned subsidiary of E.ON SE, a German listed utility and its
subsidiaries. The acquisition of EPUK brings additional high
quality assets to Premier's UK North Sea business, the opportunity
for cost and operating synergies in the North Sea, more balanced
production portfolio and adds significant immediate production and
cash flow.
The Group reached agreement on the acquisition on 13 January
2016 and the Class I Circular was approved by Premier shareholders
on 25 April 2016. Premier paid total cash consideration of US$135.0
million.
The acquisition has been accounted for as a business
combination. The fair value assessment of the EPUK identifiable
assets and liabilities acquired have been reviewed in accordance
with the provisions of IFRS3 - Business Combinations. The fair
values are provisional and will be finalised in our full year 2016
financial statements.
The fair values of the oil and gas properties and intangible
assets acquired have been determined using valuation techniques
based on discounted cash flows using forward curve commodity
prices, a discount rate based on market observable data and cost
and production profiles consistent with the 2P reserves acquired
with each asset. The financial instruments acquired have been
valued using our forward curve oil and gas price assumptions at the
date of the acquisition. The decommissioning provisions recognised
have been created based on Premier's internal estimates.
The fair value of the identifiable assets and liabilities of
EPUK as at the date of acquisition were:
Fair value
as at
28 April
2016
US$ Million
Assets
Intangible exploration and evaluation assets 105.7
Oil and gas properties 600.0
Other fixed assets 7.1
Long term decommissioning funding asset 85.9
Inventory 2.7
Trade and other receivables 51.4
Derivative financial instruments 59.4
Cash and cash equivalents 24.9
====================================================== =============
937.1
====================================================== =============
Liabilities
Trade and other payables (50.0)
Decommissioning obligations - current (13.7)
Decommissioning obligations - non-current (565.9)
Deferred tax liabilities (65.6)
====================================================== =============
(695.2)
====================================================== =============
Total identifiable net assets acquired at fair value 241.9
Total consideration (135.0)
====================================================== =============
Excess of fair value over cost (negative goodwill) 106.9
====================================================== =============
The excess of fair value over cost has arisen primarily due to
E.On's strategic decision to exit the UK and Norway E&P
sectors, and Premier's willingness to acquire the entire UK
business. The negative goodwill has been recognised immediately in
the condensed consolidated income statement.
From the date of acquisition to 30 June 2016, EPUK contributed
US$44.2 million to Group revenue and increased the Group's profit
before tax by US$5.0 million. If the acquisition of EPUK had taken
place at the beginning of the year, EPUK contribution to Group
revenue for period ended 30 June 2016 would be US$162.7 million and
would have reduced the Group's profit before tax by US$25.0
million.
Costs related to the acquisition represent transaction costs of
US$5.6 million and the recognition of a settlement provision of
US$16.0 million at 30 June 2016 in respect of employee costs.
13. PROVISIONS
The most significant component of the group's provisions balance
relates to the decommissioning of the group's oil and gas
interests, totalling US$1,474.2 million at 30 June 2016 (31
December 2015: US$1,062.6 million). The increase during the period
was primarily due to the E.ON acquisition ($579.6 million - see
note 12) and unwinding of the discount (US$28.7 million), partially
offset by foreign exchange gains of US$154.7 million and other
downward changes in estimates of US$42.3 million.
The large foreign exchange gain relates to the group's UK North
Sea business unit where the underlying decommissioning costs will
largely be incurred in GBP and has been principally caused by a
significant reduction in the USD to GBP exchange rate at 30 June
2016. Included within the foreign exchange gain is an amount of
$100.8 million which has been credited to the income statement,
representing a reduction in the decommissioning cost estimate in
excess of the carrying value recognised for the underlying assets,
with the remaining US$53.9 million netted against the fixed asset
additions figure in note 9.
INDEPENT REVIEW REPORT TO PREMIER OIL PLC
We have been engaged by the company to review the condensed set
of financial statements in the half-yearly financial report for the
six months ended 30 June 2016 which comprises the condensed
consolidated income statement, the condensed consolidated balance
sheet, the condensed consolidated statement of changes in equity,
the condensed consolidated statement of comprehensive income, the
condensed consolidated cash flow statement and related notes 1 to
13. We have read the other information contained in the half-yearly
financial report and considered whether it contains any apparent
misstatements or material inconsistencies with the information in
the condensed set of financial statements.
This report is made solely to the company in accordance with
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. Our work has been undertaken so that we might state to the
company those matters we are required to state to it in an
independent review report and for no other purpose. To the fullest
extent permitted by law, we do not accept or assume responsibility
to anyone other than the company, for our review 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 and Transparency Rules of the United Kingdom's
Financial Conduct Authority.
As disclosed in note 1, the annual financial statements of the
group are prepared in accordance with IFRSs as adopted by the
European Union. The condensed set of financial statements included
in this half-yearly financial report has been prepared in
accordance with International Accounting Standard 34 "Interim
Financial Reporting" as adopted by the European Union.
Our responsibility
Our responsibility is to express to the company a conclusion on
the condensed set of financial statements in the half-yearly
financial report based on our review.
Scope of review
We conducted our review in accordance with International
Standard on Review Engagements (UK and Ireland) 2410 "Review of
Interim Financial Information Performed by the Independent Auditor
of the Entity" issued by the Auditing Practices Board for use in
the United Kingdom. A review of interim financial information
consists of making inquiries, 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 Ireland) 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 2016 is not prepared, in all material respects, in accordance
with International Accounting Standard 34 as adopted by the
European Union and the Disclosure and Transparency Rules of the
United Kingdom's Financial Conduct Authority.
Emphasis of matter - going concern
In forming our conclusion on our review of the condensed
financial statements, we have considered the adequacy of the
disclosure made in note 1 of the condensed financial statements
concerning the group's ability to continue as a going concern. As
disclosed in note 1, the group's projections currently indicate
that a breach of one of the financial covenants within the group's
borrowing facilities is likely to arise in respect of the next
covenant testing period for the 12 months ending 31 August 2016.
Should a covenant breach occur, then the group's debt holders on
all of the group's facilities will have the right to request
repayment of the outstanding debt and to cancel the relevant
facilities.
In order to address the risk of a covenant breach, discussions
are ongoing with Premier's lending group in order to continue
deferring the testing date for the financial covenants whilst
modified terms are agreed. Management expects that the modified
terms will include amendments of the financial covenants such that
there is a reasonable expectation that the group will remain in
compliance with the amended loan facility terms for the foreseeable
future.
Whilst we have concluded that the directors' use of the going
concern basis of accounting in the preparation of the condensed
financial statements is appropriate, these conditions, along with
the other matters explained in note 1, indicate the existence of a
material uncertainty which may give rise to significant doubt over
the group's ability to continue as a going concern. The condensed
financial statements do not include the adjustments that would
result if the group was unable to continue as a going concern. Our
review conclusion is not modified in respect of this matter.
Deloitte LLP
Chartered Accountants and Statutory Auditor
London, UK
17 August 2016
WORKING INTEREST PRODUCTION BY REGION (unaudited)
Six months Six months Year to
to to 31 December
30 June 30 June 2015
2016 2015 kboepd
kboepd kboepd
UK:
Balmoral area* 1.7 3.4 3.2
Huntington** 8.8 6.2 6.2
Wytch Farm 5.1 5.4 5.2
Kyle 1.8 - 1.9
Babbage 1.2 - -
Elgin Franklin 1.7 - -
Other UK 1.9 1.9 0.1
==================== =========== =========== =============
22.2 16.9 16.7
==================== =========== =========== =============
Indonesia:
Natuna Sea Block A 12.5 11.4 12.3
Kakap 1.3 1.8 1.6
-------------------- ----------- ----------- -------------
13.8 13.2 13.9
-------------------- ----------- ----------- -------------
Vietnam:
Chim Sáo 16.7 19.6 16.9
16.7 19.6 16.9
==================== =========== =========== =============
Pakistan:
Bhit/Badhra 2.6 3.3 3.2
Kadanwari 1.1 2.0 1.7
Qadirpur 2.5 2.8 2.7
Zamzama 1.7 2.2 1.9
Mauritania:
Chinguetti 0.4 0.4 0.4
==================== =========== =========== =============
8.3 10.7 10.1
==================== =========== =========== =============
TOTAL 61.0 60.4 57.6
==================== =========== =========== =============
* Includes Balmoral, Brenda, Nicol and Stirling fields.
** Huntington at 100% working interest since completion of the E.ON acquisition
This information is provided by RNS
The company news service from the London Stock Exchange
END
IR UWSRRNSAWARR
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