TIDMENQ
RNS Number : 5123T
EnQuest PLC
21 March 2019
Results for the year ended 31 December 2018 and 2019 outlook
48% production growth and debt reduction delivered in 2018
2019 production growth and debt reduction driven by Magnus
21 March 2019
Unless otherwise stated, all figures are on a Business
performance basis and are in US Dollars.
2018 performance
-- Acquisition of additional interests in Magnus and the Sullom
Voe Oil Terminal completed in December
-- Group production averaged 55,447 Boepd in 2018, up 48.2% on
2017
-- Revenue of $1,201.0 million (2017: $635.2 million) and EBITDA
of $716.3 million (2017: $303.6 million); higher volumes and
realised prices, partially offset by the impact of commodity
hedges
-- Cash generated from operations of $788.6 million (2017:
$327.0 million) reflecting higher EBITDA
-- Cash capital expenditure of $220.2 million (2017: $367.6
million)
-- Cash and available bank facilities amounted to $309.0 million
at 31 December 2018, with net debt of
$1,774.5 million (2017: $1,991.4 million)
-- Net 2P reserves of 245 MMboe and net 2C resources of 198
MMboe at the end of 2018 (2017: 2P reserves of 210 MMboe; 2C
resources of 164 MMboe); growth driven by acquisition of Magnus
2019 performance and outlook
-- Average Group production expected to grow by around 20% to
between 63,000 to 70,000 Boepd; production has averaged 67,700
Boepd in the first two months of the year
-- Operating expenditure expected to be approximately $600
million, including additional interest in Magnus
-- Cash capital expenditures expected to be approximately $275
million; includes a combined total of approximately $100 million
related to deferred payments from prior periods and phasing of
spend from 2018, mainly DC4
-- EnQuest has hedges in place for c.8.0 MMbbls of oil.
Approximately 6.5 MMbbls are hedged at an average floor price of
c.$66/bbl. In accordance with the Oz Management facility agreement,
the Group has a further c.1.5 MMbbls hedged across 2019 with an
average floor price of c.$56/bbl
-- Group's credit facility reduced to $730.0 million following
early repayment of $55.0 million
-- End 2019 Net debt to EBITDA ratio expected to be approaching
2x; EnQuest's target is between 1x and 2x
EnQuest Chief Executive, Amjad Bseisu, said:
"In 2018, the Group met its financial and operational targets.
Production increased by 48%, just above the midpoint of our
guidance, which, along with strong cost control, drove a
significant improvement in cash generation allowing the Group to
reduce net debt.
"FPSO performance has been the main limiting factor in achieving
Kraken's full production potential. As such, our clear operational
priority is to improve Kraken's FPSO uptime and efficiency. We are
working with the FPSO operator on a number of improvement
initiatives.
"We are committed to further reducing our debt, and expect our
net debt to EBITDA ratio to trend towards 2x this year and intend
to operate within our 1-2x target in the future.
"The acquisition of Magnus has added material value to the
business through significant production and reserve growth, and the
application of our production enhancing capabilities are already
improving performance above original expectations.
"In the near term, we remain focused on investing in short-cycle
projects which maximise cash flow and allow us to deliver on our
plans to reduce our debt. We have opportunities for low-cost
material growth in near-field, short-cycle infill and tie-back
investments, particularly at Magnus, PM8/Seligi and Kraken.
"Longer term, our capital allocation will balance investment to
develop our asset base, returns to shareholders and the acquisition
of suitable growth opportunities."
Production and financial information
2018 2017 Change
%
Production (Boepd) 55,447 37,405 48.2
------------------------------------- ---------- ---------- -------
Revenue and other operating income
($m)(1) 1,201.0 635.2 89.1
------------------------------------- ---------- ---------- -------
Realised oil price ($/bbl)(1) 61.2 52.2 17.2
------------------------------------- ---------- ---------- -------
Gross profit ($m) 275.0 65.7 318.6
------------------------------------- ---------- ---------- -------
Profit before tax & net finance
costs ($m) 290.0 47.3 513.1
------------------------------------- ---------- ---------- -------
EBITDA ($m)(2) 716.3 303.6 135.9
------------------------------------- ---------- ---------- -------
Cash generated from operations
($m) 788.6 327.0 141.2
------------------------------------- ---------- ---------- -------
Reported profit after tax ($m) 127.3 (60.8) -
------------------------------------- ---------- ---------- -------
Reported basic earnings per share
(cents)(3) 10.4 (4.6) -
------------------------------------- ---------- ---------- -------
Cash capex ($m) 220.2 367.6 (40.1)
------------------------------------- ---------- ---------- -------
End 2018 End 2017
------------------------------------- ---------- ---------- -------
Net (debt)/cash ($m)(4) (1,774.5) (1,991.4) (10.9)
------------------------------------- ---------- ---------- -------
Notes:
1 Including losses of $93.0 million (2017: losses of $20.6
million) associated with EnQuest's oil price hedges
2 EBITDA is calculated on a Business performance basis, and is
calculated by taking profit/loss from operations before tax and
finance income/(costs) and adding back depletion, depreciation,
foreign exchange movements, inventory revaluation and the realised
gains/loss on foreign currency derivatives related to capital
expenditure
3 2017 reported earnings per share has been restated for the
bonus element of the rights issue
4 Net (debt)/cash represents cash and cash equivalents less
borrowings, stated excluding accrued interest and the net-off of
unamortised fees
Production details
Production on a Net daily Net daily
working interest average average
basis 1 Jan' 2018 1 Jan' 2017
to to
31 Dec' 31 Dec'
2018 2017
------------------- ---- ------------- -------------
(Boepd) (Boepd)
Northern North
Sea 19,293(1) 15,627(2)
Central North Sea 6,353 8,131
Kraken 21,369 4,709(3)
------------- -------------
Total UKCS 47,015 28,467
------------- -------------
Total Malaysia 8,432 8,938
-------------
Total EnQuest 55,447 37,405
7
------------- -------------
Notes:
1 Includes net production related to 25% interest in Magnus
until 30 November 2018 and 100% interest of Magnus from 1 December
2018, averaged over the 12 months to the end of December 2018
2 Includes net production from the initial 25% interest in
Magnus from 1 December 2017, averaged over the 12 months to the end
of December 2017
3 Net production since first oil on 23 June, averaged over the
12 months to the end of December 2017
2018 performance summary
During 2018, the Group was focused on meeting its financial and
operational targets and facilitating debt reduction. The successful
acquisition of Magnus, the Sullom Voe Terminal and related
infrastructure assets from BP was a great testament to our people's
focus on delivery and excellent team collaboration. The Group's
collective efforts delivered a set of assets with a strong
strategic fit into the portfolio. EnQuest's cash generation
capability has improved through the acquisition of Magnus in
particular and the Group is well positioned to meet its debt
repayment schedule and capital programme in 2019 and beyond.
In line with the Group's guidance, EnQuest's average production
increased by 48.2% to 55,447 Boepd, primarily reflecting the
contributions from Kraken and Magnus, a better than expected
performance at Heather, Alma/Galia and Scolty/Crathes, partially
offset by natural declines.
The combination of significantly higher production, higher
realised prices and the Group's focus on cost control resulted in
EBITDA and cash generated by operations more than doubling in 2018
compared to 2017, reaching $716.3 million and $788.6 million,
respectively.
As expected, cash capital expenditure of $220.2 million was
materially lower than 2017. The majority of the expenditure was at
Kraken, although the delayed arrival of the Transocean drilling rig
resulted in the DC4 drilling programme and associated costs being
phased into 2019, with the remaining spend largely reflecting
drilling activities at Heather/Broom and PM8/Seligi.
Liquidity and net debt
During the year, EnQuest continued to manage its liquidity
position actively and ensuring the Group is able to deploy capital
and resources to those key projects which maximise cash flow to
facilitate debt reduction.
In January, the Group agreed to receive $30.0 million in cash
from BP in exchange for undertaking the management of the physical
decommissioning of the Thistle and Deveron fields and making
payments by reference to 4.5% of BP's decommissioning costs of
these fields when spend commences. Following shareholder approval
at the General Meeting held in October, EnQuest received a further
$20.0 million in cash in exchange for increasing its total payment
obligation of BP's decommissioning costs of the Thistle and Deveron
fields by 3.0% to 7.5%.
In February, the Group completed the $37.25 million refinancing
agreement in relation to its Tanjong Baram project, providing
approximately $25.0 million in additional liquidity.
In September, the Group agreed $175 million of financing with
funds managed by Oz Management. The financing is ring-fenced on a
15% interest in the Kraken oil field and will be repaid out of the
cash flows associated with the 15% ring-fenced interest over a
maximum of five years.
In October, following shareholder approval at the General
Meeting, net proceeds of around $128.9 million were raised through
a rights issue in which the Group received valid acceptances in
respect of 95.5% of the total number of new ordinary shares offered
pursuant to the rights issue. $100.0 million of the proceeds were
used to fund EnQuest's share of the consideration in relation to
acquiring the remaining 75% interest in Magnus and additional
interests in the Sullom Voe Terminal and associated infrastructure.
The balance will be used to fund a two-well infill drilling
programme in 2019.
During the year, the Group's improved cash generation and the
Kraken financing agreement facilitated the cancellation and
repayment of $340.0 million of the Group's credit facility.
At the end of the year, net debt was reduced by 10.9% to
$1,774.5 million, with total cash and available facilities of
$309.0 million, including ring-fenced accounts associated with
Magnus, the Oz Management facility and other joint venture accounts
totalling $107.3 million.
Reserves and resources
Net 2P reserves at the end of 2018 were 245 MMboe (2017: 210
MMboe) and have been audited on a consistent basis with prior
years. This represents a reserve life of 13 years. The reserve
replacement ratio was 184%, driven by the acquisition of an
additional 75% equity interest in Magnus. Net 2C resources at the
end of 2018 were 198 MMboe (2017: 164 MMboe) and included an
additional 40 MMboe of 2C resources associated with the Magnus
acquisition.
2019 performance and additional outlook details
At Magnus, performance has remained strong through the first two
months of the year. FPSO performance has continued to limit
production performance at Kraken. All DC4 wells are now onstream
and, as FPSO maintenance activities are completed, production is
expected to significantly improve. We continue to expect to deliver
gross production of between 30,000 and 35,000 Bopd from Kraken.
Elsewhere across the portfolio, aggregate production has been
broadly in line with the Group's expectations.
2019 production is expected to grow by around 20% to between
63,000 and 70,000 Boepd, primarily driven by Magnus. Production
from DC4 at Kraken, where all three wells are now onstream, and the
anticipated improvement in performance at Scolty/Crathes following
the installation of the replacement pipeline scheduled for the
third quarter of 2019 are expected to offset natural declines
elsewhere across the portfolio.
The successful delivery of the capital programme, which includes
drilling at Kraken, Magnus and PM8/Seligi combined with
project-related expenditures at Scolty/Crathes and Thistle/Deveron
and the Dons, will underpin production during 2019 and beyond.
Debt repayment remains the priority for the Group, and will be
enabled through its improved cash-generation capability combined
with its focus on cost control and capital discipline. In March,
the Group reduced its credit facility by $55.0 million to $730.0
million, ahead of the scheduled amortisation due in April, which
now has a balance due of $50.0 million. At the end of 2019, the
Group expects overall net debt to EBITDA to be approaching 2x, with
the Group intending to operate between 1x and 2x in the future.
Summary financial review of 2018
(all figures quoted are in US Dollars and relate to Business
performance unless otherwise stated)
Revenue and other operating income for 2018 was $1,201.0
million, 89.1% higher than 2017 ($635.2 million). This increase
reflects the material increase in volumes and higher realised
prices, partially offset by realised losses of $93.0 million
associated with the Group's commodity hedge programme (2017: losses
of $20.6 million), which reflected the timing at which the hedges
were entered into and the increase in market prices during the
first half of 2018 in particular. The Group's blended average
realised oil price was $61.2/bbl in 2018, compared to $52.2/bbl
during 2017. Excluding this hedging impact, the average realised
oil price was $66.2/bbl in 2018, 22.8% higher than 2017
($53.9/bbl), reflecting higher market prices. Revenue is
predominantly derived from crude oil sales which totalled $1,237.6
million, 94.3% higher than 2017 ($637.0 million), reflecting the
material increase in volumes and higher realised prices. Revenue
from the sale of condensate and gas was $43.1 million (2017: $2.8
million) as a result of increased gas sales from Magnus, which
includes the combination of produced gas sales and the onward sale
of third-party gas purchases not required for injection activities,
for which the costs are included in other cost of sales.
Total cost of sales for 2018 was $926.0 million, 62.6% higher
than 2017 ($569.5 million). This included non-cash depletion
expense of $437.1 million, 95.9% higher than 2017 ($223.1 million)
as a result of increased production, primarily at Kraken and
Magnus.
Operating expenditures of $465.9 million were 33.4% higher than
2017 ($349.3 million), reflecting the full year contribution of
Kraken and Magnus, partly offset by the benefit of a weaker
Sterling exchange rate. The Group's average unit operating cost for
2018 was $23.0/Boe, 10.2% lower than 2017 ($25.6/Boe) primarily as
a result of the material increase in production.
Other cost of sales increased by $35.4 million to $48.1 million
compared to 2017 ($12.7 million), principally reflecting the cost
of additional Magnus related third-party gas purchases not required
for injection activities.
Other net income of $19.1 million (2017: net expense of $17.6
million) primarily comprise net foreign exchange gains as a result
of revaluing Sterling-denominated amounts on the balance sheet
following the weakening of Sterling against the US Dollar.
EBITDA for 2018 was $716.3 million, 135.9% higher than 2017
($303.6 million) largely as a result of higher production and
higher realised prices increasing Group revenues.
The tax credit for 2018 of $20.9 million (2017: $66.0 million
tax credit), excluding exceptional items, is due predominantly to
the Ring Fence Expenditure Supplement on UK activities.
Post-tax exceptional items for 2018 were a gain of $49.1 million
(2017: losses of $27.3 million). The gain in 2018 primarily
reflects the non-cash increase in fair value of $74.3 million
recognised under step acquisition accounting on the initial
interests in the assets acquired from BP in December 2017 following
completion of the acquisition of additional interests in these
assets in December 2018. Post-tax non-cash impairments of oil and
gas assets of $78.7 million were largely offset by post-tax
unrealised gains on commodity contracts of $59.9 million.
Net debt at 31 December 2018 was $1,774.5 million, a decrease of
10.9% compared to 2017 ($1,991.4 million) primarily as a result of
the improved cash generating capability of the Group and lower cash
capital expenditure programme in 2018 of $220.2 million (2017:
$367.6 million), principally at Kraken. Excluding Payment in Kind
interest ('PIK'), net debt was $1,642.5 million (2017: $1,900.9
million).
UK corporate tax losses at the end of the year were $3,225.3
million (2017: $3,121.3 million).
Ends
For further information please contact:
EnQuest PLC Tel: +44 (0)20 7925 4900
Amjad Bseisu (Chief Executive)
Jonathan Swinney (Chief Financial Officer)
Ian Wood (Communications & Investor Relations)
Tulchan Communications Tel: +44 (0)20 7353 4200
Martin Robinson
Martin Pengelley
Presentation to Analysts and Investors
A presentation to analysts and investors will be held at 09:30
today - London time. The presentation and Q&A will also be
accessible via an audio webcast, available on the investor
relations section of the EnQuest website at www.enquest.com. A
conference call facility will also be available at 09:30 on the
following numbers:
Conference call details:
UK: +44 (0)800 376 7922 or +44 (0) 844 571 8892
International: +44 (0) 207 192 8000
Confirmation Code: EnQuest
Notes to editors
This announcement has been determined to contain inside
information.
ENQUEST
EnQuest is an independent production and development company
with operations in the UK North Sea and Malaysia. The Group's
strategic vision is to be the operator of choice for maturing and
underdeveloped hydrocarbon assets by focusing on operational
excellence, differential capability, value enhancement and
financial discipline.
EnQuest PLC trades on both the London Stock Exchange and the
NASDAQ OMX Stockholm. Its UK operated assets include
Thistle/Deveron, Heather/Broom, the Dons area, Magnus, the Greater
Kittiwake Area, Scolty/Crathes Alma/Galia and Kraken; EnQuest also
has an interest in the non-operated Alba producing oil field. At
the end of December 2018, EnQuest had interests in 18 UK production
licences and was the operator of 16 of these licences. EnQuest's
interests in Malaysia include the PM8/Seligi Production Sharing
Contract and the Tanjong Baram Risk Services Contract, both of
which the Group operates.
Forward-looking statements: This announcement may contain
certain forward-looking statements with respect to EnQuest's
expectation and plans, strategy, management's objectives, future
performance, production, reserves, costs, revenues and other trend
information. These statements and forecasts involve risk and
uncertainty because they relate to events and depend upon
circumstances that may occur in the future. There are a number of
factors which could cause actual results or developments to differ
materially from those expressed or implied by these forward-looking
statements and forecasts. The statements have been made with
reference to forecast price changes, economic conditions and the
current regulatory environment. Nothing in this announcement should
be construed as a profit forecast. Past share performance cannot be
relied on as a guide to future performance.
Chairman's statement
EnQuest performance overview
In 2018, EnQuest took a further significant step forward in
strengthening the business and adding to its potential. The
exercise of the Magnus Option, which received very strong support
from our shareholders to acquire the remaining 75% equity interest
in Magnus, provided the Group with an immediate and material
increase to its 2P reserves, production and cash flow. Magnus
performance has been strong since EnQuest assumed operatorship in
December 2017 and the application of the Group's differential
capabilities saw production increase significantly in late
2018.
While production from Kraken was below our expectations,
primarily reflecting FPSO performance and weather-related outages,
the strong production performance across the Group elsewhere saw
EnQuest meet its production growth target. The Group's improved
cash-generating capability and the execution of the Kraken
financing agreement enabled the Group to make material repayments
on its bank debt. Debt reduction remains a priority for
EnQuest.
The Group's net 2P reserves were up approximately 17% after
accounting for the increased production in 2018, driven by the
additional 75% interest in Magnus. By the end of 2018, EnQuest had
a net 2P reserves base of 245 MMboe, which represents average
growth of approximately 13% per annum since EnQuest's formation
nine years ago and a reserves life of around 13 years.
Industry context
For much of 2018, we saw a steady improvement in the oil price,
reflecting a combination of strong growth in global demand coupled
with increasing constraints on supply. However, during the fourth
quarter, concerns over a weakening demand outlook and expectations
of over-supply saw a rapid deterioration in the oil price, which
dipped to around $50/bbl in late December. Since then, the price
has recovered to within the range of c.$65/bbl and c.$68/bbl.
Throughout this period of volatility, we have remained focused on
achieving our targets, maintaining and enhancing production while
controlling costs and capital expenditure. It is vital we continue
to keep this focus through 2019 with ongoing oil price
uncertainty.
The Directors believe that the UK Continental Shelf remains an
attractive investment proposition. While there may be some
disruption to the supply chain from the impacts of the UK's
proposed exit from the European Union, the Directors are confident
that such issues can be overcome. The industry has worked hard in
recent years to reduce its operating and capital costs,
facilitating delivery on the UK Government's strategy of Maximising
Economic Recovery of the significant hydrocarbons that remain in
place. This competitive regulatory structure is further supported
by a competitive fiscal regime, an extensive installed
infrastructure base, access to a world-leading supply chain and a
highly skilled workforce. EnQuest has been successful in
replicating its UK operating model in Malaysia, another maturing
region with significant hydrocarbons in place, and where the Group
has a strong partnership with PETRONAS.
EnQuest's Board
As previously noted in EnQuest's 2017 Annual Report and
Accounts, we were extremely pleased to welcome Laurie Fitch to the
Board. Laurie joined the Company on 8 January 2018 and became a
member of both the Risk and Remuneration Committees. In January
2019, as planned, Laurie succeeded Helmut Langanger as the Chair of
the Remuneration Committee. Helmut has chaired the Committee for
nine years, developing open and transparent communications with our
investors as we have shaped an effective remuneration policy. I
would like to take this opportunity to thank Helmut for his
valuable leadership over this period. We are pleased he will
continue to be a member of the Remuneration Committee to aid
Laurie's transition into the role.
As a Board, we remain conscious of the need to have an effective
succession plan that ensures the Board has the correct composition
of skills and experience to continue its support of the executive
management team in executing the Group's strategy. We are therefore
very pleased that, subject to shareholder approval at the annual
general meeting, Howard Paver will join the Board. Howard is a
petroleum engineer by background and has 40 years of oil and gas
experience working for Hess, BHP Petroleum, Mobil and Schlumberger
in various senior leadership positions. His significant knowledge
in production and development, as well as experience of managing
complex assets in various parts of the globe, will bring technical
and commercial skills to the Board. This is of particular relevance
as Helmut Langanger, who has over 40 years of industry experience,
will be rotating off the Board in due course.
In 2019, both Helmut and I will have served as Directors of the
Company for nine years. With the completion of the Magnus option
and following on from the Company's financial restructuring in late
2016, the Company is positioned to pursue its strategic goals and,
as is now appropriate, Helmut, as Senior Independent Director, is
leading a process to identify a candidate to replace me as Chairman
and take the Company forward to the next phase of its development.
It is envisaged that after my succession process has completed,
Helmut will retire from the Board.
EnQuest's people
In 2018, the Group was focused on meeting its operational and
financial targets and maintaining cost and capital discipline in a
volatile macro environment. The capital raise, via a rights issue,
to facilitate the strategically important acquisition of additional
interests in Magnus, the Sullom Voe Terminal and associated
infrastructure from BP, and the financing associated with Kraken,
all required significant amounts of the Board's and management's
time and attention. Additionally, achieving all of these objectives
has only ultimately been possible due to EnQuest's people. The
Board and I would like to express our gratitude to everyone, both
new and old, at EnQuest for their drive, commitment and
professionalism in delivering Safe Results, meeting our targets and
completing the acquisition of assets from BP to give the Company an
even stronger base upon which to build for the future.
Following the results of our culture survey in 2017, the Group's
Values were refreshed through a series of group-wide focus groups
and workshops. This process has ensured that our Values embody
everything the Company stands for and align with the aspirations of
our people, acting as a guide in the pursuit of EnQuest's strategy.
Through 2019, the refreshed Values will be incorporated into a
number of the Group's processes, including those in Human Resources
and Health, Safety, Environment and Assurance.
In early 2019, the Board approved the establishment of an
Employee Forum to improve engagement and interaction between the
workforce and the Board. This supplements the Group's existing
employee engagement activities and is in line with the revised
Corporate Governance Code published in July 2018.
Strategy and governance
The Directors provide strategic guidance and challenge to
executive management and take key decisions on the implementation
of the Group's strategy. EnQuest's governance framework also
contains several non-Board Committees, which provide advice and
support to the Chief Executive, including an Executive Committee,
Investment Committee and HSE&A Committee.
The Group welcomes the drive for increased governance and
transparency in general, and specifically in relation to climate
change. The Board recognises the increasing societal, media and
investor focus on climate change and the desire to understand its
potential impacts on the oil and gas industry through improved
disclosure, utilising mechanisms such as those proposed by the Task
Force on Climate-related Financial Disclosures. Through the Risk
and Audit Committees, the Board has continued to review the
potential risk of climate change on the effective execution of the
Group's strategy and has concluded that, on a standalone basis,
climate change is not a principal risk but one factor amongst
others influencing our assessment of the Group's principal risks,
the details of which can be found on pages 20 to 28. The Risk
Committee will continue to undertake detailed analyses of specific
risk areas to ensure that the potential effects of climate change
continue to be identified, considered and assessed appropriately
within the Group's Risk Management Framework. Further, the Board,
in particular through the work of the Risk Committee, has been
active in supporting the continued evolution of the Group's Risk
Management Framework to
enhance effective risk management within the Board-approved risk
appetite of the Company. Through this process, the Risk Committee
reviewed all risk areas faced by the Group and identified the
causes of risk and their associated impacts and mapped these to the
preventative and containment controls used to manage such risks to
acceptable levels.
Ensuring that the Board works effectively remains a key focus of
the Company. During the year, an external evaluation of the Board
was held which recognised the improvements made in the Group's
governance since the last external evaluation in 2016. It also
identified additional areas for consideration to drive continuous
improvement in this area. The most important area discussed related
to Board succession planning, which I have already outlined. The
Board is committed to delivering the highest standards of corporate
governance. Activities are already under way in relation to the
changes to the Corporate Governance Code announced in July 2018 and
the Board is actively engaged in the implementation of the
necessary processes and procedures that will enable continued
compliance.
The Board believes that the manner in which the Group conducts
its business is important. In the execution of our strategy, we are
committed to working responsibly for the benefit of all our
stakeholders. The Board has approved the Company's overall approach
to corporate responsibility, which is focused on five main areas.
These are: Health and Safety; People; Environment; Business
Conduct; and Community. The Board receives regular information on
the performance of the Company in these areas, and specifically
monitors health, safety and environmental reporting at each Board
meeting. The Company's Health, Safety, Environment & Assurance
('HSE&A') Policy is reviewed by the Board annually and all
incidents, forward-looking indicators and significant HSE&A
programmes are discussed by the Board. Specific developments and
updates in all areas are brought to the Board's attention when
appropriate. Having undertaken a detailed review of the Group's
HSE&A processes, the Risk Committee recommended the addition of
HSE&A oversight and review within its scope of work to
supplement and assist the Board in reviewing such matters.
The Group has a Code of Conduct that it requires all personnel
to be familiar with as it sets out the behaviour which the
organisation expects of its Directors, managers and employees, as
well as suppliers, contractors, agents and partners.
Dividend
The Company has not declared or paid any dividends since
incorporation and does not plan to pay dividends in the immediate
future. However, the Board anticipates reviewing the policy when
appropriate, the timing of which will be subject to the oil price
environment, the capital structure of the Company and its expected
future cash flows.
2019: continued focus on delivery and debt reduction
We have made significant progress in 2018, meeting our targets
and making substantial repayments of our bank debt. The acquisition
of Magnus diversifies our production portfolio and, along with
Kraken and PM8/Seligi, provides the Group with material future
production opportunities. In 2019, we must continue to focus on
delivering on our targets to facilitate the effective management of
our liquidity position and capital structure. With the oil price
environment remaining volatile, we recognise that we must maintain
our focus on financial discipline, cost efficiencies and managing
Group liquidity. We will continue to prioritise our resources to
those projects which maximise cash flow to facilitate debt
reduction, continuing the Company's progress towards a more
sustainable balance sheet which will enable the long-term growth of
the business.
Chief Executive's report
Overview
During 2018, the Group was focused on meeting its financial and
operational targets and facilitating debt reduction. The successful
acquisition of Magnus, the Sullom Voe Terminal and related
infrastructure assets from BP was a great testament to our people's
focus on delivery and excellent team collaboration. The Group's
collective efforts delivered a set of assets with a strong
strategic fit into the portfolio. EnQuest's cash-generation
capability has improved through the acquisition of Magnus in
particular and we are well positioned to meet our debt repayment
schedule and capital programme in 2019 and beyond.
Operational performance
EnQuest's average production increased by 48.2% to 55,447 Boepd,
above the mid-point of the Group's guidance. The increase reflected
the contributions from Kraken and Magnus, along with a better than
expected performance at Heather, Alma/Galia and Scolty/Crathes,
partially offset by natural declines.
Following strong shareholder support for the rights issue
undertaken in October, EnQuest completed the acquisition of
additional interests in Magnus, the Sullom Voe Terminal and related
infrastructure in December. The additional interest in Magnus and
the success of plant debottlenecking and well intervention work
drove a substantial and better than expected increase in
production.
The acquisition of Magnus also drove a material increase in net
2P reserves to 245 MMboe at the end of 2018, up 17% on the 210
MMboe at the end of 2017, and was a key component in the Group
achieving a reserves replacement ratio of 184%. While production at
Kraken has been below expectations, with FPSO performance the main
limiting factor, the Group's reserves position for Kraken remains
materially unchanged. Since the Company was formed with around 81
MMboe of 2P reserves, the Group has achieved a compound average
reserves growth of 13%, with remaining 2P reserves representing a
current production life of around 13 years.
Financial performance
The combination of increased production and higher realised
prices drove an improved financial performance in 2018. Both EBITDA
and cash generated by operations more than doubled, to $716.3
million and $788.6 million respectively. The Group's ongoing focus
on cost control kept operating expenditure to $465.9 million, with
unit operating costs reduced to around $23.0/Boe. Capital
expenditure was also significantly lower year on year, down $147.4
million to $220.2 million, primarily driven by the reduced
programme at Kraken.
EnQuest reviewed a number of potential opportunities to realise
value from the Kraken asset. Having reviewed the various options
available to the Group, the Board approved the financing
arrangement for $175 million, ring-fenced on a 15% interest in the
Kraken oil field, with funds managed by Oz Management, as the
preferred economic option at the time. We continue to keep a future
potential equity farm-down at Kraken under review.
The combination of this financing agreement and strong
underlying business performance facilitated accelerated repayments
of the Group's credit facility, which reduced by $340.0 million,
from $1,125.0 million to $785.0 million, excluding the revolving
credit facility. The Group ended the year with net debt of $1,774.5
million, down from $1,991.4 million at the end of 2017 and further
debt reduction remains a near-term priority for the Group.
Health, Safety, Environment and Assurance ('HSE&A')
As always, Safe Results is our number one priority and we have
had excellent results in many areas, meeting the majority of our
performance targets. In Malaysia, we again had zero lost-time
incidents ('LTI'), with PM8/Seligi achieving eight years LTI free,
and we reduced the number of hydrocarbon release events. This
strong performance came against a backdrop of high activity levels
offshore. In the UK North Sea, our colleagues on the Kittiwake
platform recorded their 13th year without an LTI with many of our
other assets also delivering an LTI-free year. However, we saw an
increase in the number of hydrocarbon release events and had a
high-potential dropped-object incident on Magnus associated with
lifting operations. These serve to highlight that we must remain
focused on safety at all times and aim for continuous improvement
in all that we do.
The main sources of atmospheric emissions from EnQuest assets
are derived from combustion plant associated with power generation
and flaring. As such, while overall extraction emissions increased
in 2018, largely as a result of the addition of Magnus to our
portfolio, our improved production performance drove our
extraction-related greenhouse gas emissions intensity ratio lower
by 17.6%. In Malaysia, the team's focus on minimising emissions
resulted in flaring at PM8/Seligi being maintained at around 35%
below the annual flare consent from the regulator.
While hydrocarbons are expected to remain a key element of the
UK and global energy mix, the Group recognises that it must
endeavour to minimise carbon emissions from its operations as far
as practicable as it seeks to enhance hydrocarbon recovery and
extend the useful lives of mature and underdeveloped assets and
associated infrastructure in a profitable and responsible manner.
Our strategy of acquiring assets and extending their economic life
facilitates the industry's move from long-term, 'full-cycle'
expenditure to lower-carbon energy supply sources while helping to
fulfil energy demand requirements during this transition
period.
UK North Sea operations
Production from the UK North Sea was materially higher in 2018
than in 2017. This increase was driven by a combination of
additional production from Kraken and Magnus and the successful
execution of our planned work programmes.
At Magnus, the team successfully undertook plant
de-bottlenecking and water injection system improvements. Two new
wells were drilled and brought online, with further production
improvements driven by successful well intervention activities.
Following our two-well drilling campaign in 2018, a further
two-well programme will commence in 2019, along with additional
intervention and plant improvement activities. Future material
infill drilling opportunities continue to be refined and assessed
to maximise recovery from the significant remaining resources in
place.
Further drilling successes were achieved at Heather, Thistle and
Alma/Galia. The H-67 well at Heather delivered above the Group's
pre-drill expectations and the Group began its well abandonment
campaign at Heather in December following the successful execution
of six well abandonments at Thistle. The replacement of three
Electric Submersible Pumps at Alma/Galia resulted in production
restoration in line with the Group's plans.
At both Alma/Galia and Scolty/Crathes, production was better
than expected as a result of improved production efficiency and the
successful management of wax deposition, respectively. The
successful production optimisation strategy at Scolty/Crathes has
resulted in the project achieving payback just over two years after
start-up, despite the wax deposition challenges meaning only the
Crathes reservoir has delivered production and revenues.
During the year, we sanctioned the Scolty/Crathes pipeline
replacement project, to remedy the wax deposition-related
production restrictions, and the Dunlin bypass, which will see
volumes from Thistle and the Dons exported via the Magnus facility
and Ninian Pipeline System to the Sullom Voe Terminal. Both
projects help underpin longer-term production from these assets.
Elsewhere, the Group continues to assess development options for
the Eagle Discovery and at Dons North East.
Production at Kraken was below expectations, reflecting a number
of FPSO and weather-related outages throughout the year. Our clear
operational priority in 2019 is to improve FPSO uptime and
efficiency. We are working with the FPSO operator on a number of
improvement initiatives to maximise facility uptime to enable
stable production. Reservoir performance has been strong and
remains broadly in line with the Group's expectations. We have seen
excellent communication between producer and injector wells and our
improving management of reservoir voidage following repairs to the
water injection system also supported reservoir deliverability.
The delayed arrival of the drilling rig at Drill Centre 4
('DC4') resulted in drilling commencing later than planned with
first production from the wells being rephased accordingly.
Drilling at DC4 is nearing completion, with the first two of three
wells now onstream. We continue to assess future opportunities at
Kraken that have material volumes of oil in place for future
development, such as the Western Flank.
At the Sullom Voe Terminal, the Group reduced terminal operating
costs by around 25%, to approximately GBP150.0 million, through the
implementation of a number of efficiency initiatives. We also
assisted in three ship-to-ship transfers of oil in the Port of
Sullom Voe, and the Group continues to explore opportunities to
maximise the long-term value of the terminal.
Malaysia operations
Production in 2018 was slightly lower than in 2017, primarily
reflecting natural decline at Tanjong Baram. Our focus on asset
integrity, which included underwater structural integrity
assessments and gas compressor rejuvenation, helped drive continued
high levels of production efficiency at PM8/Seligi. The regulator
recognised the Group's efforts with an award for the 'Highest
Improvement' in relation to offshore self-regulation. Our programme
of well interventions continues to be successful in arresting the
field's decline, and we successfully concluded EnQuest's first ever
drilling campaign at PM8/Seligi, with aggregate production from the
two new wells in line with expectations.
EnQuest will continue its asset life extension activities in
2019 through further investment in two new wells, idle well
restoration and facility improvements and upgrades. Technical
studies to support future development drilling and secondary
recovery projects to increase ultimate recovery from the material
volumes in place in PM8/Seligi are also under way.
2019 performance and outlook
Following effective reservoir management and well intervention
work at Magnus, performance has remained strong through the first
two months of the year. FPSO performance has continued to limit
production performance at Kraken. All DC4 wells are now onstream
and, as FPSO maintenance activities are completed, production is
expected to significantly improve. We continue to expect to deliver
gross production of between 30,000 and 35,000 Bopd from Kraken.
Elsewhere across the portfolio, aggregate production has been
broadly in line with the Group's expectations.
2019 production is expected to grow by around 20% to between
63,000 and 70,000 Boepd, primarily driven by Magnus. Production
from DC4 at Kraken, where all three wells are now onstream, and the
anticipated improvement in performance at Scolty/Crathes following
the installation of the replacement pipeline scheduled for the
third quarter of 2019 are expected to offset natural declines
elsewhere across the portfolio.
The successful delivery of the capital programme, which includes
drilling at Kraken, Magnus and PM8/Seligi combined with
project-related expenditures at Scolty/Crathes and Thistle/Deveron
and the Dons, will underpin production during 2019 and beyond.
Debt repayment remains the priority for the Group, and will be
enabled through its improved cash-generation capability combined
with our focus on cost control and capital discipline. In March,
the Group reduced its credit facility by $55.0 million to $730.0
million, ahead of the scheduled amortisation due in April, which
now has a balance due of $50.0 million. At the end of 2019, the
Group expects overall net debt to EBITDA to be approaching 2x, with
the Group intending to operate between 1x and 2x in the future.
Longer-term development
In the near term, we remain focused on delivering on our plans
to reduce our debt. We also have the opportunity for material
growth where our portfolio has significant potential for
near-field, short-cycle development, particularly at Magnus,
PM8/Seligi and Kraken.
After we have reduced our debt to sustainable levels, and
dependent on price conditions and company performance, our capital
allocation will balance investment to develop our asset base,
returns to shareholders and the acquisition of suitable growth
opportunities. The application of our proven capabilities in
enhancing hydrocarbon recovery from mature and underdeveloped
assets means we are well placed to pursue long-term sustainable
growth.
Operating review
Northern North Sea operations
Daily average net production:
-- 2018: 19,293 Boepd1
-- 2017: 15,627 Boepd2
Notes:
1 Includes net production related to 25% interest in Magnus
until 30 November 2018 and 100% interest of Magnus from 1 December
2018, averaged over the 12 months to the end of December 2018
2 Includes net production from the initial 25% interest in
Magnus since the acquisition on 1 December 2017, averaged over the
12 months to the end of December 2017
2018 performance summary
Production in 2018 of 19,293 Boepd was 23.5% higher than in
2017, primarily reflecting a full year's contribution from Magnus
and better than expected performance from the H-67 well at Heather,
which came online in March, partially offset by natural declines
across the area. Good production and water injection efficiency
performance was achieved at Heather/Broom, Thistle and the Dons,
with production efficiency at each of these fields above 80%.
Magnus performance has been strong throughout 2018, also
achieving production efficiency above 80%. Successful plant
de-bottlenecking, completion of the planned maintenance shutdown
and additional production following the two well drilling campaign
were complemented by successful well intervention activities. Water
injection performance has been strong, with high levels of uptime
throughout the year, reflecting the Group's analysis of historical
power generation reliability and a focus on alleviating downtime
issues.
EnQuest continued to pursue a series of partner-funded idle well
reservoir abandonments as part of the Group's asset life extension
strategy, improving asset integrity and reducing longer-term
decommissioning costs. At Thistle, six well abandonments were
successfully concluded ahead of schedule and at a lower cost than
budgeted, with the team subsequently mobilised to Heather to
undertake abandonment work on two wells. In June, the Dunlin bypass
export project was sanctioned which, once completed, will see
volumes from Thistle and the Dons exported via the Magnus facility
and Ninian Pipeline System to the Sullom Voe Terminal.
At the Sullom Voe Terminal, the Group made excellent progress in
the optimisation of its planned work programme and identified and
implemented a number of cost-saving initiatives. The Group was
successful in reducing terminal operating costs by around 25% to
approximately GBP150.0 million through focused supply chain
management, efficient project delivery and simplifying and
improving utilisation of the resources on site. These savings were
achieved while delivering a strong safety performance and high
levels of site availability. In line with the Group's aim to
maximise the long-term value of the terminal, the Group has worked
with the Shetland Islands Council and other stakeholders to deliver
three ship-to-ship transfers of crude oil at the terminal.
2019 performance and outlook
Strong production performance at Magnus has continued, with
aggregate production elsewhere broadly in line with the Group's
plans.
At Magnus, the Group is focused on maintaining and improving
production through a combination of drilling two new wells, further
well intervention activity and increases in the facility's water
injection capacity by returning to service the second of two
deaeration towers on the asset and improving pump operations.
EnQuest will continue to optimise the volumes and placement of both
injected water and gas to maintain production. A three-week
shutdown is planned for the second quarter.
The planned two-week maintenance shutdowns at Thistle and the
Dons are expected to take place in the summer and have been
coordinated with the operator of the existing third-party export
route and the timing of the installation of the Dunlin bypass
pipeline to minimise downtime during the pipeline's commissioning
phase. Drilling of the Dons North East prospect continues to be
evaluated.
At Heather/Broom, further well abandonments are expected to be
executed during the year along with a scheduled three-week shutdown
in the third quarter. Further well intervention and drilling
opportunities are being developed.
Central North Sea operations
Daily average net production:
-- 2018: 6,353 Boepd
-- 2017: 8,131 Boepd
2018 performance summary
Production in 2018 of 6,353 Boepd was 21.9% lower than in 2017.
The reduction was primarily driven by the expected performance at
both Scolty/Crathes and Alma/Galia, although production at both
assets was slightly better than anticipated with production
efficiency at both fields above 80%.
At Alma/Galia, three failed Electric Submersible Pumps ('ESP')
were successfully replaced during the third quarter, restoring
aggregate production in line with plans. Production and water
injection efficiency were strong, although partially offset by the
end of production from the Galia reservoir following the cessation
of the originally installed ESP.
Good management of wax deposition at Scolty/Crathes drove a
better than expected performance and the installation of the new
pipeline was sanctioned in June. Wax restrictions on production
will continue to be managed until the pipeline is operational.
Aggregate production from Kittiwake and Alba was slightly ahead
of expectations. Anticipated natural declines were partially
mitigated by better than expected production and water injection
efficiency. The team at Kittiwake delivered production efficiency
of around 80% while also achieving another strong HSE&A
performance, reaching 13 years without a lost-time incident.
2019 performance and outlook
Performance to the end of February has been broadly in line with
the Group's expectations.
The Scolty/Crathes pipeline is expected to be installed during
the third quarter. To facilitate annual maintenance and the
required pipeline installation and commissioning activities, a
shutdown of approximately six weeks has been planned. Once
complete, production levels at Scolty/Crathes are expected to
improve significantly. At Kittiwake, production optimisation
activities and development options for the Eagle discovery continue
to be evaluated. Following an extensive asset integrity campaign
across the Greater Kittiwake Area in 2018, a short shutdown is
planned during the third quarter.
With Alma/Galia expected to cease production early in the next
decade, the focus is on production optimisation and cost control,
with preparatory decommissioning plans now under way. A two-week
scheduled shutdown is planned for the second quarter.
The Kraken development
Daily average net production:
-- 2018: 21,369 Bopd
-- 2017: 4,709 Bopd(1)
Note:
1 Net production since first oil on 23 June, averaged over the
12 months to the end of December 2017
2018 performance summary
Average gross production for 2018 was below expectations.
Throughout 2018, production was limited by a number of FPSO system
and weather-related outages which required additional maintenance
activities to resolve. Following repairs to the water injection
system, injection rates were significantly increased to manage
reservoir voidage, which in turn supported improved reservoir
deliverability. Reservoir performance remains on track with well
testing and reservoir modelling showing excellent communication
between producer and injector wells. Net lease charter payment
credits arising from the non-availability of the Kraken FPSO in
2018 were approximately $45 million, which partially mitigated the
loss of revenue associated with lower production performance.
At DC4, the subsea infrastructure was installed in line with
plans. Drilling commenced in November after the delayed arrival of
the Transocean Leader drilling rig, with first production from the
wells being rephased to the end of the first quarter 2019. As a
result of improved reservoir understanding, the Group gained
approval for developing DC4 with three wells instead of the four
originally planned, saving approximately $23 million with no
material impact on oil production rates or recovery
anticipated.
2019 performance and outlook
FPSO performance has continued to limit production performance
at Kraken. All DC4 wells are now onstream and performing in line
with expectations. As FPSO maintenance activities are completed,
production is expected to significantly improve. We continue to
expect to deliver gross production of between 30,000 and 35,000
Bopd from Kraken.
A three-week maintenance shutdown is scheduled for the third
quarter.
The Group continues to pursue opportunities for production
optimisation through improving facility uptime and reservoir
management activities, including well tests, water injection and
reservoir voidage. Assessment of additional near-field, low-cost
drilling opportunities within the existing producing reservoir and
the Western Flank, which combined contain around 115 MMbbls of
stock tank oil initially in place, is ongoing.
Malaysia operations
Daily average net production:
-- 2018: 8,432 Boepd(1)
-- 2017: 8,938 Boepd(1)
Note
(1) Working interest. 2018 entitlement: 5,631 Boepd; 2017
entitlement: 5,884 Boepd
2018 performance summary
Production in 2018 of 8,432 Boepd was 5.7% lower than in 2017,
primarily reflecting natural decline at Tanjong Baram. Production
efficiency has remained high at PM8/Seligi, with the planned
shutdown activities in September and October successfully concluded
ahead of budget and schedule. During the year, the Group undertook
a significant low-cost idle well intervention programme at
PM8/Seligi. In total, 12 idle wells were returned to service ahead
of schedule and below budget, delivering production improvements
above the Group's plans. Such programmes have been fundamental to
arresting natural declines at the field since EnQuest took on
operatorship. The Group also drilled its first new wells in the
field, with aggregate production broadly in line with the Group's
expectations. Asset integrity activities included underwater
structural inspections for a number of assets, gas compressor
rejuvenation and improving satellite facility monsoon reliability
performance through the upgrade of control and shutdown systems.
The installation of multi-phase flow meters at PM8/Seligi platforms
B, E and Raya-A and remote well monitoring and testing at the
satellite facilities will facilitate improved well optimisation.
The team received an award for the 'Highest Improvement' in
relation to offshore self-regulation, reflecting the Group's focus
on safety and continuous improvement.
At Tanjong Baram, the focus remained on steady, safe and
low-cost operations. Third-party export facility outages limited
production efficiency and uptime throughout the year.
2019 performance and outlook
Aggregate production from PM8/Seligi and Tanjong Baram has been
in line with the Group's expectations for the first two months of
2019, with the Group receiving an award for meeting domestic demand
fluctuations for natural gas.
At PM8/Seligi, a two-well drilling campaign is expected to be
executed in the third quarter of 2019, with first production from
both wells around the end of the quarter. Further subsurface
studies will be completed to enable the Group to continue to
develop and optimise its future drilling opportunities to further
increase recovery from the significant hydrocarbons in place,
targeting an increase in production over time.
Further idle well intervention activities are planned throughout
the year, with the Group planning to return to service around ten
wells in order to mitigate natural decline in the reservoir.
2019 will also benefit from asset rejuvenation activity,
including idle piping isolation, pipework maintenance, glycol
dehydration unit rejuvenation and a compressor turbine control
panel upgrade. A minimal shutdown is planned this year and is
aligned with the third-party operated oil export pipeline and
terminal maintenance activities to minimise downtime.
Longer term, EnQuest will extend field life through further
investment in idle well restoration, facility improvements and
upgrades and technical studies supporting development drilling and
secondary recovery projects to increase ultimate recovery.
At Tanjong Baram, the focus is on maintaining safe operations,
with production expected to continue to decline.
Financial review
Financial overview
All figures quoted are in US Dollars and relate to Business
performance unless otherwise stated.
The Group made significant progress in 2018, meeting our
targets, maintaining financial discipline and making substantial
repayments of our bank debt. Significant time and attention were
devoted to completing the acquisition of assets from BP and
executing the financing agreement for a 15% share of Kraken, which
have strengthened the balance sheet and enhanced liquidity.
Production on a working interest basis increased by 48.2% to
55,447 Boepd, compared to 37,405 Boepd in 2017. The full year's
contribution from Magnus, including the post-acquisition impact of
an additional 75% equity interest in December, increased volumes at
Kraken and the strong performance at Heather were partially offset
by anticipated lower production at Alma/Galia and Scolty/Crathes,
along with natural declines across the portfolio.
Revenue for 2018 was $1,201.0 million, 89.1% higher than in 2017
($635.2 million) reflecting the material increase in volumes and
higher realised prices. The Group's commodity hedge programme
resulted in realised losses of $93.0 million in 2018 (2017: losses
of $20.6 million) as a result of the timing at which the hedges
were entered into and the increase in market prices during the
first half of 2018 in particular.
The Group's operating expenditures of $465.9 million were 33.4%
higher than in 2017 ($349.3 million) reflecting the full year
contribution of the Kraken and Magnus assets. Unit operating costs
decreased by 10.2% to $23.0/Boe (2017: $25.6/Boe) as a result of
increased production.
EBITDA for 2018 was $716.3 million, up 135.9% compared to 2017
($303.6 million), primarily as a result of increased revenue.
2018 2017
$ million $ million
--------------------------- ----------- -----------
Profit from operations
before tax and finance
income/(costs) 290.0 47.3
--------------------------- ----------- -----------
Depletion and depreciation 442.4 227.6
--------------------------- ----------- -----------
Inventory revaluation 5.8 -
--------------------------- ----------- -----------
Net foreign exchange
(gain)/loss (21.9) 23.9
--------------------------- ----------- -----------
Realised (gain)/loss
on FX derivatives related
to capital expenditure1 - 4.8
--------------------------- ----------- -----------
EBITDA 716.3 303.6
--------------------------- ----------- -----------
Note:
1 Realised (gain)/loss on FX derivatives is recorded within cost
of sales. Where the derivative hedges capital expenditure, the
(gain)/loss is added back when calculating EBITDA in order to
reflect the underlying result of operating activities.
EnQuest's net debt decreased by $216.9 million to $1,774.5
million at 31 December 2018 (31 December 2017: $1,991.4 million).
This includes $132.0 million of interest that has been capitalised
to the principal of the facilities pursuant to the terms of the
Group's November 2016 refinancing ('Payable in Kind' or 'PIK') (31
December 2017: $90.5 million) (see note 19 for further details).
Excluding PIK capitalised in 2018, net debt reduced by $258.4
million.
Net debt/(cash)
------------------------
31 December 31 December
2018 2017
$ million $ million
---------------------------- ----------- -----------
Bonds(1) 965.1 944.9
---------------------------- ----------- -----------
Multi-currency revolving
credit facility(2) ('RCF') 799.4 1,100.0
---------------------------- ----------- -----------
Oz Management facility 178.5 -
---------------------------- ----------- -----------
Tanjong Baram Project
Finance Facility 31.7 8.5
---------------------------- ----------- -----------
Mercuria Prepayment
Facility 22.2 75.5
---------------------------- ----------- -----------
SVT Working Capital
Facility 15.7 25.6
---------------------------- ----------- -----------
Other loans 2.5 10.0
---------------------------- ----------- -----------
Cash and cash equivalents (240.6) (173.1)
---------------------------- ----------- -----------
Net debt 1,774.5 1,991.4
---------------------------- ----------- -----------
Notes:
1 Stated excluding accrued interest and accounting adjustment on
adoption of IFRS 9 Financial Instruments of $33.4 million, and
excluding the net-off of unamortised fees. Includes $117.5 million
of PIK (2017: $85.7 million)
2 Stated excluding accrued interest and excluding the net-off of
unamortised fees. Includes $14.4 million of PIK (2017: $4.8
million)
During the year, the Group's improved cash generation and the
Kraken financing agreement facilitated cancellation and repayment
of $340.0 million of the RCF, more than the scheduled amortisation
requirement. In March 2019, EnQuest repaid an additional $55.0
million early with further scheduled amortisation reductions under
the facility due in April 2019 ($50.0 million) and October 2019
($100.0 million).
As at 31 December 2018, total cash and available facilities
totalled $309.0 million, including ring-fenced accounts associated
with Magnus, the Oz Management facility and other joint venture
accounts totalling $107.3 million (2017: $270.9 million including
ring-fenced accounts associated with Magnus and other joint venture
accounts totalling $71.9 million). Undrawn available facilities
amounted to $68.4 million at the end of 2018 (2017: $97.8
million).
UK corporate tax losses at the end of the year remained broadly
in line with 2017 at $3,225.3 million (2017: $3,121.3 million). The
Group generated taxable profits as production from Kraken increased
and completed the acquisition of 75% of the Magnus field and
associated infrastructure. Both utilised existing tax losses, which
were largely offset by additional Ring Fence Expenditure Supplement
('RFES') generated in the period.
In the current environment, no significant corporation tax or
supplementary corporation tax is expected to be paid on UK
operational activities for the foreseeable future. During 2018,
cash tax has been paid on the profits generated from Magnus and
associated infrastructure assets prior to the completion of the
acquisition of the additional interests. As part of this
transaction, the assets were transferred to EnQuest Heather Ltd
from EnQuest NNS Ltd, which allows profits generated by these
assets to be offset against tax losses. Post-transfer, no taxes are
expected to be payable in respect of these assets for the
foreseeable future. The Group also paid cash corporate income tax
on the Malaysian assets which will continue throughout the life of
the Production Sharing Contract.
Income statement
Production and revenue
Production on a working interest basis increased by 48.2% to
55,447 Boepd, compared to 37,405 Boepd in 2017. The full year's
contribution from Magnus, including the post-acquisition impact of
an additional 75% equity interest in December, increased volumes at
Kraken and the strong performance at Heather were partially offset
by anticipated lower production at Alma/Galia and Scolty/Crathes,
along with natural declines across the portfolio.
On average, market prices for crude oil in 2018 were higher than
in 2017. The Group's blended average realised oil price excluding
the impact of hedging was $66.2/bbl, 22.8% higher than in 2017
($53.9/bbl). Revenue is predominantly derived from crude oil sales
which totalled $1,237.6 million, 94.3% higher than in 2017 ($637.0
million), reflecting the material increase in volumes and higher
realised prices. Revenue from the sale of condensate and gas was
$43.1 million (2017: $2.8 million) as a result of sales of gas from
Magnus, which includes the combination of produced gas sales and
the onward sale of third-party gas purchases not required for
injection activities, for which the costs are included in other
cost of sales. Tariffs and other income generated $13.4 million
(2017: $16.0 million). The Group's commodity hedges and other oil
derivatives generated $93.0 million of realised losses (2017: $20.6
million), including losses of $17.2 million of non-cash
amortisation of option premiums (2017: losses of $10.4 million) as
a result of the timing at which the hedges were entered into and
the increase in market prices during the first half of 2018 in
particular. The Group's blended average realised oil price
including the impact of hedging was $61.2/bbl in 2018, 17.2% higher
than 2017 ($52.2/bbl).
Cost of sales
2018 2017
$ million $ million
----------------------------- ----------- -----------
Production costs 396.9 287.1
----------------------------- ----------- -----------
Tariff and transportation
expenses 68.4 62.2
----------------------------- ----------- -----------
Realised (gain)/loss
on FX derivatives related
to operating costs 0.6 -
----------------------------- ----------- -----------
Operating costs 465.9 349.3
----------------------------- ----------- -----------
Realised (gain)/loss
on FX derivatives related
to capital expenditure - 4.8
----------------------------- ----------- -----------
(Credit)/charge relating
to the Group's lifting
position and inventory (25.1) (20.4)
----------------------------- ----------- -----------
Depletion of oil and
gas assets 437.1 223.1
----------------------------- ----------- -----------
Other cost of sales 48.1 12.7
----------------------------- ----------- -----------
Cost of sales 926.0 569.5
----------------------------- ----------- -----------
Operating cost per barrel(1) $/Boe $/Boe
----------------------------- ----------- -----------
- Production costs 19.6 21.0
----------------------------- ----------- -----------
- Tariff and transportation
expenses 3.4 4.6
----------------------------- ----------- -----------
23.0 25.6
----------------------------- ----------- -----------
Note:
1 Calculated on a working interest basis.
Cost of sales were $926.0 million for the year ended 31 December
2018, 62.6% higher than in 2017 ($569.5 million). Operating costs
increased by $116.6 million, reflecting the full year contribution
of Kraken and Magnus partly offset by the benefit of a weaker
Sterling exchange rate. The Group's average unit operating cost
decreased by 10.2% to $23.0/Boe as a result of increased
production.
Depletion expense of $437.1 million was 95.9% higher than in
2017 ($223.1 million), mainly reflecting the contribution from
Kraken and Magnus in 2018. Other cost of sales of $48.1 million
were higher than in 2017 ($12.7 million), principally reflecting
the cost of additional Magnus related third-party gas purchases not
required for injection activities.
General and administrative expenses
General and administrative expenses were $4.0 million (2017:
$0.8 million), reflecting the Group's personnel and property
costs.
Other income and expenses
Net other income of $19.1 million (2017: net other expenses of
$17.6 million) primarily comprises net foreign exchange gains,
which relate to the revaluation of Sterling-denominated amounts in
the balance sheet following the weakening of Sterling against the
Dollar. The prior year expense comprised net foreign exchange
losses, offset by one-off general and administration recovery
impacts.
Finance costs
Finance costs of $236.1 million were 58.5% higher than in 2017
($149.0 million). The increase was primarily driven by a $40.8
million reduction in capitalised interest as a result of the Kraken
project coming onstream in 2017 (2018: $1.5 million; 2017: $42.3
million), an additional $24.5 million in finance lease interest
(2018: $55.8 million; 2017: $31.3 million), $19.7 million
additional bond and loan interest charges (2018: $157.7 million;
2017: $137.9 million) and an additional $0.5 million relating to
the unwinding of discount on provisions and liabilities, largely in
respect of decommissioning (2018: $14.0 million; 2017: $13.5
million). Other finance costs included $8.5 million amortisation of
arrangement fees for financing facilities and bonds (2017: $2.8
million) and other financial expenses of $1.7 million (2017: $5.9
million), primarily the cost for surety bonds principally to
provide security for decommissioning liabilities.
Finance income
Finance income of $3.4 million (2017: $2.2 million) includes
$1.8 million of bank interest receivable (2017: $0.4 million) and
$1.5 million from the unwind of the discount on financial assets
(2017: $1.8 million).
Taxation
The tax credit for 2018 of $20.9 million (2017: $66.0 million
tax credit), excluding exceptional items, is mainly due to the RFES
on UK activities.
Earnings per share
The Group's Business performance basic profit per share was 6.4
cents (2017: loss per share of 2.5 cents, restated for bonus
element of rights issue) and Business performance diluted profit
per share was 6.2 cents (2017: loss per share of 2.5 cents,
restated for bonus element of rights issue).
Remeasurement and exceptional items
Revenue included unrealised gains of $97.4 million in respect of
the mark to market movement on the Group's commodity contracts
(2017: unrealised loss of $7.7 million).
Non-cash impairment charge on the Group's oil and gas assets
arising from changes in assumptions combined with change in
production profiles in the North Sea totalled $126.0 million (2017:
$172.0 million).
Other income and expense included a $1.3 million loss on fair
value in relation to the revaluation of the option to purchase the
remaining 75% of Magnus and other interests and the fair value
uplift of the initial acquisition assets on the accounting step
acquisition of $74.3 million. It also includes the reversal of a
contingent provision of $5.3 million.
A tax credit of $12.4 million (2017: credit of $117.0 million)
has been presented as exceptional, representing the tax impact of
the above items.
Earnings per share
The Group's reported basic profit per share was 10.4 cents
(2017: loss per share of 4.6 cents, restated for bonus element of
rights issue) and reported diluted profit per share was 10.1 cents
(2017: loss per share of 4.6 cents, restated for bonus element of
rights issue).
Cash flow and liquidity
Net debt at 31 December 2018 amounted to $1,774.5 million,
including PIK of $132.0 million, compared with net debt of $1,991.4
million at 31 December 2017, including PIK of $90.5 million. The
Group has remained in compliance with financial covenants under its
debt facilities throughout the year. The movement in net debt was
as follows:
$ million
--------------------------------- ---------
Net debt 1 January 2018 (1,991.4)
--------------------------------- ---------
Operating cash flows 794.4
--------------------------------- ---------
Cash capital expenditure (220.2)
--------------------------------- ---------
Finance lease payments (144.8)
--------------------------------- ---------
Net cash proceeds from rights
issue 128.9
--------------------------------- ---------
Magnus acquisition consideration (100.0)
--------------------------------- ---------
Vendor loan repayments on
Magnus financing (48.6)
--------------------------------- ---------
Net interest and finance costs
paid (155.3)
--------------------------------- ---------
Non-cash capitalisation of
interest (45.0)
--------------------------------- ---------
Other movements, primarily
net foreign exchange
on cash and debt 7.5
--------------------------------- ---------
Net debt 31 December 2018(1) (1,774.5)
--------------------------------- ---------
Note:
1 Stated including $117.5 million of bond PIK (2017: $85.7
million) and $14.4 million of facility PIK (2017: $4.8 million).
Capitalised interest on Oz Management facility of $3.5 million
(2017: $nil)
The Group's reported operating cash flows for the year ended 31
December 2018 were $794.4 million, up 163.2% compared to 2017
($301.8 million). The main drivers for this increase were the
material increase in volumes and higher realised prices, partly
offset by commodity price hedges.
Cash outflow on capital expenditure is set out in the table
below:
Year ended Year ended
31 December 31 December
2018 2017
$ million $ million
--------------------------- ------------ ------------
North Sea 200.2 355.3
--------------------------- ------------ ------------
Malaysia 19.5 3.1
--------------------------- ------------ ------------
Exploration and evaluation 0.5 9.2
--------------------------- ------------ ------------
220.2 367.6
--------------------------- ------------ ------------
Cash capital expenditure primarily relates to Kraken activities
and well drilling on Heather/Broom and PM8/Seligi.
Balance sheet
The Group's total asset value has increased by $623.4 million to
$5,661.9 million at 31 December 2018 (2017: $5,038.5 million),
mainly attributable to the acquisition of the remaining 75% of
Magnus and associated assets. Net current liabilities have
decreased to $301.2 million as at 31 December 2018 (2017: $377.9
million).
Property, plant and equipment ('PP&E')
PP&E has increased by $501.3 million to $4,349.9 million at
31 December 2018 from $3,848.6 million at 31 December 2017 (see
note 10). This increase is explained by the capital additions to
PP&E of $181.5 million, additions of $745.4 million for the
acquisition of the remaining 75% interest in Magnus and additional
interests in associated assets, additions of $123.9 million on the
uplift of the original 25% acquisition, a net increase of $19.0
million for changes in estimates for decommissioning and other
provisions, including the KUFPEC cost recovery provision, offset by
depletion and depreciation charges of $442.4 million and non-cash
impairments of $126.0 million.
The PP&E capital additions during the period, including
capitalised interest, are set out in the table below:
2018
$ million
------------------- -----------
Kraken 70.3
------------------- -----------
Northern North Sea 53.8
------------------- -----------
Central North Sea 41.6
------------------- -----------
Malaysia 15.8
------------------- -----------
181.5
------------------- -----------
Intangible oil and gas assets
Intangible oil and gas assets marginally decreased to $51.8
million at 31 December 2018 (31 December 2017: $52.1 million).
Trade and other receivables
Trade and other receivables have increased by $48.0 million to
$275.8 million at 31 December 2018 compared with $227.8 million at
31 December 2017 (see note 15).
Cash and net debt(1)
The Group had $240.6 million of cash and cash equivalents at 31
December 2018 and $1,774.5 million of net debt, including PIK and
capitalised interest of $135.5 million (2017: $173.1 million of
cash and cash equivalents and $1,991.4 million of net debt,
including PIK of $90.5 million). Net debt1 comprises the following
liabilities:
-- $218.9 million principal outstanding on the GBP155 million
retail bond, including interest capitalised as an amount PIK of
$21.5 million in the year (2017: $224.1 million and $14.9 million,
respectively);
-- $746.1 million principal outstanding on the high yield bond,
including PIK of $96.1 million in the year (2017: $720.8 million
and $70.8 million, respectively);
-- $799.4 million carrying value of credit facility, comprising
amounts drawn down of $785.0 million and PIK interest of $14.4
million (2017: $1,100.0 million comprising amounts drawn down of
$1,095.2 million and PIK interest of $4.8 million);
-- $178.5 million carrying value of Oz Management facility,
comprising amounts drawn down of $175.0 million and capitalised
interest of $3.5 million (2017: $nil);
-- $15.7 million relating to the SVT Working Capital Facility (2017: $25.6 million);
-- $22.2 million relating to the Mercuria Prepayment Facility (2017: $75.5 million);
-- $2.5 million outstanding from a trade creditor loan (2017: $10.0 million); and
-- $31.7 million principal outstanding on the Tanjong Baram
Project Finance Facility (2017: $8.5 million).
Note:
1 Net debt excludes accrued interest, accounting adjustment on
adoption of IFRS 9 Financial Instruments and the net-off of
unamortised fees (see note 19).
Provisions
The Group's decommissioning provision increased by $32.4 million
to $671.7 million at 31 December 2018 (2017: $639.3 million). The
movement is explained by an increase of $29.9 million due to
changes in estimates (including the impact of oil prices and
foreign exchange rates) and $12.6 million unwinding of discount,
partially offset by reductions of $10.0 million for decommissioning
carried out in the period.
Other provisions increased by $605.4 million in 2018 to $715.4
million (2017: $110.0 million). Key movements during the period
primarily related to the remaining acquisition of 75% of Magnus and
additional interests in SVT and associated infrastructure assets
from BP. An addition of $625.3 million reflects the discounted
amounts expected to be due under the terms of the Magnus vendor
loan and long-term profit sharing agreement associated with the 75%
interest. In 2018, EnQuest repaid $48.6 million of the outstanding
vendor loan associated with the initial 25% interest, and
recognised a change in estimate of $12.8 million on the outstanding
contingent consideration (see note 29). Other provisions also
includes EnQuest's obligation to make payments to BP by reference
to 7.5% of BP's decommissioning costs of the Thistle and Deveron
fields. $5.3 million of the movement relates to the utilisation of
PM8/Seligi cost recovery.
Income tax
The Group had a UK corporation tax or supplementary corporation
tax liability at 31 December 2018 of $12.2 million (2017: $nil),
primarily reflecting tax payable on Magnus and associated
infrastructure assets prior to the completion of the acquisition of
additional interests and the transfer of these assets to EnQuest
Heather Limited. Following transfer of the assets, no further tax
is expected to be payable for the foreseeable future. The remainder
of the income tax liability of $3.7 million related to corporate
income tax on Malaysian assets (see note 7).
Deferred tax
The Group's net deferred tax asset has decreased from $335.6
million at 31 December 2017 to a net deferred tax asset of $258.9
million at 31 December 2018. The decrease is mainly due to the
deferred tax liability generated as part of the business
combination accounting for the Magnus acquisition during the
period.
Total UK tax losses carried forward at the year end amount to
$3,225.3 million (2017: $3,121.3 million) (see note 7).
Trade and other payables
Trade and other payables of $502.0 million at 31 December 2018
are $55.9 million higher than at 31 December 2017 ($446.1 million).
$483.8 million are payable within one year (2017: $367.3 million)
and $18.2 million are payable after more than one year (2017: $78.8
million). The increase in current payables mainly reflects VAT
payments due at year end combined with other working capital
movements (see note 23).
Obligations under finance leases
As at 31 December 2018, the Group held a finance lease liability
of $709.0 million associated with the Kraken FPSO of which $93.2
million is classified as a current liability.
Other financial liabilities
As at the end of 2018, the Group had no other financial
liabilities (2017: $68.3 million). The decrease primarily relates
to the cash payment associated with waiver fees due to credit
facility lenders and mark to market movements on the Group's
commodity derivatives following the weakening of the oil price in
late 2018.
Financial risk management
Oil price
The Group is exposed to the impact of changes in both Brent
crude oil prices and gas prices on its revenue and profits.
EnQuest's policy is to manage the impact of commodity prices to
protect against volatility and allow availability of cash flow for
repayment of debt and investment in capital programmes.
During the year ended 31 December 2018, commodity derivatives
generated a total gain of $4.4 million, with revenue and other
operating income including a realised loss of $93.0 million. The
losses were mostly in respect of the settlement of swaps and calls,
and the amortisation of premiums on calls.
Foreign exchange
EnQuest's functional currency is US Dollars. Foreign currency
risk arises on purchases and the translation of assets and
liabilities denominated in currencies other than US Dollars. To
mitigate the risks of large fluctuations in the currency markets,
the hedging policy agreed by the Board allows for up to 70% of the
non-US Dollar portion of the Group's annual capital budget and
operating expenditure to be hedged. For specific contracted capital
expenditure projects, up to 100% can be hedged.
EnQuest continually reviews its currency exposures and, when
appropriate, looks at opportunities to enter into foreign exchange
hedging contracts. During the year ended 31 December 2018, losses
totalling $0.4 million (2017: gain of $0.4 million) were recognised
in the income statement. This included losses totalling $0.6
million realised on contracts maturing during the year (2017:
$nil).
Surplus cash balances are deposited as cash collateral against
in-place letters of credit as a way of reducing interest costs.
Otherwise, cash balances can be invested in short-term bank
deposits and AAA-rated liquidity funds, subject to Board-approved
limits and with a view to minimising counterparty credit risks.
Going concern
The Group closely monitors and manages its funding position and
liquidity risk throughout the year, including monitoring forecast
covenant results, to ensure that it has access to sufficient funds
to meet forecast cash requirements. Cash forecasts are regularly
produced and sensitivities considered for, but not limited to,
changes in crude oil prices (adjusted for hedging undertaken by the
Group), production rates and project timing and costs. These
forecasts and sensitivity analyses allow management to mitigate
liquidity or covenant compliance risks in a timely manner.
Management has also continued to take action to implement
cost-saving programmes to reduce planned operational expenditure,
general and administrative spend and capital expenditure in 2018
and 2019. At 31 December 2018, the Group had total cash and
available facilities of $309.0 million, including ring-fenced
accounts associated with Magnus, the Oz Management facility and
other joint venture accounts totalling $107.3 million.
The Group's business plan ('Base case'), which underpins this
going concern assessment, assumes Kraken production rates are in
line with the Group's production guidance. The Base case has been
updated for the forward curve and uses an oil price assumption of
c.$61.9/bbl throughout 2019 and c.$60.7/bbl for first quarter 2020.
This has been further stress tested under a plausible downside case
('Downside case') as described in the viability statement. Both
cases reflect the bank debt amortisation profile due in the going
concern period. The Directors consider the Base case and Downside
case to be an appropriate basis on which to make their
assessment.
The Base case and Downside case indicate that the Company is
covenant compliant and able to operate within the headroom of its
existing borrowing facilities for 12 months from the date of
approval of the Annual Report and Accounts.
Should circumstances arise that differ from the Group's
projections, the Directors believe that a number of mitigating
actions, including asset sales or other funding options, can be
executed successfully in the necessary timeframe to meet debt
repayment obligations as they become due and in order to maintain
liquidity.
After making enquiries and assessing the progress against the
forecast, projections and the status of the mitigating actions
referred to above, the Directors have a reasonable expectation that
the Group can continue in operation and meet its commitments as
they fall due over the going concern period. Accordingly, the
Directors continue to adopt the going concern basis in preparing
the financial statements.
Viability statement
The Directors have assessed the viability of the Group over a
three-year period to March 2022. This assessment has taken into
account the Group's financial position as at March 2019, the future
projections and the Group's principal risks and uncertainties. The
Directors' approach to risk management, their assessment of the
Group's principal risks and uncertainties, and the actions
management are taking to mitigate these risks are outlined on pages
20 to 28. The period of three years is deemed appropriate as it is
the time horizon across which management constructs a detailed plan
against which business performance is measured and also covers the
period within which the Group's term loan and revolving credit
facility is expected to be repaid. Based on the Group's
projections, the Directors have a reasonable expectation that the
Group can continue in operation and meet its liabilities as they
fall due over the period to March 2022.
The Group's business plan process has underpinned this
assessment and has been used as the Base case. The business plan
process takes account of the Group's principal risks and
uncertainties, and has further been stress tested to understand the
impact on the Group's liquidity and financial position of
reasonably possible changes in these risks and/or assumptions.
The forecasts which underpin this assessment use the same oil
price assumption as for the going concern assessment, with a
longer-term price assumption for the viability period being aligned
to the current forward curve.
For the current assessment, the Directors also draw attention to
the specific principal risks and uncertainties (and mitigants)
identified below, which, individually or collectively, could have a
material impact on the Group's viability during the period of
review. In forming this view, it is recognised that such future
assessments are subject to a level of uncertainty that increases
with time and, therefore, future outcomes cannot be guaranteed or
predicted with certainty. The impact of these risks and
uncertainties, including their combined impact, has been reviewed
by the Directors and the effectiveness and achievability of the
potential mitigating actions have been considered.
-- Oil price volatility
A decline in oil and gas prices would adversely affect the
Group's operations and financial condition. To mitigate oil price
volatility, the Directors have hedged approximately 6.5 MMbbls of
collar options at an average floor price of around $66/bbl in the
first half of 2019. In accordance with the Oz Management facility
agreement, the Group has a further approximately 1.5 MMbbls hedged
across 2019 with an average floor price of around $56/bbl. The
Directors, in line with Group policy, will continue to pursue
hedging at the appropriate time and price.
-- Kraken production
All production and injector wells on Drilling Centres ('DC')
DC1, DC2, DC3 and DC4 are onstream. Both production processing
trains are also online and production and injection wells are
operating in line with expectations in aggregate. On the basis of
this performance, and subject to delivering on the Group's plans to
further optimise production and improve plant uptime, EnQuest
expects to deliver planned production rates.
-- Access to funding
The Group's credit facility contains certain covenants (based on
the ratio of indebtedness incurred under the term loan and
revolving credit facility to EBITDA, finance charges to EBITDA, and
a requirement for liquidity testing). Prolonged low oil prices,
cost increases and production delays or outages could further
threaten the Group's liquidity and/or ability to comply with
relevant covenants.
The Directors recognise the importance of ensuring medium-term
liquidity and in particular to protect against potential future
declines in the oil price. EnQuest has a committed $785 million
Tranche A Term Loan and a further Tranche B $75 million revolving
credit facility (collectively the 'Facility'). Across the Facility,
$68 million remains available at 31 December 2018.
In addition, the maturity dates of the existing $746 million
High Yield Bond and the GBP172 million Retail Notes (both figures
inclusive of the PIK notes) is April 2022, with an option
exercisable by the Group (at its absolute discretion) to extend the
maturity date to October 2023 if the existing Facility is not fully
repaid or refinanced by October 2020.
A further condition to the payment of interest on both the High
Yield Bond and Retail Notes in cash is based on, amongst other
things, the average prevailing oil price (dated Brent Futures
benchmark as published by Platts) for the six-month period
immediately preceding the day which is one month prior to the
relevant interest payment date being at least $65 per barrel;
otherwise interest payable is to be capitalised.
In conducting the viability review, these risks have been taken
into account in the stress testing performed on the Base case
described above.
Specifically the Base case has been subjected to stress testing
by considering the impact of the following plausible downside
risks:
-- a 10.0% discount to the oil price forward curve;
-- a 3.5% decrease in 2019 production and a 5.0% decrease from 2020 onwards;
-- a 2.5% increase in operating costs except for fixed costs related to the Kraken FPSO; and
-- a 2.5% increase in capital expenditure from 2020 onwards.
A scenario has been run illustrating the impact of the above
risks on the Base case. This plausible Downside case indicates that
mitigating actions, including asset sales or other funding options,
would need to be undertaken for the Group to be viable for in some
parts of the three-year period.
Notwithstanding the principal risks and uncertainties described
above, after making enquiries and assessing the progress against
the forecast, projections and the status of the mitigating actions
referred to above, the Directors have a reasonable expectation that
the Group can continue in operation and meet its commitments as
they fall due over the viability period ending March 2022.
Accordingly, the Directors therefore support this viability
statement.
Risks and uncertainties
Management of risks and uncertainties
Consistent with the Company's purpose (as set out on the inside
of the front cover of this report), the Board has articulated
EnQuest's strategic vision to be the operator of choice for
maturing and underdeveloped hydrocarbon assets. EnQuest is focused
on delivering on its targets, driving future growth and managing
its capital structure and liquidity.
EnQuest seeks to balance its risk position between investing in
activities that can achieve its near-term targets and drive future
growth with the appropriate returns, including any appropriate
market opportunities that may present themselves, and the
continuing need to remain financially disciplined. This combination
drives cost efficiency and cash flow generation, facilitating a
reduction in the Group's debt. In this regard, the Board has
developed certain strategic tenets to guide the Company which link
with its strategy and appetite for risk. Broadly, these reflect a
focus by the Company on:
-- Maintaining discipline across metrics such as financial
headroom, leverage ratio and gearing;
-- Enhancing diversity within our portfolio of assets, with a
focus on underdeveloped producing assets and maturing assets with
investment potential; and
-- Ensuring the quality of the investment decision-making process.
In pursuit of its strategy, EnQuest has to manage a variety of
risks. Accordingly, the Board has established a Risk Management
Framework to enhance effective risk management within the following
Board-approved overarching statement of risk appetite:
-- We make investments and manage the asset portfolio against
agreed key performance indicators consistent with the strategic
objectives of enhancing net cash flow, reducing leverage, managing
costs and diversifying our asset base;
-- We seek to embed a risk culture within our organisation
corresponding to the risk appetite which is articulated for each of
our principal risks;
-- We seek to avoid reputational risk by ensuring that our
operational and HSE&A processes, policies and practices reduce
the potential for error and harm to the greatest extent practicable
by means of a variety of controls to prevent or mitigate
occurrence; and
-- We set clear tolerances for all material operational risks to
minimise overall operational losses, with zero tolerance for
criminal conduct.
The Board reviews the Company's risk appetite annually in light
of changing market conditions and the Company's performance and
strategic focus. The Executive Committee periodically reviews and
updates the Group Risk Register based on the individual risk
registers of the business. The Group Risk Register, along with an
assurance mapping and controls review exercise and a risk report
(focused on identifying and mitigating the most critical and
emerging risks through a systematic analysis of the Company's
business, its industry and the global risk environment), is
periodically reviewed by the Board (with senior management), to
ensure that key issues are being adequately identified and actively
managed. In addition, the Group's Risk Committee (a sub-Committee
of the Board) provides a forum for the Board to review selected
individual risk areas in greater depth.
As part of its strategic, business planning and risk processes,
the Group considers how a number of macro-economic themes may
influence its principal risks. These are factors which influence
long-term supply and demand trends and/or about which the Company
should be cognisant in developing its strategy. They include, for
example, developments in technology, demographics, climate change
and how markets and the regulatory environment may respond, and the
decommissioning of infrastructure in the UK North Sea and other
mature basins. These themes are relevant to the Group's assessments
across a number of its principal risks. The Group will continue to
monitor these themes and the relevant developing policy environment
at an international and national level and will adapt its strategy
accordingly. For example, EnQuest remains conscious of the
potential for a number of aspects of climate change to amplify
certain principal risks over time (e.g. in relation to access to
capital markets - see 'Financial' risk on page 24 - and oil price -
see 'Oil and gas prices' risk on page 26). The Group is also
conscious that as an operator of mature producing assets with
limited appetite for exploration, it has limited exposure to
investments which do not deliver near-term returns and is therefore
in a position to adapt and calibrate its exposure to new
investments according to developments in relevant markets.
As part of its evolution of the Group's Risk Management
Framework, the Risk Committee has refreshed its views on all risk
areas faced by the Group (categorising these into a 'Risk Library'
of 18 overarching risks). For each risk area, the Committee
reviewed 'Risk Bowties' that identified risk causes and impacts and
mapped these to preventative and containment controls used to
manage the risks to acceptable levels.
The Board, supported by the Audit and Risk Committees, has
reviewed the Group's system of risk management and internal control
for the period from 1 January 2018 to the date of this report and
carried out a robust assessment of the Company's emerging and
principal risks, the procedures in place to identify and mitigate
principal and emerging risks and confirms that the Group complies
in this respect with the Financial Reporting Council's 'Guidance on
Risk Management, Internal Control and Related Financial and
Business Reporting'.
Key business risks
The Group's principal risks (identified from the 'Risk Library')
are those which could prevent the business from executing its
strategy and creating value for shareholders or lead to a
significant loss of reputation. The Board has carried out a robust
assessment of the principal risks facing the Company, including
those that would threaten its business model, future performance,
solvency or liquidity.
Cognisant of the Group's purpose and strategy, the Board is
satisfied that the Group's risk management system works effectively
in assessing and managing the Group's risk appetite and has
supported a robust assessment by the Directors of the principal
risks facing the Group.
Set out on the following pages are:
-- The principal risks and mitigations;
-- An estimate of the potential impact and likelihood of
occurrence after the mitigation actions, along with how these have
changed in the past year; and
-- An articulation of the Group's risk appetite for each of these principal risks.
Amongst these, the key risks the Group currently faces are a
sustained decline in oil prices (see 'Oil and gas prices' risk on
page 26), a lack of growth opportunities (see 'Production' risk on
page 22 and 'Subsurface risk and reserves replacement' on page 23)
and materially lower than expected production performance for a
prolonged period, particularly at the Kraken field (see
'Production' risk on page 22).
risk appetite
---------------------------- ------------------------------- ----------------------------
Health, safety & environment The Group's principal The Group's desire is
('HSE') aim is Safe Results to maintain upper quartile
Oil and gas development, with no harm to people HSE performance measured
production and exploration and respect for the against suitable industry
activities are complex environment. Should metrics.
and HSE risks cover operational results
many areas including and safety ever come
Major Accident Hazards, into conflict, employees
personal health and have a responsibility
safety, compliance with to choose safety over
regulatory requirements, operational results.
asset integrity issues Employees are empowered
and potential environmental to stop operations for
harm, including those safety-related reasons.
associated with the
impacts of climate change.
Potential impact - Medium
(2017 Medium)
Likelihood - Low (2017
Low)
There has been no material
change in the potential
impact or likelihood
and the Group's overall
record on HSE remains
robust.
---------------------------- ------------------------------- ----------------------------
mitigation
---------------------------- ------------------------------- ----------------------------
The Group maintains, EnQuest's HSE Policy
in conjunction with is now fully integrated
its core contractors, across our operated
a comprehensive programme sites and this has enabled
of HSE, asset integrity an increased focus on
and assurance activities Health, Safety and the
and has implemented Environment.
a continual improvement There is a strong assurance
programme, promoting programme
a culture of transparency in place to ensure
in relation to HSE matters. EnQuest complies with
HSE performance is discussed its Policy and Principles
at each Board meeting and regulatory commitments.
and the mitigation of
HSE risk has been enhanced
through further emphasising
the role of HSE oversight
within the Risk Committee's
terms of reference.
During 2018, the Group
continued to focus on
control of Major Accident
Hazards and 'Safe Behaviours'.
In addition, the Group
has a positive and transparent
relationship with the
UK Health and Safety
Executive and Department
for Business, Energy
& Industrial Strategy,
and the Malaysian regulator,
Malaysia Petroleum Management.
---------------------------- ------------------------------- ----------------------------
risk appetite
----------------------------- -------------------------------- -------------------------------
Production Since production efficiency production assets in
The Group's production and meeting production its portfolio, EnQuest
is critical to its success targets are core to has a very low tolerance
and is subject to a our business and the for operational risks
variety of risks, including: Group seeks to maintain to its production (or
subsurface uncertainties; a high degree of operational the support systems
operating in a mature control over that underpin production).
field environment; potential
for significant unexpected
shutdowns; and unplanned
expenditure (particularly
where remediation may
be dependent on suitable
weather
conditions offshore).
Lower than expected
reservoir performance
or insufficient addition
of new resources may
have a material impact
on the Group's future
growth.
Climate change could
result in more severe
weather conditions over
time, which could impact
asset uptime.
The Group's delivery
infrastructure in the
UK North Sea is, to
a significant extent,
dependent on the Sullom
Voe Terminal.
Longer-term production
is threatened if low
oil prices bring forward
decommissioning timelines.
Potential impact - High
(2017 High)
Likelihood - Low (2017
Low)
There has been no material
change in the potential
impact or likelihood.
The Group has delivered
on its 2018 production
target despite a lower
performance at Kraken
than originally expected.
With the additional
interest in the Magnus
asset, EnQuest's production
portfolio has been further
diversified, with material
growth expected as a
result in 2019. However,
the increased interest
in Magnus also increased
the Group's reliance
on the Sullom Voe Terminal.
Further, the Dunlin
bypass export project,
once completed, will
see volumes from Thistle
and the Dons exported
via the Magnus facility
and Ninian Pipeline
System and will therefore
further increase reliance
on the Sullom Voe Terminal.
----------------------------- -------------------------------- -------------------------------
mitigation
----------------------------- -------------------------------- -------------------------------
The Group's programme Life of asset production
of asset integrity and profiles are audited
assurance activities by independent reserves
provide leading indicators auditors. The Group
of significant potential also undertakes regular
issues which may result internal reviews. The
in unplanned shutdowns Group's forecasts of
or which may in other production are risked
respects have the potential to reflect appropriate
to undermine asset availability production uncertainties.
and uptime. The Group
continually assesses The Sullom Voe Terminal
the condition of its has a good safety record
assets and operates and its safety and operational
extensive maintenance performance levels are
and inspection programmes regularly monitored
designed to minimise and challenged by the
the risk of unplanned Group and other terminal
shutdowns and expenditure. owners and users to
The Group monitors both ensure that operational
leading and lagging integrity is maintained.
KPIs in relation to Further, EnQuest expects
its maintenance activities to be well positioned
and liaises closely to manage potential
with its downstream operational risks related
operators to minimise to the Sullom Voe Terminal
pipeline and terminal having assumed operatorship
production impacts. of the terminal and
with the workforce having
Production efficiency transferred with the
is continually monitored asset in 2017. Nevertheless,
with losses being identified the Group actively continues
and remedial and improvement to explore the potential
opportunities undertaken of alternative transport
as required. A continual, options and developing
rigorous cost focus hubs that may provide
is also maintained. both risk mitigation
and cost savings.
The Group also continues
to consider new opportunities
for expanding production.
----------------------------- -------------------------------- -------------------------------
risk appetite
----------------------------- -------------------------------- ----------------------------
Project execution and The efficient delivery While the Group necessarily
delivery of new project developments assumes significant
The Group's success has been a key feature risk when it sanctions
will be partially dependent of the Group's long-term a new development (for
upon the successful strategy. The Group's example, by incurring
execution and delivery current appetite is costs against oil price
of development projects. for short-cycle development assumptions), it requires
projects such as infill that risks to the efficient
Potential impact - Medium drilling and near-field implementation of the
(2017 High) tie-backs. project are minimised.
Likelihood - Low (2017
Low)
The potential impact
has reduced, with the
likelihood remaining
unchanged. As the Group
focuses on reducing
its debt, its current
appetite is to pursue
short-cycle development
projects. The main project
developments in 2019
are oil export pipeline
projects for Thistle/Deveron
(the Dunlin bypass project)
and Scolty/Crathes (the
pipeline replacement
project).
----------------------------- -------------------------------- ----------------------------
mitigation
----------------------------- -------------------------------- ----------------------------
The Group has project
teams which are responsible
for the planning and
execution of new projects
with a dedicated team
for each development.
The Group has detailed
controls, systems and
monitoring processes
in place to ensure that
deadlines are met, costs
are controlled and that
design concepts and
the Field Development
Plan are adhered to
and implemented. These
are modified when circumstances
require and only through
a controlled management
of change process and
with the necessary internal
and external authorisation
and communication. The
Group also engages third-party
assurance experts to
review, challenge and,
where appropriate, make
recommendations to improve
the processes for project
management, cost control
and governance of major
projects. EnQuest ensures
that responsibility
for delivering time-critical
supplier obligations
and lead times are fully
understood, acknowledged
and proactively managed
by the most senior levels
within supplier organisations.
EnQuest also supports
its partners and suppliers
through the provision
of appropriate secondees
if required.
----------------------------- -------------------------------- ----------------------------
risk appetite
------------------------------- --------------------------------- -------------------------
Subsurface risk and Reserves replacement the assumption of risk
reserves replacement is an element of the in relation to the key
Failure to develop its sustainability of the activities required
contingent and prospective Group and its ability to deliver reserves
resources or secure to grow. The Group has growth, such as drilling
new licences and/or some tolerance for and acquisitions.
asset acquisitions and
realise their expected
value.
Potential impact - High
(2017 High)
Likelihood - Medium
(2017 Medium)
There has been no material
change in the potential
impact or likelihood
as oil price volatility,
a focus on strengthening
the balance sheet and
increased competition
to acquire assets continues
to limit business development
activity to the pursuit
of reserves enhancing,
selective, cash--accretive
opportunities.
Low oil prices can potentially
affect development of
contingent and prospective
resources and/or reserves
certifications.
------------------------------- --------------------------------- -------------------------
mitigation
------------------------------- --------------------------------- -------------------------
The Group puts a strong The Group continues
emphasis on subsurface to consider potential
analysis and employs opportunities to acquire
industry--leading professionals. new production resources
The Group continues that meet its investment
to recruit in a variety criteria.
of technical positions
which enables it to
manage existing assets
and evaluate the acquisition
of new assets and licences.
All analysis is subject
to internal and, where
appropriate, external
review and relevant
stage gate processes.
All reserves are currently
externally reviewed
by a Competent Person.
In addition, EnQuest
has active business
development teams, both
in the UK and internationally,
developing a range of
opportunities and liaising
with vendors/government.
------------------------------- --------------------------------- -------------------------
risk appetite
----------------------------- -------------------------- -----------------------------
Financial The Group recognises costs and complying
Inability to fund financial that significant leverage with its obligations
commitments or maintain has been required to to finance providers
adequate cash flow and fund its growth as low while delivering shareholder
liquidity and/or reduce oil prices have impacted value, recognising that
costs. revenues. However, it reasonable assumptions
is intent on reducing relating to external
The Group's term loan its leverage levels, risks need to be made
and revolving credit maintaining liquidity, in transacting with
facility contains certain enhancing profit margins, finance providers.
financial covenants reducing
(based on the ratio
of indebtedness incurred
under the term loan
and revolving facility
to EBITDA, finance charges
to EBITDA and a requirement
for liquidity testing).
Prolonged low oil prices,
cost increases, including
those related to an
environmental incident,
and production delays
or outages could threaten
the Group's liquidity
and/or ability to comply
with relevant covenants.
Potential impact - High
(2017 High)
Likelihood - Medium
(2017 Medium)
There has been no material
change in the potential
impact or likelihood;
however, there is potential
for the cost of capital
to increase as factors
such as climate change
concerns and oil price
volatility may reduce
investors' acceptable
levels of oil and gas
sector exposure and
the cost of emissions
trading certificates,
or their replacement
in the event the UK
exits the European Union,
may trend higher. In
addition, adhering to
the term loan amortisation
schedule remains partially
dependent on the successful
increase in the Group's
aggregate production
being materially in
line with expectations
and no significant reduction
in oil prices. Further
information is contained
in the going concern
and viability paragraphs
on pages 18 to 20 of
the Financial Review.
----------------------------- -------------------------- -----------------------------
mitigation
----------------------------- -------------------------- -----------------------------
Debt reduction is a Funding from the bonds
strategic priority. and revolving credit
During the year, the facility is supplemented
Group completed a $175 by operating cash inflow
million credit facility from the Group's producing
from Oz Management and assets. The Group reviews
raised c.$129 million its cash flow requirements
(net) through a rights on an ongoing basis
issue, of which $100 to ensure it has adequate
million was used to resources for its needs.
fund the Group's cash
consideration for the The Group is continuing
acquisition of additional to enhance its financial
interests in assets position through maintaining
from BP. The Group also a focus on controlling
paid and/or cancelled and reducing costs through
a total of $340 million supplier renegotiations,
of the term facility. assessing counterparty
credit risk, hedging
These steps, together and trading, cost-cutting
with other mitigating and rationalisation.
actions available to Where costs are incurred
management, are expected by external service
to provide the Group providers, the Group
with sufficient liquidity actively challenges
to strengthen its balance operating costs. The
sheet for longer--term Group also maintains
growth. a framework of internal
controls.
Ongoing compliance with
the financial covenants
under the Group's term
loan and revolving credit
facility is actively
monitored and reviewed.
----------------------------- -------------------------- -----------------------------
risk appetite
---------------------------- ------------------------------- --------------------------------
Human resources As a low-cost, lean The Group recognises
The Group's success organisation, the Group that the benefits of
continues to be dependent relies on motivated a lean and flexible
upon its ability to and high-quality employees organisation require
attract and retain key to achieve its targets agility to assure against
personnel and develop and manage its risks. the risk of skills shortages.
organisational capability
to deliver strategic
growth. Industrial action
across the sector could
also impact the operations
of the Group.
Potential impact - Medium
(2017 Low)
Likelihood - High (2017
Medium)
The impact and likelihood
have increased given
the increased competition
in the sector, particularly
in the UK.
---------------------------- ------------------------------- --------------------------------
mitigation
---------------------------- ------------------------------- --------------------------------
The Group has established The Group also maintains
an able and competent market--competitive
employee base to execute contracts with key suppliers
its principal activities. to support the execution
In addition to this, of work where the necessary
the Group seeks to maintain skills do not exist
good relationships with within the Group's employee
its employees and contractor base.
companies and regularly
monitors the employment The Group recognises
market to provide remuneration that there is a gender
packages, bonus plans pay gap within the organisation
and long-term share-based but that there is no
incentive plans that issue with equal pay
incentivise performance for the same tasks.
and long-term commitment EnQuest aims to attract
from employees to the the best talent, recognising
Group. the value of diversity.
We recognise that our Executive and senior
people are critical management retention,
to our success and so succession planning
are continually evolving and development remain
our end-to-end people important priorities
management processes, for the Board. It is
including recruitment a Board-level priority
and selection, career that executive and senior
development and performance management possess the
management. This ensures appropriate mix of skills
that we have the right and experience
person for the job and to realise the Group's
that we provide appropriate strategy; succession
training, support and planning therefore remains
development opportunities a key priority.
with feedback to drive
continuous improvement EnQuest is introducing
whilst delivering Safe a Group Employee Forum
Results. The culture during 2019 to add to
of the Group is an area our employee communication
of ongoing focus and and engagement strategy.
a 'Values refresh' took This forum will improve
place during 2018. engagement and interaction
between the workforce
and the Board.
---------------------------- ------------------------------- --------------------------------
risk appetite
------------------------------ ------------------------------ ---------------------------------
Reputation The Group has no tolerance
The reputational and for conduct which may
commercial exposures compromise its reputation
to a major offshore for integrity and competence.
incident, including
those related to an
environmental incident,
or non-compliance with
applicable law and regulation
are significant.
Potential impact - High
(2017 High)
Likelihood - Low (2017
Low)
There has been no material
change in the potential
impact or likelihood.
------------------------------ ------------------------------ ---------------------------------
mitigation
------------------------------ ------------------------------ ---------------------------------
All activities are conducted The Group undertakes
in accordance with approved regular audit activities
policies, standards to provide assurance
and procedures. Interface on compliance with established
agreements are agreed policies, standards
with all core contractors. and procedures.
The Group requires adherence All EnQuest personnel
to its Code of Conduct and contractors are
and runs compliance required to pass an
programmes to provide annual anti-bribery,
assurance on conformity corruption and anti-facilitation
with relevant legal of tax evasion course.
and ethical requirements.
All personnel are authorised
to shut down production
for safety-related reasons.
------------------------------ ------------------------------ ---------------------------------
risk appetite
------------------------------- ------------------------------- ------------------------------
Oil and gas prices The Group recognises
A material decline in that considerable exposure
oil and gas prices adversely to this risk is inherent
affects the Group's to its business.
operations and financial
condition.
Potential impact - High
(2017 High)
Likelihood - Medium
(2017 Medium)
There has been no material
change in
the potential impact
or likelihood.
The Group recognises
that climate change
concerns and related
regulatory developments
are likely to reduce
demand for hydrocarbons
over time. This may
be mitigated by correlated
constraints on the development
of new supply.
------------------------------- ------------------------------- ------------------------------
mitigation
------------------------------- ------------------------------- ------------------------------
This risk is being mitigated In order to develop
by a number of measures its resources, the Group
including hedging oil needs to be able to
price, renegotiating fund the required investment.
supplier contracts, The Group will therefore
reducing costs and commitments regularly review and
and institutionalising implement suitable policies
a lower cost base. to hedge against the
possible negative impact
The Group monitors oil of changes in oil prices
price sensitivity relative while remaining within
to its capital commitments the limits set by its
and has a policy (see term loan and revolving
page 74) which allows credit facility.
hedging of its production.
As at 19 March 2019, The Group has established
the Group had hedged an in-house trading
approximately 8 MMbbls. and marketing function
This ensures that the to enable it to enhance
Group will receive a its ability to mitigate
minimum oil price for the exposure to volatility
its production. in oil prices.
Further, as described
previously, the Group's
focus on production
efficiency supports
mitigation of a low
oil price environment.
------------------------------- ------------------------------- ------------------------------
risk appetite
--------------------------------- --------------------------------- ---------------------------
Fiscal risk and government The Group faces an uncertain Due to the nature of
take macro--economic and such risks and their
Unanticipated changes regulatory environment. relative unpredictability,
in the regulatory or it must be tolerant
fiscal environment can of certain inherent
affect the Group's ability exposure.
to deliver its strategy/business
plan and potentially
impact revenue and future
developments.
Potential impact - High
(2017 High)
Likelihood - Medium
(2017 Medium)
There has been no material
change in the potential
impact or likelihood,
although the anticipated
exit of the United Kingdom
from the European Union
may impact the regulatory
environment going forward,
for example by affecting
the cost of emissions
trading certificates.
--------------------------------- --------------------------------- ---------------------------
mitigation
--------------------------------- --------------------------------- ---------------------------
It is difficult for All business development
the Group to predict or investment activities
the timing or severity recognise potential
of such changes. However, tax implications and
through Oil & Gas UK the Group maintains
and other industry associations, relevant internal tax
the Group engages with expertise.
government and other
appropriate organisations At an operational level,
in order to keep abreast the Group has procedures
of expected and potential to identify impending
changes; the Group also changes in relevant
takes an active role regulations to ensure
in making appropriate legislative compliance.
representations.
--------------------------------- --------------------------------- ---------------------------
risk appetite
--------------------------- ---------------------------- ----------------------------
Joint venture partners The Group requires partners creditworthiness of
Failure by joint venture of high integrity. It partners and evaluates
parties to fund their recognises that it must this aspect carefully
obligations. accept a degree of exposure as part of every investment
to the decision.
Dependence on other
parties where the Group
is not the operator.
Potential impact - Medium
(2017 Medium)
Likelihood - Medium
(2017 Medium)
There has been no material
change in the potential
impact or likelihood.
--------------------------- ---------------------------- ----------------------------
mitigation
--------------------------- ---------------------------- ----------------------------
The Group operates regular The Group generally
cash call and billing prefers to be the operator.
arrangements with its The Group maintains
co-venturers to mitigate regular dialogue with
the Group's credit exposure its partners to ensure
at any one point in alignment of interests
time and keeps in regular and to maximise the
dialogue with each of value of joint venture
these parties to ensure assets.
payment. Risk of default
is mitigated by joint
operating agreements
allowing the Group to
take over any defaulting
party's share in an
operated asset and rigorous
and continual assessment
of the financial situation
of partners.
--------------------------- ---------------------------- ----------------------------
risk appetite
----------------------------- ----------------------------- -------------------------
Competition The Group operates in sector.
The Group operates in a mature industry with
a competitive environment well-established competitors
across many areas, including and aims to be the leading
the acquisition of oil operator in the
and gas assets, the
marketing of oil and
gas, the procurement
of oil and gas services
and access to human
resources.
Potential impact - High
(2017 Medium)
Likelihood - High (2017
Medium)
The potential impact
and likelihood has increased
due to an increase in
the number of available
oil and gas assets and
competitors looking
to acquire them.
----------------------------- ----------------------------- -------------------------
mitigation
----------------------------- ----------------------------- -------------------------
The Group has strong The Group maintains
technical and business good relations with
development capabilities oil and gas service
to ensure that it is providers and constantly
well positioned to identify keeps the market under
and execute potential review.
acquisition opportunities.
----------------------------- ----------------------------- -------------------------
risk appetite
--------------------------------- ------------------------------ ------------------------------
Portfolio concentration Although the extent concentrated in the
The Group's assets are of portfolio concentration UK North Sea and therefore
primarily concentrated is moderated by production this risk remains intrinsic
in the UK North Sea generated internationally, to the Group.
around a limited number the majority of the
of infrastructure hubs Group's assets remain
and existing production relatively
(principally oil) is
from mature fields.
This amplifies exposure
to key infrastructure
(including ageing pipelines
and terminals), political/fiscal
changes and oil price
movements.
Potential impact - High
(2017 High)
Likelihood - High (2017
Medium)
The acquisition of an
additional interest
in the Magnus oil field
has elevated this risk
in the long term (by
further concentrating
the Group's portfolio
in the UK North Sea).
Further, the Dunlin
bypass export project,
once completed, will
see volumes from Thistle
and the Dons exported
via the Magnus facility
and Ninian Pipeline
System to the Sullom
Voe Terminal.
The Group is currently
focused on oil production
and does not have significant
exposure to gas or other
sources of income.
--------------------------------- ------------------------------ ------------------------------
mitigation
--------------------------------- ------------------------------ ------------------------------
This risk is mitigated Production at the Greater
in part through acquisitions. Kittiwake Area, Alma/Galia
For all acquisitions, and Kraken reduced the
the Group uses a number Group's prior concentration
of business development to the Brent Pipeline
resources to evaluate System ('BPS') and the
and transact acquisitions Sullom Voe Terminal.
in a commercially sensitive However, the acquisition
manner. This includes of an additional interest
performing extensive in the Magnus field
due diligence (using in December 2018 resulted
in-house and external in further concentration
personnel) and actively in Sullom Voe Terminal,
involving executive with concentration increasing
management in reviewing again following completion
commercial, technical of the Dunlin bypass
and other business risks export project in 2019.
together with mitigation Although the Group has
measures. concentration risk at
Sullom Voe Terminal,
The Group also constantly taking operatorship
keeps its portfolio of the terminal has
under rigorous review put the Group in a position
and, accordingly, actively of more direct control
considers the potential of such risk.
for making disposals
and divesting, executing
development projects,
making international
acquisitions, expanding
hubs and potentially
investing in gas assets
or export capability
where such opportunities
are consistent with
the Group's focus on
enhancing net revenues,
generating cash flow
and strengthening the
balance sheet.
--------------------------------- ------------------------------ ------------------------------
risk appetite
------------------------------ -------------------------------- -----------------------------
International Business In light of its long-term However, such tolerance
While the majority of growth strategy, the does not impair the
the Group's activities Group seeks to expand Group's commitment to
and assets are in the and diversify its production comply with legislative
UK, the international (geographically and and regulatory requirements
business is still material. in terms of quantum); in the jurisdictions
The Group's international as such, it is tolerant in which it operates.
business is subject of assuming certain Opportunities should
to the same risks as commercial risks which enhance net revenues
the UK business (e.g. may accompany the opportunities and facilitate strengthening
HSE&A, production and it pursues. of the balance sheet.
project execution);
however, there are additional
risks that the Group
faces, including security
of staff and assets,
political, foreign exchange
and currency control,
taxation, legal and
regulatory, cultural
and language barriers
and corruption.
Potential impact - Medium
(2017 Medium)
Likelihood - Medium
(2017 Medium)
There has been no material
change in the impact
or likelihood.
------------------------------ -------------------------------- -----------------------------
mitigation
------------------------------ -------------------------------- -----------------------------
Prior to entering a Where appropriate, the
new country, EnQuest risks may be mitigated
evaluates the host country by entering into a joint
to assess whether there venture with partners
is an adequate and established with local knowledge
legal and political and experience.
framework in place to
protect and safeguard After country entry,
first its expatriate EnQuest maintains a
and local staff and, dialogue with local
second, any investment and regional government,
within the country in particularly with those
question. responsible for oil,
energy and fiscal matters,
When evaluating international and may obtain support
business risks, executive from appropriate risk
management reviews commercial, consultancies. When
technical and other there is a significant
business risks together change in the risk to
with mitigation and people or assets within
how risks can be managed a country, the Group
by the business on an takes appropriate action
ongoing basis. to safeguard people
and assets.
EnQuest looks to employ
suitably qualified host
country staff and work
with good-quality local
advisers to ensure it
complies with national
legislation, business
practices and cultural
norms while at all times
ensuring that staff,
contractors and advisers
comply with EnQuest's
business principles,
including those on financial
control, cost management,
fraud and corruption.
------------------------------ -------------------------------- -----------------------------
risk appetite
--------------------------------- ---------------------------- ------------------------------
IT security and resilience The Group endeavours data, impact operations
The Group is exposed to provide a secure or destabilise its financial
to risks arising from IT environment that systems; it has a very
interruption to, or is able to resist and low appetite for this
failure of, IT infrastructure. withstand any attacks risk.
The risks of disruption or unintentional disruption
to normal operations that may compromise
range from loss in functionality sensitive
of generic systems (such
as email and internet
access) to the compromising
of more sophisticated
systems that support
the Group's operational
activities. These risks
could result from malicious
interventions such as
cyber-attacks.
Potential impact - Medium
(2017 Medium)
Likelihood - Low (2017
Low)
--------------------------------- ---------------------------- ------------------------------
mitigation
--------------------------------- ---------------------------- ------------------------------
The Group has established The Risk Committee undertook
IT capabilities and additional analyses
endeavours to be in of cyber-security risks
a position to defend in 2018. Recognising
its systems against that it is one of the
disruption or attack. Group's key focus areas,
the Group now employs
a cyber-security manager.
Work on assessing the
cyber-security environment
and implementing improvements
as necessary will continue
during 2019.
--------------------------------- ---------------------------- ------------------------------
Stefan Ricketts
Company Secretary
The Strategic Report was approved by the Board and signed on its
behalf by the Company Secretary on 20 March 2019.
KEY PERFORMANCE INDICATORS
2018 2017 2016
UK North Sea Lost Time Incident Frequency
('LTIF')(1) 0.61 0.70 0.82
Malaysia LTIF(1) 0.00 0.00 0.00
------------------------------------------------ -------- -------- --------
Group LTIF(1) 0.43 0.46 0.51
------------------------------------------------ -------- -------- --------
Production (Boepd) 55,447 37,405 39,751
------------------------------------------------ -------- -------- --------
Net 2P reserves (MMboe) 245 210 215
------------------------------------------------ -------- -------- --------
Business performance data:
Revenue and other operating income(2) ($
million) 1,201.0 627.5 849.6
Realised blended average oil price per
barrel(2) ($) 61.2 52.2 63.8
Opex per barrel (production and transportation
costs) ($) 23.0 25.6 24.6
EBITDA(3) ($ million) 716.3 303.6 477.1
Cash capex(4) on property, plant and equipment
oil and gas assets ($ million) 220.2 367.6 609.2
------------------------------------------------ -------- -------- --------
Reported data:
Cash generated from operations ($ million) 788.6 327.0 408.3
Net debt including PIK ($ million) 1,774.5 1,991.4 1,796.5
------------------------------------------------ -------- -------- --------
(1) Lost time incident frequency represents the number of
incidents per million exposure hours worked (based on 12 hours for
offshore and 8 hours for onshore)
(2) Including realised loss of $93.0 million in 2018 associated
with EnQuest's oil price hedges (2017: realised loss of $20.6
million; 2016: realised gain of $255.8 million)
(3) EBITDA is calculated on a Business performance basis, and is
calculated by taking profit/loss from operations before tax and
finance income/(costs) and adding back depletion, depreciation,
foreign exchange movements, inventory revaluation and the realised
gains/loss on foreign currency derivatives related to capital
expenditure
(4) Net of proceeds from disposal of $nil million (2017: $nil
million; 2016: $1.5 million)
OIL AND GAS RESERVES AND RESOURCES
At 31 December 2018
UKCS Other Regions Total
--------------- ---------------- ------
MMboe MMboe MMboe MMboe MMboe
Proven and probable reserves
(notes 1,2,3,6 and 8)
At 31 December 2017 190 21 210
Revisions of previous estimates (3) 1 (2)
Discoveries, extensions and
additions - - -
Acquisitions and disposals
(note 7) 55 - 55
Production
Export Meter (17) (3)
Volume Adjustments (note
5) 0 1
Production during period: (17) (2) (19)
Total at 31 December 2018 225 20 245
Contingent resources (notes
1,2 and 4)
At 31 December 2017 98 67 164
Revisions of previous estimates 4 1 5
Discoveries, extensions and
additions - - -
Acquisitions and disposals
(note 7) 36 - 36
Promoted to reserves (6) - (6)
Total at 31 December 2018 131 68 198
Notes:
1 Reserves are quoted on a net entitlement basis, resources
are quoted on a working interest basis
2 Proven and probable reserves and contingent resources have
been assessed by the Group's internal reservoir engineers,
utilising geological, geophysical, engineering and financial
data
3 The Group's proven and probable reserve profiles has been
audited by a recognised Competent Person in accordance with
the definitions set out under the 2018 Petroleum Resources
Management System and supporting guidelines issued by the
Society of Petroleum Engineers
4 Contingent resources relate to technically recoverable hydrocarbons
for which commerciality has not yet been determined and are
stated on a best technical case or '2C' basis
5 Correction of export to sales volumes
6 All UKCS volumes are presented pre-SVT value adjustment
7 Proven and probable reserves: Acquisition of additional 75%
equity in Magnus. Contingent resources: Acquisition of additional
75% equity in Magnus largely offset by relinquishment of the
Group's equity interests in the Kildrummy and Torphins licences
8 The above proven and probable reserves include 6 MMboe that
will be consumed as lease fuel on the Kraken FPSO and fuel
gas on Heather, Broom, West Don, Don SW, Conrie and Ythan
9 The above table excludes Tanjong Baram in Malaysia
Group Statement of Comprehensive Income
For the year ended 31 December 2018
2018 2017
------------------------- ----- ----------------------------------------- -----------------------------------------
Remeasurements Remeasurements
and exceptional and exceptional
Business items (note Reported Business items (note Reported
performance 4) in year performance 4) in year
Notes $'000 $'000 $'000 $'000 $'000 $'000
------------------------- ----- ------------ ---------------- --------- ------------ ---------------- ---------
Revenue and other
operating
income 5(a) 1,201,005 97,432 1,298,437 635,167 (7,716) 627,451
------------------------- ----- ------------ ---------------- --------- ------------ ---------------- ---------
Cost of sales 5(b) (926,020) 1,718 (924,302) (569,506) 5,481 (564,025)
------------------------- ----- ------------ ---------------- --------- ------------ ---------------- ---------
Gross profit/(loss) 274,985 99,150 374,135 65,661 (2,235) 63,426
------------------------- ----- ------------ ---------------- --------- ------------ ---------------- ---------
Net impairment
(charge)/reversal
to oil and gas assets 4 - (126,046) (126,046) - (171,971) (171,971)
------------------------- ----- ------------ ---------------- --------- ------------ ---------------- ---------
General and
administration
expenses 5(c) (4,018) - (4,018) (848) - (848)
------------------------- ----- ------------ ---------------- --------- ------------ ---------------- ---------
Other income 5(d) 22,428 78,316 100,744 6,807 50,613 57,420
------------------------- ----- ------------ ---------------- --------- ------------ ---------------- ---------
Other expenses 5(e) (3,362) (14,715) (18,077) (24,363) (20,358) (44,721)
------------------------- ----- ------------ ---------------- --------- ------------ ---------------- ---------
Profit/(loss) from
operations
before tax and finance
income/(costs) 290,033 36,705 326,738 47,257 (143,951) (96,694)
------------------------- ----- ------------ ---------------- --------- ------------ ---------------- ---------
Finance costs 6 (236,114) (28) (236,142) (149,020) (272) (149,292)
------------------------- ----- ------------ ---------------- --------- ------------ ---------------- ---------
Finance income 6 3,389 - 3,389 2,213 - 2,213
------------------------- ----- ------------ ---------------- --------- ------------ ---------------- ---------
Profit/(loss) before
tax 57,308 36,677 93,985 (99,550) (144,223) (243,773)
------------------------- ----- ------------ ---------------- --------- ------------ ---------------- ---------
Income tax 7 20,887 12,406 33,293 65,996 116,947 182,943
------------------------- ----- ------------ ---------------- --------- ------------ ---------------- ---------
Profit/(loss) for the
year attributable to
owners of the parent 78,195 49,083 127,278 (33,554) (27,276) (60,830)
------------------------- ----- ------------ ---------------- --------- ------------ ---------------- ---------
Other comprehensive income
------------------------------- ----- ------- -------- --------
Items that may be reclassified
to profit or loss:
------------------------------- ----- ------- -------- --------
Transfers to income statement
of cash flow hedges (36) (5)
------------------------------- ----- ------- -------- --------
Other comprehensive income
for the year, net of tax (36) (5)
------------------------------- ----- ------- -------- --------
Total comprehensive income
for the year, attributable
to owners of the parent 127,242 (60,835)
------------------------------- ----- ------- -------- --------
Earnings per share 8 $ $ $ $
------------------------------- ----- ------- -------- --------
Basic 0.064 0.104 (0.025)* (0.046)*
------------------------------- ----- ------- -------- --------
Diluted 0.062 0.101 (0.025)* (0.046)*
------------------------------- ----- ------- -------- --------
* Restated following rights issue
The attached notes 1 to 29 form part of these Group financial
statements.
Group Balance Sheet
At 31 December 2018
2018 2017
Notes $'000 $'000
--------------------------------- ----- ----------------------- ----------
ASSETS
--------------------------------- ----- ----------------------- ----------
Non-current assets
--------------------------------- ----- ----------------------- ----------
Property, plant and equipment 10 4,349,913 3,848,622
--------------------------------- ----- ----------------------- ----------
Goodwill 11 283,950 189,317
--------------------------------- ----- ----------------------- ----------
Intangible oil and gas assets 12 51,803 52,103
--------------------------------- ----- ----------------------- ----------
Investments 13 31 152
--------------------------------- ----- ----------------------- ----------
Deferred tax assets 7 286,721 398,263
--------------------------------- ----- ----------------------- ----------
Other financial assets 20 5,958 8,191
--------------------------------- ----- ----------------------- ----------
4,978,376 4,496,648
--------------------------------- ----- ----------------------- ----------
Current assets
--------------------------------- ----- ----------------------- ----------
Inventories 14 100,532 78,045
--------------------------------- ----- ----------------------- ----------
Trade and other receivables 15 275,809 227,754
--------------------------------- ----- ----------------------- ----------
Current tax receivable 20 1,159
--------------------------------- ----- ----------------------- ----------
Cash and cash equivalents 16 240,604 173,128
--------------------------------- ----- ----------------------- ----------
Other financial assets 20 66,575 61,737
--------------------------------- ----- ----------------------- ----------
683,540 541,823
--------------------------------- ----- ----------------------- ----------
TOTAL ASSETS 5,661,916 5,038,471
--------------------------------- ----- ----------------------- ----------
EQUITY AND LIABILITIES
--------------------------------- ----- ----------------------- ----------
Equity
--------------------------------- ----- ----------------------- ----------
Share capital and premium 17 345,331 210,402
--------------------------------- ----- ----------------------- ----------
Merger reserve 662,855 662,855
--------------------------------- ----- ----------------------- ----------
Cash flow hedge reserve - 36
--------------------------------- ----- ----------------------- ----------
Share-based payment reserve (6,884) (5,516)
--------------------------------- ----- ----------------------- ----------
Retained earnings (17,750) (106,911)
--------------------------------- ----- ----------------------- ----------
TOTAL EQUITY 983,552 760,866
--------------------------------- ----- ----------------------- ----------
Non-current liabilities
--------------------------------- ----- ----------------------- ----------
Borrowings 19 735,470 888,993
--------------------------------- ----- ----------------------- ----------
Bonds 19 990,282 934,351
--------------------------------- ----- ----------------------- ----------
Obligations under finance leases 24 615,781 679,924
--------------------------------- ----- ----------------------- ----------
Provisions 22 1,306,092 705,999
--------------------------------- ----- ----------------------- ----------
Trade and other payables 23 18,209 78,777
--------------------------------- ----- ----------------------- ----------
Other financial liabilities 20 - 7,121
--------------------------------- ----- ----------------------- ----------
Deferred tax liabilities 7 27,815 62,685
--------------------------------- ----- ----------------------- ----------
3,693,649 3,357,850
--------------------------------- ----- ----------------------- ----------
Current liabilities
--------------------------------- ----- ----------------------- ----------
Borrowings 19 311,261 330,012
--------------------------------- ----- ----------------------- ----------
Obligations under finance leases 24 93,169 118,009
--------------------------------- ----- ----------------------- ----------
Provisions 22 81,050 43,215
--------------------------------- ----- ----------------------- ----------
Trade and other payables 23 483,781 367,312
--------------------------------- ----- ----------------------- ----------
Other financial liabilities 20 142 61,207
--------------------------------- ----- ----------------------- ----------
Current tax payable 15,312 -
--------------------------------- ----- ----------------------- ----------
984,715 919,755
--------------------------------- ----- ----------------------- ----------
TOTAL LIABILITIES 4,678,364 4,277,605
--------------------------------- ----- ----------------------- ----------
TOTAL EQUITY AND LIABILITIES 5,661,916 5,038,471
--------------------------------- ----- ----------------------- ----------
The attached notes 1 to 29 form part of these Group financial
statements.
The financial statements were approved by the Board of Directors
on 20 March 2019 and signed on its behalf by:
Jonathan Swinney
Chief Financial Officer
Group Statement of Changes in Equity
For the year ended 31 December 2018
Share
capital Cash flow Share-based
and share Merger hedge payments Retained
premium reserve reserve reserve earnings Total
$'000 $'000 $'000 $'000 $'000 $'000
---------------------------- ---------- -------- --------- ----------- --------- --------
Balance at 1 January 2017 208,639 662,855 41 (6,602) (46,081) 818,852
---------------------------- ---------- -------- --------- ----------- --------- --------
Profit/(loss) for the year - - - - (60,830) (60,830)
---------------------------- ---------- -------- --------- ----------- --------- --------
Other comprehensive income - - (5) - - (5)
---------------------------- ---------- -------- --------- ----------- --------- --------
Total comprehensive income
for the year - - (5) - (60,830) (60,835)
---------------------------- ---------- -------- --------- ----------- --------- --------
Share-based payment - - - 2,849 - 2,849
---------------------------- ---------- -------- --------- ----------- --------- --------
Shares issued on behalf of
Employee Benefit Trust 1,763 - - (1,763) - -
---------------------------- ---------- -------- --------- ----------- --------- --------
Balance at 31 December 2017
(as previously reported) 210,402 662,855 36 (5,516) (106,911) 760,866
---------------------------- ---------- -------- --------- ----------- --------- --------
Adjustment on adoption of
IFRS 9 (see note 2) (38,117) (38,117)
---------------------------- ---------- -------- --------- ----------- --------- --------
Balance at 1 January 2018 210,402 662,855 36 (5,516) (145,028) 722,749
---------------------------- ---------- -------- --------- ----------- --------- --------
Profit/(loss) for the year - - - - 127,278 127,278
---------------------------- ---------- -------- --------- ----------- --------- --------
Other comprehensive income - - (36) - - (36)
---------------------------- ---------- -------- --------- ----------- --------- --------
Total comprehensive income
for the year - - (36) - 127,278 127,242
---------------------------- ---------- -------- --------- ----------- --------- --------
Issue of share capital 128,916 - - - - 128,916
---------------------------- ---------- -------- --------- ----------- --------- --------
Share-based payment - - - 4,645 - 4,645
---------------------------- ---------- -------- --------- ----------- --------- --------
Shares purchased on behalf
of Employee Benefit Trust 6,013 - - (6,013) - -
---------------------------- ---------- -------- --------- ----------- --------- --------
Balance at 31 December 2018 345,331 662,855 - (6,884) (17,750) 983,552
---------------------------- ---------- -------- --------- ----------- --------- --------
The attached notes 1 to 29 form part of these Group financial
statements.
Group Statement of Cash Flows
For the year ended 31 December 2018
2018 2017
Notes $'000 $'000
----------------------------------------------------- ----- --------- ----------
CASH FLOW FROM OPERATING ACTIVITIES
----------------------------------------------------- ----- --------- ----------
Cash generated from operations 28 788,629 327,034
----------------------------------------------------- ----- --------- ----------
Cash (paid)/received on sale/(purchase) of
financial instruments (16,363) (1,185)
----------------------------------------------------- ----- --------- ----------
Proceeds from exercise of Thistle decommissioning 50,000 -
option
----------------------------------------------------- ----- --------- ----------
Decommissioning spend 22 (10,036) (10,605)
----------------------------------------------------- ----- --------- ----------
Income taxes paid (17,798) (13,463)
----------------------------------------------------- ----- --------- ----------
Net cash flows from/(used) operating activities 794,432 301,781
----------------------------------------------------- ----- --------- ----------
INVESTING ACTIVITIES
----------------------------------------------------- ----- --------- ----------
Purchase of property, plant and equipment (220,213) (358,420)
----------------------------------------------------- ----- --------- ----------
Purchase of intangible oil and gas assets - (9,171)
----------------------------------------------------- ----- --------- ----------
Proceeds from disposal of Ascent loan notes - 3,561
----------------------------------------------------- ----- --------- ----------
Consideration on exercise of Magnus acquisition
option (100,000) -
----------------------------------------------------- ----- --------- ----------
Deferred consideration on initial Magnus acquisition (48,642) -
----------------------------------------------------- ----- --------- ----------
Interest received 1,600 340
----------------------------------------------------- ----- --------- ----------
Net cash flows (used)/from in investing activities (367,255) (363,690)
----------------------------------------------------- ----- --------- ----------
FINANCING ACTIVITIES
----------------------------------------------------- ----- --------- ----------
Proceeds from bank facilities 219,900 162,970
----------------------------------------------------- ----- --------- ----------
Repayment of bank facilities (402,008) (50,969)
----------------------------------------------------- ----- --------- ----------
Gross proceeds from issue of shares 138,926 -
----------------------------------------------------- ----- --------- ----------
Shares purchased by Employee Benefit Trust (6,013) -
----------------------------------------------------- ----- --------- ----------
Share issue and debt restructuring costs paid (3,997) (1,356)
----------------------------------------------------- ----- --------- ----------
Repayment of obligations under finance leases (144,820) -
----------------------------------------------------- ----- --------- ----------
Interest paid (136,482) (46,052)
----------------------------------------------------- ----- --------- ----------
Other finance costs paid (20,425) (6,286)
----------------------------------------------------- ----- --------- ----------
Net cash flows from/(used) financing activities (354,919) 58,307
----------------------------------------------------- ----- --------- ----------
NET (DECREASE)/INCREASE IN CASH AND CASH EQUIVALENTS 72,258 (3,602)
----------------------------------------------------- ----- --------- ----------
Net foreign exchange on cash and cash equivalents (4,726) 5,210
----------------------------------------------------- ----- --------- ----------
Cash and cash equivalents at 1 January 169,668 168,060
----------------------------------------------------- ----- --------- ----------
CASH AND CASH EQUIVALENTS AT 31 DECEMBER 237,200 169,668
----------------------------------------------------- ----- --------- ----------
Reconciliation of cash and cash equivalents
----------------------------------------------------- ----- --------- ----------
Cash and cash equivalents per statement of
cash flows 237,200 169,668
----------------------------------------------------- ----- --------- ----------
Restricted cash 16 3,404 3,460
----------------------------------------------------- ----- --------- ----------
Cash and cash equivalents per balance sheet 240,604 173,128
----------------------------------------------------- ----- --------- ----------
The attached notes 1 to 29 form part of these Group financial
statements.
Notes to the Group Financial Statements
For the year ended 31 December 2018
1. Corporate information
EnQuest PLC ('EnQuest' or the 'Company') is a limited liability
company incorporated and registered in England and is listed on the
London Stock Exchange and on the Stockholm NASDAQ OMX.
The principal activities of the Company and its subsidiaries
(together the 'Group') is to enhance hydrocarbon recovery and
extend the useful lives of mature and underdeveloped assets and
associated infrastructure in a profitable and responsible
manner.
The Group's financial statements for the year ended 31 December
2018 were authorised for issue in accordance with a resolution of
the Board of Directors on 20 March 2019.
A listing of the Group companies is contained in note 27 to
these Group financial statements.
2. Summary of significant accounting policies
Basis of preparation
The Group financial information has been prepared in accordance
with International Financial Reporting Standards ('IFRS') as
adopted by the European Union as they apply to the financial
statements of the Group for the year ended 31 December 2018 and
applied in accordance with the Companies Act 2006. The accounting
policies which follow set out those policies which apply in
preparing the financial statements for the year ended 31 December
2018.
The Group financial information has been prepared on an
historical cost basis, except for the fair value remeasurement of
certain financial instruments, including derivatives, as set out in
the accounting policies below. The presentation currency of the
Group financial information is United States Dollars and all values
in the Group financial information are rounded to the nearest
thousand ($'000) except where otherwise stated.
The financial statements have been prepared on the going concern
basis. Further information relating to the use of the going concern
assumption is provided in the 'Going concern' section of the
Financial Review.
New standards and interpretations
The Group applied IFRS 15 Revenue from Contracts with Customers
and IFRS 9 Financial Instruments from 1 January 2018. The nature
and effect of the changes as a result of adoption of these new
accounting standards are described below. Other new standards are
also effective from 1 January 2018 but they do not have a material
effect on the Group's financial statements. The Group has not early
adopted any standards, interpretations or amendments that have been
issued but are not yet effective.
IFRS 15 Revenue from Contracts with Customers
IFRS 15 establishes a comprehensive framework for determining
whether, how much and when revenue is recognised. It replaces IAS
18 Revenue, IAS 11 Construction Contracts and related
interpretations. The five-step model applies to revenue arising
from contracts with customers and requires revenue to be recognised
at an amount that reflects the consideration to which an entity
expects to be entitled in exchange for transferring goods or
services to a customer. Determining the timing of the transfer of
control, at a point in time or over time, requires judgement.
The Group adopted IFRS 15 using the full retrospective method of
adoption as per the new IFRS 15 accounting policies and the Group
has assessed that there is no impact on the financial
statements.
IFRS 9 Financial Instruments
IFRS 9 Financial Instruments replaces IAS 39 Financial
Instruments: Recognition and Measurement, bringing together the
accounting aspects for financial instruments: classification and
measurement, impairment under the expected credit loss ('ECL')
model and hedge accounting.
When adopting IFRS 9, the Group has applied transition relief
and opted not to restate prior periods. Differences arising from
the adoption of IFRS 9 are recognised in retained earnings. The
total impact on the Group's retained earnings as at 1 January 2018
is $38.1 million. The effect of adopting IFRS 9 is as follows:
Impact on the statement of financial position
(increase/(decrease)):
31 December IFRS 9 1 January
2017 Adjustment 2018
Balance sheet (extract) $'000 $'000 $'000
Non-current liabilities
Bonds 934,351 38,117 972,468
Total 934,351 38,117 972,468
============ ============ ==========
Equity
Retained earnings (106,911) (38,117) (145,028)
Total (106,911) (38,117) (145,028)
============ ============ ==========
The table shows the adjustment recognised for each relevant line
item. Line items that were not affected by the changes have not
been included. The adjustments are recognised in the opening
balance sheet on 1 January 2018.
In October 2017, the IASB confirmed the accounting for
modifications of financial liabilities under IFRS 9. When a
financial liability measured at amortised cost is modified without
this resulting in derecognition, a gain or loss should be
recognised in profit or loss. The gain or loss is calculated as the
difference between the original contractual cash flows and the
modified cash flows discounted at the original effective interest
rate ('EIR'). Any fees and costs incurred are amortised over the
remaining term of the asset.
At the end of 2016 the Group's bonds were refinanced, for which
the modification was not considered to be significant under IAS 39.
As a result, the change in contractual cash flows on the bonds was
amortised over the new life of the bonds, rather than taken
straight to profit or loss. Under IFRS 9, the refinancing is a
modification of the debt in which the difference in contractual
cash flows should be taken straight to profit or loss. The cash
flows were reassessed and, on 1 January 2018 on the adoption of
IFRS 9, an adjustment for $38.1 million was taken through opening
reserves and through the amortised value of the bonds ($15.4
million increase to high yield bonds and a $22.7 million increase
to retail bonds).
Standards issued but not yet effective
Standards issued and relevant to the Group, but not yet
effective up to the date of issuance of the Group's financial
statements, are listed below. This listing is of standards and
interpretations issued, which the Group reasonably expects to be
applicable at a future date. The Group intends to adopt these
standards when they become effective. The Directors do not
anticipate that the adoption of these standards will have a
material impact on the Group's financial statements in the period
of initial application.
IFRS 16 Leases
IFRS 16 Leases, issued in January 2016, sets out the principles
for the recognition, measurement, presentation and disclosure of
leases for both lessors and lessees. It replaces the previous
leases standard IAS 17 Leases and is effective from 1 January 2019.
IFRS 16 requires lessees and lessors to make more extensive
disclosures than under IAS 17.
IFRS 16 introduces a single, on-balance sheet lease accounting
model for lessees. A lessee recognises a right-of-use asset,
representing its right to use the underlying asset, and a lease
liability, representing its obligation to make lease payments.
Lessees will be required to recognise separately the interest
expense on the lease liability and the depreciation expense on the
right-of-use asset. There are recognition exemptions for short-term
leases and leases of low-value items. Lessor accounting remains
similar to the current accounting under IAS 17 i.e. lessors
continue to classify leases as finance or operating leases.
During 2018, the Group has performed an impact assessment for
the application of IFRS 16. This assessment is based on currently
available information and will be subject to changes arising from
further reasonable and supportable information being made available
to the Group in 2019, including the Group's borrowing rate at 1
January 2019 when the Group will adopt IFRS 16. The Group continues
to assess its accounting processes, controls and policies on an
ongoing basis.
The Group will adopt the new standard on the required effective
date using the modified retrospective method. The Group will apply
the practical expedient to grandfather the definition of a lease on
transition. It will therefore apply IFRS 16 to all contracts
entered into before 1 January 2019 and identified as leases in
accordance with IAS 17. Contracts which have not been considered or
identified as a lease will continue to be accounted for in line
with their historical treatment. The Group will also elect to use
the exemptions proposed by the standard on lease contracts for
which the lease terms ends within 12 months as of the date of
initial application and lease contracts for which the underlying
asset is of low value.
The Group has identified leases which will be recognised as
finance leases under IFRS 16. On the implementation of IFRS 16 on 1
January 2019, the Group expects to recognise right-of-use assets
and corresponding lease liabilities of approximately $82 million.
The preliminary estimated impact on the Group's 2019 consolidated
statement of comprehensive income results in a decrease in to net
profit of approximately $2 million; a result of the replacement of
operating lease payments previously accounted under IAS 17 by
increased depreciation and finance charges under IFRS 16. EBITDA is
estimated to increase by approximately $7 million. The estimated
2019 consolidated financial statements impact is computed based on
the information available to date and the actual impact of IFRS 16
on the Group's 2019 consolidated financial statements may differ
from the estimates provided above.
Basis of consolidation
Subsidiaries
Subsidiaries are all entities over which the Group has the sole
right to exercise control over the operations and govern the
financial policies generally accompanying a shareholding of more
than half of the voting rights. The existence and effect of
potential voting rights that are currently exercisable or
convertible are considered when assessing the Group's control.
Subsidiaries are fully consolidated from the date on which control
is transferred to the Group and are de-consolidated from the date
that control ceases.
Intercompany profits, transactions and balances are eliminated
on consolidation. Accounting policies of subsidiaries have been
changed where necessary to ensure consistency with the policies
adopted by the Group.
Joint arrangements
Oil and gas operations are usually conducted by the Group as
co-licensees in unincorporated joint operations with other
companies. Joint control is the contractually agreed sharing of
control of an arrangement, which exists only when decisions about
the relevant activities require the consent of the relevant parties
sharing control.
Most of the Group's activities are conducted through joint
operations, whereby the parties that have joint control of the
arrangement have the rights to the assets, and obligations for the
liabilities, relating to the arrangement. The Group reports its
interests in joint operations using proportionate consolidation -
the Group's share of the production, assets, liabilities, income
and expenses of the joint operation are combined with the
equivalent items in the consolidated financial statements on a
line-by-line basis.
Business combinations
Business combinations are accounted for using the acquisition
method. The cost of an acquisition is measured as the aggregate of
the consideration transferred, measured at acquisition date fair
value, and the amount of any controlling interest in the acquiree.
For each business combination, the acquirer measures the
non-controlling interest in the acquiree either at fair value or at
the proportionate share of the acquiree's identifiable net assets.
Those petroleum reserves and resources that are able to be reliably
valued are recognised in the assessment of fair values on
acquisition. Other potential reserves, resources and rights, for
which fair values cannot be reliably determined, are not
recognised.
Where applicable, the consideration for the acquisition includes
any asset or liability resulting from a contingent consideration
arrangement, measured at its acquisition date fair value.
Subsequent changes in such fair values are adjusted against the
cost of acquisition where they qualify as measurement period
adjustments (see below). All other subsequent changes in the fair
value of contingent consideration classified as a financial
liability are remeasured through profit or loss. If the contingent
consideration is not within the scope of IFRS 9, it is measured at
fair value in accordance with the appropriate IFRS. Contingent
consideration that is classified as equity is not remeasured and
subsequent settlement is accounted for within equity.
If the initial accounting for a business combination is
incomplete by the end of the reporting period in which the
combination occurs, the Group reports provisional amounts for the
items for which the accounting is incomplete. Those provisional
amounts are adjusted during the measurement period (see below), or
additional assets or liabilities are recognised to reflect new
information obtained about facts and circumstances that existed as
of the acquisition date that, if known, would have affected the
amounts recognised as of that date.
The measurement period is the period from the date of
acquisition to the date the Group obtains complete information
about facts and circumstances that existed as of the acquisition
date, and is subject to a maximum of one year.
Goodwill
Goodwill arising on a business combination is initially measured
at cost, being the excess of the cost of the business combination
over the net fair value of the identifiable assets, liabilities and
contingent liabilities of the entity at the date of
acquisition.
If the fair value of the net assets acquired is in excess of the
aggregate consideration transferred, the Group reassesses whether
it has correctly identified all of the assets acquired and all of
the liabilities assumed and reviews the procedures used to measure
the amounts to be recognised at the acquisition date. If the
reassessment still results in an excess of the fair value of net
assets acquired over the aggregate consideration transferred, the
gain is recognised in profit or loss.
Following initial recognition, goodwill is stated at cost less
any accumulated impairment losses. Goodwill is reviewed for
impairment annually or more frequently if events or changes in
circumstances indicate that such carrying value may be
impaired.
For the purposes of impairment testing, goodwill acquired is
allocated to the cash generating units ('CGU') that are expected to
benefit from the synergies of the combination. Each unit or units
to which goodwill is allocated represents the lowest level within
the Group at which the goodwill is monitored for internal
management purposes.
Impairment is determined by assessing the recoverable amount of
the CGU to which the goodwill relates. Where the recoverable amount
of the CGU is less than the carrying amount of the CGU and related
goodwill, an impairment loss is recognised. Impairment losses
relating to goodwill cannot be reversed in future periods.
Critical accounting estimates and judgements
The management of the Group has to make estimates and judgements
when preparing the financial statements of the Group. Uncertainties
in the estimates and judgements could have an impact on the
carrying amount of assets and liabilities and the Group's result.
The most important estimates and judgements in relation thereto
are:
Estimates in oil and gas reserves
The business of the Group is to enhance hydrocarbon recovery and
extend the useful lives of mature and underdeveloped assets and
associated infrastructure in a profitable and responsible manner.
Estimates of oil and gas reserves are used in the calculations for
impairment tests and accounting for depletion and decommissioning.
Changes in estimates of oil and gas reserves resulting in different
future production profiles will affect the discounted cash flows
used in impairment testing, the anticipated date of decommissioning
and the depletion charges in accordance with the unit of production
method.
Estimates in impairment of oil and gas assets, goodwill and the
estimate of the cost recovery provision
Determination of whether oil and gas assets or goodwill have
suffered any impairment requires an estimation of the fair value
less costs to dispose of the CGU to which oil and gas assets and
goodwill have been allocated. The calculation requires the entity
to estimate the future cash flows expected to arise from the CGU
using discounted cash flow models comprising asset-by-asset life of
field projections using Level 3 inputs (based on the IFRS 13 fair
value hierarchy). Key assumptions and estimates in the impairment
models relate to: commodity prices that are based on internal view
of forward curve prices for the first three years and thereafter at
$75/bbl inflated at 2.0% per annum from 2023; discount rates
derived from the Group's post-tax weighted average cost of capital
of 10.0% (2017: 10.0%); commercial reserves and the related cost
profiles. As the production and related cash flows can be estimated
from EnQuest's experience, management believes that the estimated
cash flows expected to be generated over the life of each field is
the appropriate basis upon which to assess goodwill and individual
assets for impairment.
These same models and assumptions are used in the calculation of
the cost recovery provision (see note 22).
Determining the fair value of property, plant and equipment on
business combinations
The Group determines the fair value of property, plant and
equipment acquired in a business combination based on the
discounted cash flows at the time of acquisition from the proven
and probable reserves. In assessing the discounted cash flows, the
estimated future cash flows attributable to the asset are
discounted to their present value using a discount rate that
reflects the market assessments of the time value of money and the
risks specific to the asset at the time of the acquisition. In
calculating the asset fair value, the Group will apply a forward
curve followed by an oil price assumption representing management's
view of the long-term oil price.
Decommissioning provision
Amounts used in recording a provision for decommissioning are
estimates based on current legal and constructive requirements and
current technology and price levels for the removal of facilities
and plugging and abandoning of wells. Due to changes in relation to
these items, the future actual cash outflows in relation to
decommissioning are likely to differ in practice. To reflect the
effects due to changes in legislation, requirements, technology and
price levels, the carrying amounts of decommissioning provisions
are reviewed on a regular basis.
The effects of changes in estimates do not give rise to prior
year adjustments and are dealt with prospectively. While the Group
uses its best estimates and judgement, actual results could differ
from these estimates.
In estimating decommissioning provisions, the Group applies an
annual inflation rate of 2.0% (2017: 2.0%) and an annual discount
rate of 2.0% (2017: 2.0%).
Going concern
The Directors' assessment of going concern concludes that the
use of the going concern basis is appropriate and that the
Directors have a reasonable expectation that the Group will be able
to continue in operation and meet its commitments as they fall due
over the going concern period.
The going concern assumption is highly sensitive to economic
conditions. The Group closely monitors and manages its funding
position and liquidity risk throughout the year, including
monitoring forecast covenant results, to ensure it has access to
sufficient funds to meet forecast cash requirements. Cash forecasts
are regularly produced and sensitivities considered for, but not
limited to, changes in crude oil prices (adjusted for hedging
undertaken by the Group), production rates and development project
timing and costs. These forecasts and sensitivity analyses allow
management to mitigate liquidity or covenant compliance risks in a
timely manner. See the Financial Review for further details.
Taxation
The Group's operations are subject to a number of specific tax
rules which apply to exploration, development and production. In
addition, the tax provision is prepared before the relevant
companies have filed their tax returns with the relevant tax
authorities and, significantly, before these have been agreed. As a
result of these factors, the tax provision process necessarily
involves the use of a number of estimates and judgements including
those required in calculating the effective tax rate. In
considering the tax on exceptional items, the Group applies the
appropriate statutory tax rate to each item to calculate the
relevant tax charge on exceptional items.
The Group recognises deferred tax assets on unused tax losses
where it is probable that future taxable profits will be available
for utilisation. This requires management to make judgements and
assumptions regarding the likelihood of future taxable profits and
the amount of deferred tax that can be recognised.
Foreign currencies
Items included in the financial statements of each of the
Group's entities are measured using the currency of the primary
economic environment in which the entity operates (functional
currency). The Group's financial statements are presented in United
States Dollars ($), the currency which the Group has elected to use
as its presentation currency.
In the accounts of the Company and its individual subsidiaries,
transactions in currencies other than a company's functional
currency are recorded at the prevailing rate of exchange on the
date of the transaction. At the year end, monetary assets and
liabilities denominated in foreign currencies are retranslated at
the rates of exchange prevailing at the balance sheet date.
Non-monetary assets and liabilities that are measured at historical
cost in a foreign currency are translated using the rate of
exchange as at the dates of the initial transactions. Non-monetary
assets and liabilities measured at fair value in a foreign currency
are translated using the rate of exchange at the date the fair
value was determined. All foreign exchange gains and losses are
taken to profit and loss in the statement of comprehensive
income.
Property, plant and equipment
Property, plant and equipment is stated at cost less accumulated
depreciation and any impairment in value. Cost comprises the
purchase price or construction cost and any costs directly
attributable to making that asset capable of operating as intended
by management. The purchase price or construction cost is the
aggregate amount paid and the fair value of any other consideration
given to acquire the asset.
Oil and gas assets are depleted, on a field-by-field basis,
using the unit of production method based on entitlement to proven
and probable reserves, taking account of estimated future
development expenditure relating to those reserves.
Depreciation on other elements of property, plant and equipment
is provided on a straight-line basis at the following rates:
Office furniture and equipment Five years
Fixtures and fittings Ten years
Long leasehold land period of lease
Each asset's estimated useful life, residual value and method of
depreciation are reviewed and adjusted if appropriate at each
financial year end. No depreciation is charged on assets under
construction.
Oil and gas assets
Exploration and appraisal assets
The Group adopts the successful efforts method of accounting for
exploration and evaluation costs. Pre-licence costs are expensed in
the period in which they are incurred. Expenditure directly
associated with exploration, evaluation or appraisal activities is
initially capitalised as an intangible asset. Such costs include
the costs of acquiring an interest, appraisal well drilling costs,
payments to contractors and an appropriate share of directly
attributable overheads incurred during the evaluation phase. For
such appraisal activity, which may require drilling of further
wells, costs continue to be carried as an asset whilst related
hydrocarbons are considered capable of commercial development. Such
costs are subject to technical, commercial and management review to
confirm the continued intent to develop, or otherwise extract
value. When this is no longer the case, the costs are written off
as exploration and evaluation expenses in the statement of
comprehensive income. When exploration licences are relinquished
without further development, any previous impairment loss is
reversed and the carrying costs are written off through the
statement of comprehensive income. When assets are declared part of
a commercial development, related costs are transferred to
property, plant and equipment. All intangible oil and gas assets
are assessed for any impairment prior to transfer and any
impairment loss is recognised in the statement of comprehensive
income.
Development assets
Expenditure relating to development of assets including the
construction, installation and completion of infrastructure
facilities such as platforms, pipelines and development wells, is
capitalised within property, plant and equipment.
Farm-outs - in the exploration and evaluation phase
The Group does not record any expenditure made by the farmee on
its account. In the event of a partial farm-out, the Group also
does not recognise any gain or loss on its exploration and
evaluation farm-out arrangements but redesignates any costs
previously capitalised in relation to the whole interest as
relating to the partial interest retained. Any cash consideration
received directly from the farmee is credited against costs
previously capitalised in relation to the whole interest with any
excess accounted for by the farmor as a gain on disposal.
Farm-outs - outside the exploration and evaluation phase
In accounting for a farm-out arrangement outside the exploration
and evaluation phase, the Group:
-- Derecognises the proportion of the asset that it has sold to the farmee;
-- Recognises the consideration received or receivable from the
farmee, which represents the cash received and/or the farmee's
obligation to fund the capital expenditure in relation to the
interest retained by the farmor and/or any deferred
consideration;
-- Recognises a gain or loss on the transaction for the
difference between the net disposal proceeds and the carrying
amount of the asset disposed of. A gain is only recognised when the
value of the consideration can be determined reliably. If not, then
the Group accounts for the consideration received as a reduction in
the carrying amount of the underlying assets; and
-- Tests the retained interests for impairment if the terms of
the arrangement indicate that the retained interest may be
impaired.
The consideration receivable on disposal of an item of property,
plant and equipment or an intangible asset is recognised initially
at its fair value by the Group. However, if payment for the item is
deferred, the consideration received is recognised initially at the
cash price equivalent. The difference between the nominal amount of
the consideration and the cash price equivalent is recognised as
interest revenue. Any part of the consideration that is receivable
in the form of cash is treated as a financial asset and is
accounted for at amortised cost.
Carry arrangements
Where amounts are paid on behalf of a carried party these are
capitalised. Where there is an obligation to make payments on
behalf of a carried party and the timing and amount are uncertain,
a provision is recognised. Where the payment is a fixed monetary
amount, a financial liability is recognised.
Changes in unit of production factors
Changes in factors which affect unit of production calculations
are dealt with prospectively, not by immediate adjustment of prior
years' amounts.
Borrowing costs
Borrowing costs directly attributable to the construction of
qualifying assets, which are assets that necessarily take a
substantial period of time to prepare for their intended use, are
added to the cost of those assets, until such time as the assets
are substantially ready for their intended use. All other borrowing
costs are recognised as interest payable in the statement of
comprehensive income in accordance with the effective interest
method.
Impairment of tangible and intangible assets (excluding
goodwill)
At each balance sheet date, the Group reviews the carrying
amounts of its oil and gas assets to assess whether there is an
indication that those assets may be impaired. If any such
indication exists, the Group makes an estimate of the asset's
recoverable amount. An asset's recoverable amount is the higher of
its fair value less costs of disposal and its value in use. In
assessing value in use, the estimated future cash flows
attributable to the asset are discounted to their present value
using a post-tax discount rate that reflects current market
assessments of the time value of money and the risks specific to
the asset.
If the recoverable amount of an asset is estimated to be less
than its carrying amount, the carrying amount of the asset is
reduced to its recoverable amount. An impairment loss is recognised
immediately in the statement of comprehensive income.
Where an impairment loss subsequently reverses, the carrying
amount of the asset is increased to the revised estimate of its
recoverable amount, but only so that the increased carrying amount
does not exceed the carrying amount that would have been determined
had no impairment loss been recognised for the asset in prior
years. A reversal of an impairment loss is recognised immediately
in the statement of comprehensive income.
Non-current assets held for sale
Non-current assets classified as held for sale are measured at
the lower of carrying amount and fair value less costs of
disposal.
Non-current assets are classified as held for sale if their
carrying amount will be recovered through a sale transaction rather
than through continuing use. This condition is regarded as met only
when the sale is highly probable and the asset is available for
immediate sale in its present condition. Management must be
committed to the sale which should be expected to qualify for
recognition as a completed sale within one year from the date of
classification.
Financial instruments (policy applicable from 1 January
2018)
Financial assets and financial liabilities are recognised when
the Group becomes a party to the contractual provisions of the
financial instrument.
Financial assets are derecognised when the contractual rights to
the cash flows from the financial asset expire, or when the
financial asset and substantially all the risks and rewards are
transferred. A financial liability is derecognised when it is
extinguished, discharged, cancelled or expires. When an existing
financial liability is replaced by another from the same lender on
substantially different terms, or the terms of an existing
liability are substantially modified, such an exchange or
modification is treated as the derecognition of the original
liability and the recognition of a new liability. The difference in
the respective carrying amounts is recognised in the statement of
profit or loss.
Financial assets and financial liabilities are offset and the
net amount is reported in the consolidated statement of financial
position if there is a currently enforceable legal right to offset
the recognised amounts and there is an intention to settle on a net
basis.
Financial assets
Initial recognition and initial measurement
Financial assets are classified, at initial recognition, as
amortised cost, fair value through other comprehensive income
('FVOCI'), or fair value through profit or loss ('FVPL').
The classification of financial assets at initial recognition
depends on the financial asset's contractual cash flow
characteristics and the Group's business model for managing them.
With the exception of trade receivables that do not contain a
significant financing component or for which the Group has applied
the practical expedient, the Group initially measures a financial
asset at its fair value plus transaction costs (in the case of a
financial asset not at fair value through profit or loss). Trade
receivables that do not contain a significant financing component
or for which the Group has applied the practical expedient are
measured at the transaction price determined under IFRS 15.
Subsequent measurement
Financial assets at amortised cost
This category is the most relevant to the Group. The Group
measures financial assets at amortised cost if both of the
following conditions are met:
-- The financial asset is held within a business model with the
objective to hold financial assets in order to collect contractual
cash flows; and
-- The contractual terms of the financial asset give rise on
specified dates to cash flows that are solely payments of principal
and interest on the principal amount outstanding.
Financial assets at amortised cost are subsequently measured
using the effective interest rate method and are subject to
impairment. Gains and losses are recognised in profit or loss when
the asset is derecognised, modified or impaired.
Financial assets at fair value through other comprehensive
income (debt instruments)
The Group measures debt instruments at fair value through OCI if
both of the following conditions are met:
-- The financial asset is held within a business model with the
objective of both holding to collect contractual cash flows and
selling; and
-- The contractual terms of the financial asset give rise on
specified dates to cash flows that are solely payments of principal
and interest on the principal amount outstanding.
For debt instruments at FVOCI, interest income, foreign exchange
revaluation and impairment losses or reversals are recognised in
the statement of profit or loss and computed in the same manner as
for financial assets measured at amortised cost. The remaining fair
value changes are recognised in OCI. Upon derecognition, the
cumulative fair value change recognised in OCI is recycled to
profit or loss.
Financial assets at fair value through profit or loss
Financial assets at fair value through profit or loss include
financial assets held for trading, financial assets designated upon
initial recognition at fair value through profit or loss, or
financial assets mandatorily required to be measured at fair value.
Financial assets are classified as held for trading if they are
acquired for the purpose of selling or repurchasing in the near
term. All financial assets not classified as measured at amortised
cost or FVOCI as described above are measured at FVPL.
Derivatives, including separated embedded derivatives, are also
classified as held for trading unless they are designated as
effective hedging instruments. Financial assets with cash flows
that are not solely payments of principal and interest are
classified and measured at fair value through profit or loss,
irrespective of the business model. Notwithstanding the criteria
for debt instruments to be classified at amortised cost or at
FVOCI, as described above, debt instruments may be designated at
FVPL on initial recognition if doing so eliminates, or
significantly reduces, an accounting mismatch.
Financial assets at FVPL are carried in the statement of
financial position at fair value with net changes in fair value
recognised in the statement of profit or loss.
This category includes derivative instruments and listed equity
investments which the Group had not irrevocably elected to classify
at FVOCI.
Financial assets with embedded derivatives are considered in
their entirety when determining whether their cash flows are solely
payment of principal and interest.
Impairment of financial assets
IFRS 9's impairment requirements use more forward-looking
information to recognise expected credit losses - the ECL model.
This replaces IAS 39's 'incurred loss model'.
The Group recognises an allowance for ECLs for all debt
instruments not held at fair value through profit or loss. ECLs are
based on the difference between the contractual cash flows due in
accordance with the contract and all the cash flows that the Group
expects to receive, discounted at an approximation of the original
effective interest rate. The expected cash flows will include cash
flows from the sale of collateral held or other credit enhancements
that are integral to the contractual terms.
ECLs are recognised in two stages. For credit exposures for
which there has not been a significant increase in credit risk
since initial recognition, ECLs are provided for credit losses that
result from default events that are possible within the next 12
months (a '12-month ECL'). For those credit exposures for which
there has been a significant increase in credit risk since initial
recognition, a loss allowance is required for credit losses
expected over the remaining life of the exposure, irrespective of
the timing of the default (a 'lifetime ECL').
For trade receivables and contract assets, the Group applies a
simplified approach in calculating ECLs. Therefore, the Group does
not track changes in credit risk, but instead recognises a loss
allowance based on lifetime ECLs at each reporting date. The Group
has established a provision matrix that is based on its historical
credit loss experience, adjusted for forward-looking factors
specific to the debtors and the economic environment.
For debt instruments at FVOCI, the Group applies the low credit
risk simplification. At every reporting date, the Group evaluates
whether the debt instrument is considered to have low credit risk
using all reasonable and supportable information that is available
without undue cost or effort. In making that evaluation, the Group
reassesses the internal credit rating of the debt instrument. In
addition, the Group considers that there has been a significant
increase in credit risk when contractual payments are more than 30
days past due.
It is the Group's policy to measure ECLs on such instruments on
a 12-month basis.
Financial liabilities
Initial recognition and initial measurement
Financial liabilities are classified, at initial recognition, as
financial liabilities at FVPL, loans and borrowings, payables, or
as derivatives designated as hedging instruments in an effective
hedge, as appropriate.
All financial liabilities are recognised initially at fair value
and, in the case of loans and borrowings and payables, net of
directly attributable transaction costs.
The Group's financial liabilities include loans and borrowings,
trade and other payables, quoted and unquoted financial
liabilities, and derivative financial instruments.
Subsequent measurement
Financial liabilities at fair value through profit or loss
Financial liabilities at FVPL include financial liabilities held
for trading and financial liabilities designated upon initial
recognition as at fair value through profit or loss.
Financial liabilities are classified as held for trading if they
are incurred for the purpose of repurchasing in the near term. This
category also includes derivative financial instruments entered
into by the Group that are not designated as hedging instruments in
hedge relationships as defined by IFRS 9. Separated embedded
derivatives are also classified as held for trading unless they are
designated as effective hedging instruments. Gains or losses on
liabilities held for trading are recognised in the statement of
profit or loss.
The Group uses derivative financial instruments, such as forward
currency contracts, interest rate swaps and commodity contracts, to
address its foreign currency risks, interest rate risks and
commodity price risks, respectively. Such derivative financial
instruments are initially recognised at fair value on the date on
which a derivative contract is entered into and are subsequently
remeasured at fair value. Derivatives are carried as financial
assets when the fair value is positive and as financial liabilities
when the fair value is negative. Any changes in fair value are
recognised immediately in the profit or loss within 'Remeasurements
and exceptional items' profit or loss on the face of the income
statement. When a derivative reaches maturity, the realised gain or
loss is included within the Group's 'Business performance' results
with a corresponding reclassification from 'Remeasurements and
exceptional items'.
Option premium received or paid for commodity derivatives are
amortised into 'Business performance' revenue over the period
between the inception of the option, and that option's expiry date.
This results in a corresponding reclassification from
'Remeasurements and exceptional items' revenue.
The Group has not designated any derivative financial
instruments as hedging instruments for the periods contained within
these financial statements.
Loans and borrowings
This is the category most relevant to the Group and includes the
measurement of the bonds. After initial recognition,
interest-bearing loans and borrowings are subsequently measured at
amortised cost using the EIR method. Gains and losses are
recognised in profit or loss when the liabilities are derecognised
as well as through the EIR amortisation process. This category
generally applies to interest-bearing loans and borrowings.
Amortised cost is calculated by taking into account any discount
or premium on acquisition and fees or costs that are an integral
part of the EIR. The EIR amortisation is included as finance costs
in the statement of profit or loss.
Inventories
Inventories of consumable well supplies are stated at the lower
of cost and net realisable value, cost being determined on an
average cost basis. Inventories of hydrocarbons are stated at the
lower of cost and net realisable value.
Cash and cash equivalents
Cash and cash equivalents includes cash at bank, cash in hand,
outstanding bank overdrafts and highly liquid interest-bearing
securities with original maturities of three months or less.
Equity
Share capital
The balance classified as equity share capital includes the
total net proceeds (both nominal value and share premium) on issue
of registered share capital of the parent company. Share issue
costs associated with the issuance of new equity are treated as a
direct reduction of proceeds.
Merger reserve
Merger reserve represents the difference between the market
value of shares issued to effect business combinations less the
nominal value of shares issued. The merger reserve in the Group
financial statements also includes the consolidation adjustments
that arise under the application of the pooling of interest
method.
Cash flow hedge reserve
For cash flow hedges, the effective portion of the gain or loss
on the hedging instrument is recognised directly as other
comprehensive income in the cash flow hedge reserve. Upon
settlement of the hedged item, the change in fair value is
transferred to profit or loss.
Share-based payments reserve
Equity-settled share-based payment transactions are measured at
the fair value of the services received, and the corresponding
increase in equity is recorded directly at the fair value of the
services received. The share-based payments reserve includes shares
held within the Employee Benefit Trust.
Retained earnings
Retained earnings contain the accumulated results attributable
to the shareholders of the parent company.
Employee Benefit Trust
EnQuest PLC shares held by the Group are deducted from the
share-based payments reserve and are recognised at cost.
Consideration received for the sale of such shares is also
recognised in equity, with any difference between the proceeds from
the sale and the original cost being taken to reserves. No gain or
loss is recognised in the statement of comprehensive income on the
purchase, sale, issue or cancellation of equity shares.
Provisions
Decommissioning
Provision for future decommissioning costs is made in full when
the Group has an obligation: to dismantle and remove a facility or
an item of plant; to restore the site on which it is located; and
when a reasonable estimate of that liability can be made. The
amount recognised is the present value of the estimated future
expenditure. An amount equivalent to the discounted initial
provision for decommissioning costs is capitalised and amortised
over the life of the underlying asset on a unit of production basis
over proven and probable reserves. Any change in the present value
of the estimated expenditure is reflected as an adjustment to the
provision and the oil and gas asset.
The unwinding of the discount applied to future decommissioning
provisions is included under finance costs in the statement of
comprehensive income.
Other
Provisions are recognised when: the Group has a present legal or
constructive obligation as a result of past events; it is probable
that an outflow of resources will be required to settle the
obligation; and a reliable estimate can be made of the amount of
the obligation.
Leases
The determination of whether an arrangement is or contains a
lease is based on the substance of the arrangement at the inception
date. The arrangement is assessed for whether fulfilment of the
arrangement is dependent on the use of a specific asset or assets
or the arrangement conveys a right to use the asset or assets, even
if that right is not explicitly specified in an arrangement.
Group as a lessee
A lease is classified at the inception date as a finance lease
or an operating lease. A lease that transfers substantially all the
risks and rewards incidental to ownership to the Group is
classified as a finance lease.
Finance leases are capitalised at the commencement of the lease
at the fair value of the leased asset or, if lower, at the present
value of the minimum lease payments. Lease payments are apportioned
between finance charges and reduction of the lease liability so as
to achieve a constant rate of interest on the remaining balance of
the liability. Finance charges are recognised in finance costs in
the income statement.
A leased asset is depreciated over the useful life of the asset.
However, if there is no reasonable certainty that the Group will
obtain ownership by the end of the lease term, the asset is
depreciated over the shorter of the estimated useful life of the
asset and the lease term. Lease charter payment credits, arising
from the non-performance of the leased asset, are recognised as an
operating expense in the income statement for the period to which
they relate.
An operating lease is a lease other than a finance lease.
Operating lease payments are recognised as an operating expense in
the income statement on a straight-line basis over the lease
term.
Group as a lessor
Leases in which the Group does not transfer substantially all
the risks and rewards of ownership of an asset are classified as
operating leases. Rental income arising is accounted for on a
straight-line basis over the lease terms and is included in revenue
in the statement of profit or loss due to its operating nature.
Initial direct costs incurred in negotiating and arranging an
operating lease are added to the carrying amount of the leased
asset and recognised over the lease term on the same basis as
rental income. Contingent rents are recognised as revenue in the
period in which they are earned.
Revenue from contracts with customers
Revenue from contracts with customers is recognised when control
of the goods or services are transferred to the customer at an
amount that reflects the consideration to which the Group expects
to be entitled to in exchange for those goods or services. The
Group has concluded that it is the principal in its revenue
arrangements because it typically controls the goods or services
before transferring them to the customer.
Sale of crude oil, gas and condensate
The sale of crude oil, gas or condensate represents a single
performance obligation, being the sale of barrels equivalent on
collection of a cargo or on delivery of commodity into an
infrastructure. Revenue is accordingly recognised for this
performance obligation when control over the corresponding
commodity is transferred to the customer. Variable revenue
conditions can arise on either party based on the failure to
provide commitments detailed within the contract. These variations
arise as an event occurs and therefore the transaction price is
known at the timing of the performance obligations with no
judgement required. The normal credit term is 30 to 90 days upon
collection or delivery.
Tariff revenue for the use of Group infrastructure
Tariffs are charged to customers for the use of infrastructure
owned by the Group. There is one contract per customer which is for
a period of 12 months or less and is based on one performance
obligation for the use of Group assets. The use of the assets is
not separable as they are interdependent in order to fulfil the
contract and no one item of infrastructure can be individually
isolated. Revenue is recognised over the performance of the
contract as services are provided for the use of the infrastructure
at the agreed contracted rates on a throughput basis.
Other income
Other income is recognised to the extent that it is probable
economic benefits will flow to the Group and the revenue can be
reliably measured.
Production imbalances and under/over-lift
Production imbalances arise on fields as oil is lifted per each
joint venture party, resulting in a variance in the volume of oil
lifted versus the entitlement per owner per their working interest.
All Group fields are operated through a Joint Venture Agreement
('JVA') through which production imbalances are settled. Settlement
occurs through agreed lifting schedules and are not settled in
cash, with the exception of a misbalance at the cessation of
contract. As collaborative agreements and non-monetary exchanges,
the transactions do not meet the definition of a customer under
IFRS 15 and are recognised through cost of sales.
The under or over-lifted positions of hydrocarbons arising from
production imbalances are valued at market prices prevailing at the
balance sheet date. An under-lift of production from a field is
included in current receivables and valued at the reporting date
spot price or prevailing contract price. An over-lift of production
from a field is included in current liabilities and valued at the
reporting date spot price or prevailing contract price. Movements
in under or over-lifted positions are accounted for through cost of
sales.
Remeasurements and exceptional items
As permitted by IAS 1 (Revised): Presentation of Financial
Statements, certain items are presented separately. The items that
the Group separately presents as exceptional on the face of the
statement of comprehensive income are those material items of
income and expense which, because of the nature or expected
infrequency of the events giving rise to them, merit separate
presentation to allow shareholders to understand better the
elements of financial performance in the year, so as to facilitate
comparison with prior periods and to better assess trends in
financial performance.
The following items are classified as Remeasurements and
exceptional items ('exceptional'):
-- Unrealised mark-to-market changes in the remeasurement of
derivative contracts are included in exceptional profit or loss.
This includes the recycling of realised amounts from exceptional
items into 'Business performance' income when a derivative
instrument matures, together with the recycling of option premium
amortisation from exceptional to 'Business performance' as set out
in the derivatives policy previously;
-- Impairments and write offs/write downs are deemed to be
exceptional in nature. This includes impairments of tangible and
intangible assets, and write offs/write downs of unsuccessful
exploration. Other non-routine write offs/write downs, where deemed
material, are also included in this category;
-- The depletion of a fair value uplift to property, plant and
equipment that arose from the merger accounting applied at the time
of EnQuest's formation; and
-- Other exceptional items that arise from time to time as
reviewed by management and disclosed as exceptionals in the notes
to the financial statements, such as the acquisition accounting of
Magnus and other interests in 2017 and 2018.
Employee benefits
Short-term employee benefits
Short-term employee benefits such as salaries, social premiums
and holiday pay, are expensed when incurred.
Pension obligations
The Group's pension obligations consist of defined contribution
plans. A defined contribution plan is a pension plan under which
the Group pays fixed contributions. The Group has no further
payment obligations once the contributions have been paid. The
amount charged to the statement of comprehensive income in respect
of pension costs reflects the contributions payable in the year.
Differences between contributions payable during the year and
contributions actually paid are shown as either accrued liabilities
or prepaid assets in the balance sheet.
Share-based payment transactions
Eligible employees (including Directors) of the Group receive
remuneration in the form of share-based payment transactions,
whereby employees render services in exchange for shares or rights
over shares (equity-settled transactions) of EnQuest PLC.
Equity-settled transactions
The cost of equity-settled transactions with employees is
measured by reference to the fair value at the date on which they
are granted. Fair value is measured in reference to the scheme
rules, as detailed in note 18. In valuing equity-settled
transactions, no account is taken of any service or performance
conditions, other than conditions linked to the price of the shares
of EnQuest PLC (market conditions) or 'non-vesting' conditions, if
applicable.
The cost of equity-settled transactions is recognised over the
period in which the relevant employees become fully entitled to the
award (the vesting period). The cumulative expense recognised for
equity-settled transactions at each reporting date until the
vesting date reflects the extent to which the vesting period has
expired and the Group's best estimate of the number of equity
instruments that will ultimately vest. The statement of
comprehensive income charge or credit for a period represents the
movement in cumulative expense recognised as at the beginning and
end of that period.
No expense is recognised for awards that do not ultimately vest,
except for awards where vesting is conditional upon a market or
non-vesting condition, which are treated as vesting irrespective of
whether or not the market or non-vesting condition is satisfied,
provided that all other performance conditions are satisfied.
Equity awards cancelled are treated as vesting immediately on the
date of cancellation, and any expense not previously recognised for
the award at that date is recognised in the statement of
comprehensive income.
Taxes
Income taxes
Current tax assets and liabilities are measured at the amount
expected to be recovered from or paid to the taxation authorities,
based on tax rates and laws that are enacted or substantively
enacted by the balance sheet date.
Deferred tax is provided in full on temporary differences
arising between the tax bases of assets and liabilities and their
carrying amounts in the Group financial statements. However,
deferred tax is not accounted for if it arises from initial
recognition of an asset or liability in a transaction other than a
business combination that at the time of the transaction affects
neither accounting nor taxable profit or loss. Deferred tax is
measured on an undiscounted basis using tax rates (and laws) that
have been enacted or substantively enacted by the balance sheet
date and are expected to apply when the related deferred tax asset
is realised or the deferred tax liability is settled. Deferred tax
assets are recognised to the extent that it is probable that future
taxable profits will be available against which the temporary
differences can be utilised.
Deferred tax liabilities are recognised for taxable temporary
differences arising on investments in subsidiaries, except where
the Group is able to control the reversal of the temporary
difference and it is probable that the temporary difference will
not reverse in the foreseeable future.
The carrying amount of deferred income tax assets is reviewed at
each balance sheet date. Deferred income tax assets and liabilities
are offset only if a legal right exists to offset current tax
assets against current tax liabilities, the deferred income taxes
relate to the same taxation authority and that authority permits
the Group to make a single net payment.
Production taxes
In addition to corporate income taxes, the Group's financial
statements also include and disclose production taxes on net income
determined from oil and gas production.
Production tax relates to Petroleum Revenue Tax ('PRT') within
the UK and is accounted for under IAS 12 Income Taxes since it has
the characteristics of an income tax as it is imposed under
Government authority and the amount payable is based on taxable
profits of the relevant fields. Current and deferred PRT is
provided on the same basis as described above for income taxes.
Investment allowance
The UK taxation regime provides for a reduction in ring fence
supplementary corporation tax where investment in new or existing
UK assets qualify for a relief known as investment allowance.
Investment allowance must be activated by commercial production
from the same field before it can be claimed. The Group has both
unactivated and activated investment allowance which could reduce
future supplementary corporation taxation. The Group's policy is
that investment allowance is recognised as a reduction in the
charge to taxation in the years claimed.
3. Segment information
Management have considered the requirements of IFRS 8: Operating
Segments in regard to the determination of operating segments and
concluded that the Group has two significant operating segments:
the North Sea and Malaysia. Operations are managed by location and
all information is presented per geographical segment. The
information reported to the Chief Operating Decision Maker does not
include an analysis of assets and liabilities and accordingly this
information is not presented.
Year ended 31 December 2018 Total
North All other Adjustments
$'000 Sea Malaysia segments segments and eliminations Consolidated
----------------------------------- --------- -------- --------- --------- ----------------- ------------
Revenue:
----------------------------------- --------- -------- --------- --------- ----------------- ------------
Revenue from contracts with
customers 1,140,116 144,483 - 1,284,599 - 1,284,599
----------------------------------- --------- -------- --------- --------- ----------------- ------------
Other income 9,046 - 395 9,441 4,397 13,838
----------------------------------- --------- -------- --------- --------- ----------------- ------------
Total revenue 1,149,162 144,483 395 1,294,040 4,397 1,298,437
----------------------------------- --------- -------- --------- --------- ----------------- ------------
Income/(expenses):
----------------------------------- --------- -------- --------- --------- ----------------- ------------
Depreciation and depletion (411,624) (30,767) - (442,391) - (442,391)
----------------------------------- --------- -------- --------- --------- ----------------- ------------
Net impairment reversal/(charge)
to oil and gas assets (125,009) (1,037) - (126,046) - (126,046)
----------------------------------- --------- -------- --------- --------- ----------------- ------------
Impairment reversal of investments (121) - - (121) - (121)
----------------------------------- --------- -------- --------- --------- ----------------- ------------
Exploration write offs and
impairments (1,407) - - (1,407) - (1,407)
----------------------------------- --------- -------- --------- --------- ----------------- ------------
Segment profit/(loss) 276,365 38,442 5,839 320,646 6,092 326,738
----------------------------------- --------- -------- --------- --------- ----------------- ------------
Other disclosures:
----------------------------------- --------- -------- --------- --------- ----------------- ------------
Capital expenditure 167,070 15,806 - 182,876 - 182,876
----------------------------------- --------- -------- --------- --------- ----------------- ------------
Year ended 31 December 2017 Total
North All other Adjustments
$'000 Sea Malaysia segments segments and eliminations Consolidated
----------------------------------- --------- -------- --------- --------- ----------------- ------------
Revenue:
----------------------------------- --------- -------- --------- --------- ----------------- ------------
Revenue from contracts with
customers 527,272 119,545 - 646,817 - 646,817
----------------------------------- --------- -------- --------- --------- ----------------- ------------
Other income 8,578 347 - 8,925 (28,291) (19,366)
----------------------------------- --------- -------- --------- --------- ----------------- ------------
Total revenue 535,850 119,892 - 655,742 (28,291) 627,451
----------------------------------- --------- -------- --------- --------- ----------------- ------------
Income/(expenses):
----------------------------------- --------- -------- --------- --------- ----------------- ------------
Depreciation and depletion (201,684) (27,514) - (229,198) - (229,198)
----------------------------------- --------- -------- --------- --------- ----------------- ------------
Net impairment reversal/(charge)
to oil and gas assets (187,716) 15,745 - (171,971) - (171,971)
----------------------------------- --------- -------- --------- --------- ----------------- ------------
Impairment reversal of investments (19) - - (19) - (19)
----------------------------------- --------- -------- --------- --------- ----------------- ------------
Exploration write offs and
impairments 193 - - 193 - 193
----------------------------------- --------- -------- --------- --------- ----------------- ------------
Segment profit/(loss) (135,187) 39,062 22,844 (73,281) (23,413) (96,694)
----------------------------------- --------- -------- --------- --------- ----------------- ------------
Other disclosures:
----------------------------------- --------- -------- --------- --------- ----------------- ------------
Capital expenditure 322,398 2,299 - 324,697 - 324,697
----------------------------------- --------- -------- --------- --------- ----------------- ------------
Adjustments and eliminations
Finance income and costs and gains and losses on derivatives are
not allocated to individual segments as the underlying instruments
are managed on a Group basis.
Capital expenditure consists of property, plant and equipment
and intangible assets, including assets from the acquisition of
subsidiaries. Inter-segment revenues are eliminated on
consolidation. All other adjustments are part of the
reconciliations presented further below.
Reconciliation of profit/(loss):
Year ended Year ended
31 December 31 December
2017
2018 $'000
$'000
---------------------------------------------------- ------------ ------------
Segment profit/(loss) 320,646 (73,281)
---------------------------------------------------- ------------ ------------
Finance income 3,389 2,213
---------------------------------------------------- ------------ ------------
Finance expense (236,142) (149,292)
---------------------------------------------------- ------------ ------------
Gain/(loss) on oil and foreign exchange derivatives 6,092 (23,413)
---------------------------------------------------- ------------ ------------
Profit/(loss) before tax 93,985 (243,773)
---------------------------------------------------- ------------ ------------
Revenue from two customers relating to the North Sea operating
segment each exceed 10% of the Group's consolidated revenue arising
from sales of crude oil, with the total amount of $580.5 million
(2017: two customers; $206.1 million arising in the North Sea
operating segment and $105.2 million in the Malaysia operating
segment).
All of the Group's segment assets (non-current assets excluding
financial instruments, deferred tax assets and other financial
assets) are located in the United Kingdom except for $111.7 million
located in Malaysia (2017: $119.1 million).
4. Remeasurements and exceptional items
Impairments
Fair value and
write
Year ended 31 December 2018 remeasurement offs Other
$'000 (i) (ii) (iii) Total
---------------------------------------- -------------- ----------- ------- ---------
Revenue and other operating income 97,432 - - 97,432
---------------------------------------- -------------- ----------- ------- ---------
Cost of sales 2,310 (592) - (4,119)
---------------------------------------- -------------- ----------- ------- ---------
Net impairment (charge)/reversal on oil
and gas assets - (126,046) - (126,046)
---------------------------------------- -------------- ----------- ------- ---------
Other income - - 78,316 78,316
---------------------------------------- -------------- ----------- ------- ---------
Other expenses (9,590) (1,528) (3,597) (14,715)
---------------------------------------- -------------- ----------- ------- ---------
Finance costs - - (28) (28)
---------------------------------------- -------------- ----------- ------- ---------
90,152 (128,166) 74,691 36,677
---------------------------------------- -------------- ----------- ------- ---------
Tax on items above (36,962) 48,161 1,207 12,406
---------------------------------------- -------------- ----------- ------- ---------
53,190 (80,005) 75,898 49,083
---------------------------------------- -------------- ----------- ------- ---------
Impairments
Fair value and
write
Year ended 31 December 2017 Remeasurement offs Other
$'000 (i) (ii) (iii) Total
---------------------------------------- -------------- ----------- -------- ---------
Revenue and other operating income (7,716) - - (7,716)
---------------------------------------- -------------- ----------- -------- ---------
Cost of sales 9,726 (2,682) (1,563) 5,481
---------------------------------------- -------------- ----------- -------- ---------
Net impairment (charge)/reversal on oil
and gas assets - (171,971) - (171,971)
---------------------------------------- -------------- ----------- -------- ---------
Other income 1,685 193 48,735 50,613
---------------------------------------- -------------- ----------- -------- ---------
Other expenses - (19) (20,339) (20,358)
---------------------------------------- -------------- ----------- -------- ---------
Finance costs - - (272) (272)
---------------------------------------- -------------- ----------- -------- ---------
3,695 (174,479) 26,561 (144,223)
---------------------------------------- -------------- ----------- -------- ---------
Tax on items above (1,473) 65,730 5,482 69,739
---------------------------------------- -------------- ----------- -------- ---------
Other tax exceptional items(iv) - - 47,208 47,208
---------------------------------------- -------------- ----------- -------- ---------
2,222 (108,749) 79,251 (27,276)
---------------------------------------- -------------- ----------- -------- ---------
(i) Fair value remeasurements include unrealised mark-to-market
movements on derivative contracts and other financial instruments
where the Group does not classify them as effective hedges. It also
includes the impact of recycled realised gains and losses
(including option premia) out of 'Remeasurements and exceptional
items' and into 'Business performance' profit or loss. Refer to
note 2 for further details on the Group's accounting policies for
derivatives and 'Remeasurements and exceptional items'. In
addition, this includes the fair value remeasurement of contingent
consideration on the Magnus vendor loan of $9.7 million (2017:
includes $1.3 million gain in respect of the disposal of the Ascent
Resources loan notes)
(ii) Impairments and write offs includes an impairment of
tangible oil and gas assets totalling $126.0 million (2017:
impairment of $172.0 million). 2017 includes a charge of $2.7
million in relation to exceptional inventory write downs. Further
details on the tangible impairment are provided in note 10
(iii) Other includes a $1.3 million loss in relation to the
revaluation of the option to purchase the Magnus oil field and
other interests and $74.3 million in relation to the step
acquisition uplift of the original 25% equity acquired in 2017 (see
note 29) (2017: $22.3 million purchase option, $16.1 million
Thistle decommissioning option and $10.3 million 25% acquisition
value, totalling a gain of $48.7 million). Other movements mainly
relate to the derecognition of contingent consideration on future
exploration of $5.3 million (see note 22) (2017: Charge of $10.3
million in relation to the 2014 PM8 cost recovery settlement
agreement, a charge of $6.4 million for the cancellation of
contracts and a charge of $2.8 million in relation to the provision
on restricted cash). Other income also includes other items of
income and expense which, because of the nature or expected
infrequency of the events giving rise to them, merit separate
presentation to allow shareholders to understand better the
elements of financial performance in the year so as to facilitate
comparison with prior periods and to better assess trends in
financial performance
(iv) In 2017, other tax exceptional items included $13.2 million
for the recognition of previously de-recognised tax losses,
together with $34.0 million for the impact on deferred tax of a
revision to the balance of non-qualifying expenditure
5. Revenue and expenses
(a) Revenue
The Group generates revenue through the sale of crude oil, gas
and condensate, and the provision of infrastructure to its
customers for tariff income. Other sources of revenue include
amounts related to derivative contracts and rental income from
operating leases.
The nature and effect of initially applying IFRS 15 on the
Group's financial statements are disclosed in note 2.
Year ended Year ended
31 December 31 December
2018 2017
$'000 $'000
--------------------------------------------------------- ------------ ------------
Revenue from contracts with customers:
--------------------------------------------------------- ------------ ------------
Revenue from crude oil sales 1,237,600 636,966
--------------------------------------------------------- ------------ ------------
Revenue from gas and condensate sales 43,063 2,822
--------------------------------------------------------- ------------ ------------
Tariff revenue 3,936 7,029
--------------------------------------------------------- ------------ ------------
Total revenue from contracts with customers 1,284,599 646,817
--------------------------------------------------------- ------------ ------------
Rental income 7,205 7,074
--------------------------------------------------------- ------------ ------------
Realised (losses)/gains on oil derivative contracts
(see note 20(f)) (93,035) (20,575)
--------------------------------------------------------- ------------ ------------
Other operating revenue 2,236 1,851
--------------------------------------------------------- ------------ ------------
Business performance revenue 1,201,005 635,167
--------------------------------------------------------- ------------ ------------
Unrealised (losses)/gains on oil derivative contracts(i)
(see note 20(f)) 97,432 (7,716)
--------------------------------------------------------- ------------ ------------
Total revenue and other operating income 1,298,437 627,451
--------------------------------------------------------- ------------ ------------
(i) Unrealised gains and losses on oil derivative contracts
which are either ineffective for hedge accounting purposes or held
for trading are disclosed as exceptional items in the income
statement (see note 4)
Disaggregation of revenue from contracts with customers
Year ended Year ended
31 December 31 December
2018 2017
$'000 $'000
-------------------------------------------- --------- ------------ --------- ------------
North Sea Malaysia North Sea Malaysia
-------------------------------------------- --------- ------------ --------- ------------
Revenue from contracts with customers:
-------------------------------------------- --------- ------------ --------- ------------
Revenue from crude oil sales 1,096,581 141,019 519,694 117,272
-------------------------------------------- --------- ------------ --------- ------------
Revenue from gas and condensate sales 39,599 3,464 549 2,273
-------------------------------------------- --------- ------------ --------- ------------
Tariff revenue 3,936 - 7,029 -
-------------------------------------------- --------- ------------ --------- ------------
Total revenue from contracts with customers 1,140,116 144,483 527,272 119,545
-------------------------------------------- --------- ------------ --------- ------------
Revenue derived from the sale of crude oil, gas and condensate
is recognised as goods transferred at a point in time when control
is gained by the customer on collection or delivery. The sale of
oil is subject to market prices. The Group manages this risk
through the use of commodity derivative contracts. Revenue derived
from tariff revenue is recognised as the service is provided over
time.
Contract balances
The following table provides information about receivables from
contracts with customers. There are no contract assets or contract
liabilities.
2018 2017
$'000 $'000
------------------ ------ ------
Trade receivables 69,857 80,743
------------------ ------ ------
Trade receivables are non-interest-bearing and are generally on
terms of 30 to 90 days post control gained by the customer. In 2018
and 2017, no provision was recognised for expected credit losses on
trade receivables.
(b) Cost of sales
Year ended Year ended
31 December 31 December
2018 2017
$'000 $'000
------------------------------------------------------------- ------------ ------------
Production costs 396,880 287,064
------------------------------------------------------------- ------------ ------------
Tariff and transportation expenses 68,446 62,208
------------------------------------------------------------- ------------ ------------
Realised loss/(gain) on foreign exchange derivative
contracts(i) (see note 20(f)) 615 4,848
------------------------------------------------------------- ------------ ------------
Change in lifting position (14,332) (20,643)
------------------------------------------------------------- ------------ ------------
Crude oil inventory movement (10,761) 237
------------------------------------------------------------- ------------ ------------
Depletion of oil and gas assets (see note 10) 437,104 223,135
------------------------------------------------------------- ------------ ------------
Other cost of operations 48,068 12,657
------------------------------------------------------------- ------------ ------------
Business performance cost of sales 926,020 569,506
------------------------------------------------------------- ------------ ------------
Depletion of oil and gas assets (see note 10) - 1,563
------------------------------------------------------------- ------------ ------------
Write down of inventory - 2,682
------------------------------------------------------------- ------------ ------------
Unrealised (gains)/losses on foreign exchange derivative
contracts(ii) (see note 20(f)) (248) (9,726)
------------------------------------------------------------- ------------ ------------
Unrealised (gains)/losses on carbon derivative contracts(ii)
(see note 20(f)) (2,062) -
------------------------------------------------------------- ------------ ------------
Other expenses 592 -
------------------------------------------------------------- ------------ ------------
Total cost of sales 924,302 564,025
------------------------------------------------------------- ------------ ------------
(i) The realised loss on foreign exchange derivative contracts
was $0.6 million for contracts related to operating expenditure
(2017: loss of $4.8 million related to capital expenditure)
(ii) Unrealised gains and losses on foreign exchange derivative
contracts which are held for trading are disclosed as exceptional
in the income statement (see note 4)
(c) General and administration expenses
Year ended Year ended
31 December 31 December
2018 2017
$'000 $'000
----------------------------------------------------------- ------------ ------------
Staff costs (see note 5(f)) 91,113 79,138
----------------------------------------------------------- ------------ ------------
Depreciation (see note 10) 5,287 4,500
----------------------------------------------------------- ------------ ------------
Other general and administration costs 32,764 20,077
----------------------------------------------------------- ------------ ------------
Recharge of costs to operations and joint venture partners (125,146) (102,867)
----------------------------------------------------------- ------------ ------------
4,018 848
----------------------------------------------------------- ------------ ------------
(d) Other income
Year ended Year ended
31 December 31 December
2018 2017
$'000 $'000
----------------------------------------------------------------- ------------ ------------
Net foreign exchange gains 21,911 -
----------------------------------------------------------------- ------------ ------------
Prior year general and administrative expenses recovery - 5,101
----------------------------------------------------------------- ------------ ------------
Other income 517 1,706
----------------------------------------------------------------- ------------ ------------
Business performance other income 22,428 6,807
----------------------------------------------------------------- ------------ ------------
Excess of fair value over consideration: 25% acquisition
value (see note 29) - 10,314
----------------------------------------------------------------- ------------ ------------
Excess of fair value over consideration: Purchase option
(see note 29) (1,329) 22,300
----------------------------------------------------------------- ------------ ------------
Excess of fair value over consideration: Thistle decommissioning
option (see note 29) - 16,120
----------------------------------------------------------------- ------------ ------------
Fair value gain on step acquisition (see note 29) 74,345 -
----------------------------------------------------------------- ------------ ------------
Contingent consideration release 5,300 -
----------------------------------------------------------------- ------------ ------------
Gain on disposal of financial assets - 1,263
----------------------------------------------------------------- ------------ ------------
Change in provision for contingent consideration - 423
----------------------------------------------------------------- ------------ ------------
Other exceptional income - 193
----------------------------------------------------------------- ------------ ------------
Total other income 100,744 57,420
----------------------------------------------------------------- ------------ ------------
(e) Other expenses
Year ended Year ended
31 December 31 December
2018 2017
$'000 $'000
------------------------------------------------------- ------------ ------------
Net foreign exchange losses - 23,910
------------------------------------------------------- ------------ ------------
Exploration and evaluation expenses: Pre-licence costs
expensed 40 43
------------------------------------------------------- ------------ ------------
Other 3,322 410
------------------------------------------------------- ------------ ------------
Business performance other expenses 3,362 24,363
------------------------------------------------------- ------------ ------------
Change in provision for contingent consideration 9,590 -
------------------------------------------------------- ------------ ------------
2014 PM8 cost recovery settlement agreement - 10,329
------------------------------------------------------- ------------ ------------
Early termination of contracts - 6,435
------------------------------------------------------- ------------ ------------
Write down of receivable 3,010 2,808
------------------------------------------------------- ------------ ------------
Exploration and evaluation expenses: Written off and
impaired 1,407 -
------------------------------------------------------- ------------ ------------
Other expenses 708 786
------------------------------------------------------- ------------ ------------
Total other expenses 18,077 44,721
------------------------------------------------------- ------------ ------------
(f) Staff costs
Year ended Year ended
31 December 31 December
2018 2017
$'000 $'000
---------------------------------------------- ------------ ------------
Wages and salaries 56,316 48,773
---------------------------------------------- ------------ ------------
Social security costs 4,487 4,686
---------------------------------------------- ------------ ------------
Defined contribution pension costs 4,210 3,057
---------------------------------------------- ------------ ------------
Expense of share-based payments (see note 18) 4,645 2,849
---------------------------------------------- ------------ ------------
Other staff costs 4,731 2,486
---------------------------------------------- ------------ ------------
Total employee costs 74,389 61,851
---------------------------------------------- ------------ ------------
Contractor costs 16,724 17,287
---------------------------------------------- ------------ ------------
Total staff costs 91,113 79,138
---------------------------------------------- ------------ ------------
The average number of persons employed by the Group during the
year was 839, with 415 in operating activities and 424 in
administrative functions (2017: 506, with 343 in operating
activities and 163 in administrative functions).
(g) Auditor's remuneration
The following amounts were payable by the Group to its auditor,
Ernst & Young LLP, during the year:
Year ended Year ended
31 December 31 December
2018 2017
$'000 $'000
--------------------------------------------------------- ------------ ------------
Fees payable to the Company's auditor for the audit
of the parent company and Group financial statements 721 584
--------------------------------------------------------- ------------ ------------
Fees payable to the Company's auditor and its associates
for other services:
--------------------------------------------------------- ------------ ------------
The audit of the Company's subsidiaries 108 114
--------------------------------------------------------- ------------ ------------
Audit related assurance services (interim review) 134 181
--------------------------------------------------------- ------------ ------------
Tax advisory services 5 5
--------------------------------------------------------- ------------ ------------
Corporate finance services(i) 368 -
--------------------------------------------------------- ------------ ------------
615 300
--------------------------------------------------------- ------------ ------------
Total auditor's remuneration 1,336 884
--------------------------------------------------------- ------------ ------------
(i) Relates to the reporting accountant's report on the
unaudited pro forma financial information in the Company's combined
prospectus and circular for the rights issue (see note 17)
6. Finance costs/income
Year ended Year ended
31 December 31 December
2018 2017
$'000 $'000
---------------------------------------------------------- ------------ ------------
Finance costs:
---------------------------------------------------------- ------------ ------------
Loan interest payable 93,413 74,434
---------------------------------------------------------- ------------ ------------
Bond interest payable 64,243 63,463
---------------------------------------------------------- ------------ ------------
Unwinding of discount on decommissioning provisions
(see note 22) 12,617 11,471
---------------------------------------------------------- ------------ ------------
Unwinding of discount on other provisions (see note
22) 918 1,838
---------------------------------------------------------- ------------ ------------
Unwinding of discount on financial liabilities (see
note 20(g)) 72 163
---------------------------------------------------------- ------------ ------------
Fair value (gain)/loss on financial instruments at FVPL
(see note 20(f)) 353 (15)
---------------------------------------------------------- ------------ ------------
Finance charges payable under finance leases 55,837 31,273
---------------------------------------------------------- ------------ ------------
Amortisation of finance fees on loans and bonds 8,525 2,760
---------------------------------------------------------- ------------ ------------
Other financial expenses 1,664 5,902
---------------------------------------------------------- ------------ ------------
237,643 191,289
---------------------------------------------------------- ------------ ------------
Less: amounts capitalised to the cost of qualifying
assets (1,529) (42,269)
---------------------------------------------------------- ------------ ------------
Business performance finance expenses 236,114 149,020
---------------------------------------------------------- ------------ ------------
Unwinding of discounts on other provisions 28 272
---------------------------------------------------------- ------------ ------------
236,142 149,292
---------------------------------------------------------- ------------ ------------
Finance income:
---------------------------------------------------------- ------------ ------------
Bank interest receivable 1,821 381
---------------------------------------------------------- ------------ ------------
Unwinding of discount on financial asset (see note 20(g)) 1,517 1,832
---------------------------------------------------------- ------------ ------------
Other financial income 51 -
---------------------------------------------------------- ------------ ------------
3,389 2,213
---------------------------------------------------------- ------------ ------------
7. Income tax
(a) Income tax
The major components of income tax (credit)/expense are as
follows:
Year ended Year ended
31 December 31 December
2018 2017
$'000 $'000
-------------------------------------------------------------- ------------ ------------
Current income tax
-------------------------------------------------------------- ------------ ------------
Current income tax charge 17,763 214
-------------------------------------------------------------- ------------ ------------
Adjustments in respect of current income tax of previous
years - (932)
-------------------------------------------------------------- ------------ ------------
Current overseas income tax
-------------------------------------------------------------- ------------ ------------
Current income tax charge 16,048 11,191
-------------------------------------------------------------- ------------ ------------
Adjustments in respect of current income tax of previous
years 420 263
-------------------------------------------------------------- ------------ ------------
Total current income tax 34,232 10,736
-------------------------------------------------------------- ------------ ------------
Deferred income tax
-------------------------------------------------------------- ------------ ------------
Relating to origination and reversal of temporary differences (61,879) (202,173)
-------------------------------------------------------------- ------------ ------------
Adjustments in respect of changes in tax rates (4,404) -
-------------------------------------------------------------- ------------ ------------
Adjustments in respect of deferred income tax of previous
years (2,304) 14,469
-------------------------------------------------------------- ------------ ------------
Deferred overseas income tax
-------------------------------------------------------------- ------------ ------------
Relating to origination and reversal of temporary differences 612 (5,840)
-------------------------------------------------------------- ------------ ------------
Adjustments in respect of deferred income tax of previous
years 450 (135)
-------------------------------------------------------------- ------------ ------------
Total deferred income tax (67,525) (193,679)
-------------------------------------------------------------- ------------ ------------
Income tax (credit)/expense reported in profit or loss (33,293) (182,943)
-------------------------------------------------------------- ------------ ------------
(b) Reconciliation of total income tax charge
A reconciliation between the income tax charge and the product
of accounting profit multiplied by the UK statutory tax rate is as
follows:
Year ended Year ended
31 December 31 December
2018 2017
$'000 $'000
---------------------------------------------------------- ------------ ------------
Profit/(loss) before tax 93,985 (243,773)
---------------------------------------------------------- ------------ ------------
Statutory rate of corporation tax in the UK of 40% (2017:
40%) 37,594 (97,509)
---------------------------------------------------------- ------------ ------------
Supplementary corporation tax non-deductible expenditure 20,284 21,170
---------------------------------------------------------- ------------ ------------
Non-deductible expenditure/income(i) (21,689) (7,673)
---------------------------------------------------------- ------------ ------------
Petroleum revenue tax (net of income tax benefit) - 3,703
---------------------------------------------------------- ------------ ------------
North Sea tax reliefs (64,228) (93,234)
---------------------------------------------------------- ------------ ------------
Tax in respect of non-ring fence trade 691 (9,085)
---------------------------------------------------------- ------------ ------------
Tax losses not recognised 1,509 (11,230)
---------------------------------------------------------- ------------ ------------
Deferred tax rate changes (4,404) -
---------------------------------------------------------- ------------ ------------
Adjustments in respect of prior years (1,434) 13,665
---------------------------------------------------------- ------------ ------------
Overseas tax rate differences (673) (4,163)
---------------------------------------------------------- ------------ ------------
Share-based payments 899 1,475
---------------------------------------------------------- ------------ ------------
Other differences (1,842) (62)
---------------------------------------------------------- ------------ ------------
At the effective income tax rate of 17% (2017: 75%) (33,293) (182,943)
---------------------------------------------------------- ------------ ------------
(i) The 2018 credit is mainly due to the non-taxable income in
relation to the goodwill and non-taxable fair value movements on
the acquisition of the 75% interest in the Magnus oil field, this
is netted against the non-tax deductible depreciation on fixed
assets
(c) Deferred income tax
Deferred income tax relates to the following:
(Credit)/charge
for the year
Group balance recognised in
sheet profit or loss
------------------------ --------------------
2018 2017 2018 2017
$'000 $'000 $'000 $'000
------------------------------------------- ----------- ----------- --------- ---------
Deferred tax liability
------------------------------------------- ----------- ----------- --------- ---------
Accelerated capital allowances 1,400,956 1,163,562 93,196 28,290
------------------------------------------- ----------- ----------- --------- ---------
Other temporary differences - - - -
------------------------------------------- ----------- ----------- --------- ---------
1,400,956 1,163,562
------------------------------------------- ----------- ----------- --------- ---------
Deferred tax asset
------------------------------------------- ----------- ----------- --------- ---------
Losses (1,212,998) (1,228,034) 15,046 (167,998)
------------------------------------------- ----------- ----------- --------- ---------
Decommissioning liability (267,954) (254,008) (13,946) (68,590)
------------------------------------------- ----------- ----------- --------- ---------
Other temporary differences (178,920) (17,098) (161,821) 14,619
------------------------------------------- ----------- ----------- --------- ---------
(1,659,862) (1,499,140)
------------------------------------------- ----------- ----------- --------- ---------
Deferred tax expense (67,525) (193,679)
------------------------------------------- ----------- ----------- --------- ---------
Net deferred tax (assets)/liabilities (258,906) (335,578)
------------------------------------------- ----------- ----------- --------- ---------
Reflected in the balance sheet as follows:
------------------------------------------- ----------- ----------- --------- ---------
Deferred tax assets (286,721) (398,263)
------------------------------------------- ----------- ----------- --------- ---------
Deferred tax liabilities 27,815 62,685
------------------------------------------- ----------- ----------- --------- ---------
Net deferred tax (assets)/liabilities (258,906) (335,578)
------------------------------------------- ----------- ----------- --------- ---------
Reconciliation of net deferred tax assets/(liabilities)
2018 2017
$'000 $'000
----------------------------------------------------- --------- --------
At 1 January 335,578 191,715
----------------------------------------------------- --------- --------
Tax income/(expense) during the period recognised in
profit or loss 67,525 193,679
----------------------------------------------------- --------- --------
Tax income/(expense) during the period recognised in - -
other comprehensive income
----------------------------------------------------- --------- --------
Deferred taxes acquired (see note 29) (144,197) (49,816)
----------------------------------------------------- --------- --------
At 31 December 258,906 335,578
----------------------------------------------------- --------- --------
(d) Tax losses
The Group's deferred tax assets at 31 December 2018 are
recognised to the extent that taxable profits are expected to arise
in the future against which tax losses and allowances in the UK can
be utilised. In accordance with IAS 12 Income Taxes, the Group
assessed the recoverability of its deferred tax assets at 31
December 2018 with respect to ring fence tax losses and
allowances.
The Group has unused UK mainstream corporation tax losses of
$287.5 million (2017: $290.2 million) for which no deferred tax
asset has been recognised at the balance sheet date due to
uncertainty of recovery of these losses. In addition the group has
not recognised a deferred tax asset for the adjustment to bond
valuations on the adoption of IFRS 9 (see note 2). The benefit of
this deduction is taken over 10 years with a deduction of $3.8
million being taken in the current period with the remaining
benefit of $34.4 million remaining unrecognised.
The Group has unused Malaysian income tax losses of $9.4 million
(2017: $5.2 million) arising in respect of the Tanjong Baram RSC
for which no deferred tax asset has been recognised at the balance
sheet date due to uncertainty of recovery of these losses.
No deferred tax has been provided on unremitted earnings of
overseas subsidiaries, Finance Act 2009 exempted foreign dividends
from the scope of UK corporation tax where certain conditions are
satisfied.
(e) Change in legislation
Finance Act 2017 enacted legislation in relation to the
restriction of corporate interest deductions from 1 April 2017 and
the restriction of relief for mainstream corporate tax losses with
effect from 1 April 2017. While these changes do not impact North
Sea ring fence of relief for mainstream corporate tax losses with
effect from 1 April 2017, they have an impact on the current year
Group tax charge where North Sea ring fence losses are offset
against mainstream corporate tax profits which would otherwise be
exposed due to the operation of these new rules. The restriction
had no impact on the current year tax charge (2017: $15.1
million).
8. Earnings per share
The calculation of earnings per share is based on the profit
after tax and on the weighted average number of Ordinary shares in
issue during the period.
Following the completion of the rights issue in October 2018 the
earnings per share calculations, for all period up to the date the
rights issue shares were issued, have been adjusted for the bonus
element of the rights issue. The bonus factor used was 1.17.
Further information on the rights issue is included in note 17.
Basic and diluted earnings per share are calculated as
follows:
Weighted average
Profit/(loss) number of Ordinary Earnings per
after tax shares share
----------------- --------------------- ----------------
Year ended 31 Year ended 31 Year ended 31
December December December
----------------- --------------------- ----------------
2018 2017 2018 2017* 2018 2017*
$'000 $'000 million million $ $
---------------------------------- ------- -------- ---------- --------- ------- -------
Basic 127,278 (60,830) 1,226.2 1,319.8 0.104 (0.046)
---------------------------------- ------- -------- ---------- --------- ------- -------
Dilutive potential of Ordinary
shares granted under share-based
incentive schemes - - 37.8 53.0 (0.003) -
---------------------------------- ------- -------- ---------- --------- ------- -------
Diluted 127,278 (60,830) 1,264.0 1,372.9 0.101 (0.046)
---------------------------------- ------- -------- ---------- --------- ------- -------
Basic (excluding exceptional
items) 78,195 (33,554) 1,226.2 1,319.8 0.064 (0.025)
---------------------------------- ------- -------- ---------- --------- ------- -------
Diluted (excluding exceptional
items) 78,195 (33,554) 1,264.0 1,372.9 0.062 (0.025)
---------------------------------- ------- -------- ---------- --------- ------- -------
*Restated following rights issue
9. Dividends paid and proposed
The Company paid no dividends during the year ended 31 December
2018 (2017: none). At 31 December 2018, there are no proposed
dividends (2017: none).
10. Property, plant and equipment
Office
furniture,
Oil and fixtures
gas assets and fittings Total
$'000 $'000 $'000
--------------------------------------------------- ----------- ------------- ----------
Cost:
--------------------------------------------------- ----------- ------------- ----------
At 1 January 2017 6,787,343 54,722 6,842,065
--------------------------------------------------- ----------- ------------- ----------
Additions 320,627 2,994 323,621
--------------------------------------------------- ----------- ------------- ----------
Initial recognition of finance lease asset (see
note 24) 771,975 - 771,975
--------------------------------------------------- ----------- ------------- ----------
Acquired (see note 29) 124,542 - 124,542
--------------------------------------------------- ----------- ------------- ----------
Change in decommissioning provision 143,992 - 143,992
--------------------------------------------------- ----------- ------------- ----------
Change in cost recovery provision (see note 22) (77,785) - (77,785)
--------------------------------------------------- ----------- ------------- ----------
At 31 December 2017 8,070,694 57,716 8,128,410
--------------------------------------------------- ----------- ------------- ----------
Additions 178,627 2,856 181,483
--------------------------------------------------- ----------- ------------- ----------
Acquired (see note 29) 745,350 - 745,350
--------------------------------------------------- ----------- ------------- ----------
Acquired: Change in fair value on step acquisition
(see note 29) 123,909 - 123,909
--------------------------------------------------- ----------- ------------- ----------
Change in decommissioning provision (see note
12 and 22) 30,194 - 30,194
--------------------------------------------------- ----------- ------------- ----------
Change in cost recovery provision (see note 22) (7,947) - (7,947)
--------------------------------------------------- ----------- ------------- ----------
Change in financial carry liability (see note
20) (1,066) - (1,066)
--------------------------------------------------- ----------- ------------- ----------
Change in estimate (2,195) - (2,195)
--------------------------------------------------- ----------- ------------- ----------
At 31 December 2018 9,137,556 60,572 9,198,138
--------------------------------------------------- ----------- ------------- ----------
Accumulated depletion and impairment:
--------------------------------------------------- ----------- ------------- ----------
At 1 January 2017 3,846,028 32,591 3,878,619
--------------------------------------------------- ----------- ------------- ----------
Charge for the year 224,698 4,500 229,198
--------------------------------------------------- ----------- ------------- ----------
Impairment charge for the year 171,971 - 171,971
--------------------------------------------------- ----------- ------------- ----------
At 31 December 2017 4,242,697 37,091 4,279,788
--------------------------------------------------- ----------- ------------- ----------
Charge for the year 437,104 5,287 442,391
--------------------------------------------------- ----------- ------------- ----------
Impairment charge for the year 126,046 - 126,046
--------------------------------------------------- ----------- ------------- ----------
At 31 December 2018 4,805,847 42,378 4,848,225
--------------------------------------------------- ----------- ------------- ----------
Net carrying amount:
--------------------------------------------------- ----------- ------------- ----------
At 31 December 2018 4,331,719 18,194 4,349,913
--------------------------------------------------- ----------- ------------- ----------
At 31 December 2017 3,827,997 20,625 3,848,622
--------------------------------------------------- ----------- ------------- ----------
At 1 January 2017 2,941,315 22,131 2,963,446
--------------------------------------------------- ----------- ------------- ----------
On 1 December 2018, the Group acquired the remaining 75%
interest in the Magnus oil field and associated interests (see note
29), resulting in an acquisition of assets at a value of $745.4
million allocated to property, plant and equipment.
The Group acquired the initial 25% interest in Magnus oil field
and associated interests in 2017 (see note 29), resulting in an
acquisition of assets at a value of $124.5 million allocated to
property, plant and equipment. As part of the step acquisition to
100% the initial interest of 25% was revalued, resulting in an
increase of $123.9 million.
During the year ended 31 December 2017, the Group's lease from
Armada Kraken PTE Limited ('BUMI') of the Floating Production,
Storage and Offloading vessel ('FPSO') for the Kraken field
commenced. The lease has been assessed as a finance lease, and a
$772.0 million lease liability and lease asset were recognised in
June 2017. The liability was calculated based on the present value
of the minimum lease payments at inception of the lease (see note
24).
Impairments to the Group's producing oil and gas assets and
reversals of impairments are set out in the table below:
Impairment (charge)/reversal Recoverable amount(iii)
------------------------------ -------------------------
Year ended Year ended 31 December 31 December
31 December 31 December 2018 2017
2018 2017 $'000 $'000
$'000 $'000
--------------------------------- -------------- -------------- ------------ -----------
North Sea(i) (125,009) (187,716) 158,890 301,731
--------------------------------- -------------- -------------- ------------ -----------
Malaysia(ii) (1,037) 15,745 41,488 48,301
--------------------------------- -------------- -------------- ------------ -----------
Net impairment reversal/(charge) (126,046) (171,971)
--------------------------------- -------------- -------------- ------------ -----------
(i) North Sea includes Thistle/Deveron and the Dons fields. The
impairments are attributable primarily to changes in field life
assumptions
(ii) The amounts disclosed for Malaysia relate to the Tanjong Baram field
(iii) Recoverable amount has been determined on a fair value
less costs of disposal basis (see note 11 for further details of
methodology and assumptions used, and note 2 Critical Accounting
Estimates and Judgements for information on significant estimates
and judgements made in relation to impairments). The amounts
disclosed above are in respect of assets where an impairment (or
reversal) has been recorded. Assets which did not have any
impairment or reversal are excluded from the amounts disclosed
The net book value at 31 December 2018 includes $95.4 million
(2017: $71.1 million) of pre-development assets and development
assets under construction which are not being depreciated.
The amount of borrowing costs capitalised during the year ended
31 December 2018 was $1.5 million and relates to the Dunlin Bypass
project (2017: $42.3 million relating to the Kraken development
project). The weighted average rate used to determine the amount of
borrowing costs eligible for capitalisation is 7.7% (2017:
7.0%).
The net book value of property, plant and equipment held under
finance leases and hire purchase contracts at 31 December 2018 was
$690.7 million (2017: $756.3 million).
11. Goodwill
A summary of goodwill is presented below:
2018 2017
$'000 $'000
----------------------------- ------- --------
Cost and net carrying amount
----------------------------- ------- --------
At 1 January 189,317 189,317
----------------------------- ------- --------
Acquisition (see note 29) 94,633 -
----------------------------- ------- --------
At 31 December 283,950 189,317
----------------------------- ------- --------
On 1 December 2018, the Group acquired the remaining 75%
interest in the Magnus oil field and associated interests. Goodwill
of $94.6 million was recognised, representing the future economic
benefits that EnQuest's expertise is expected to realise from the
assets (see note 29).
The historic goodwill balance arose from the acquisition of
Stratic and PEDL in 2010 and the Greater Kittiwake Area asset in
2014.
Goodwill acquired through business combinations has been
allocated to a single CGU, the UK Continental Shelf ('UKCS'), and
this is therefore the lowest level at which goodwill is
reviewed.
Impairment testing of oil and gas assets and goodwill
In accordance with IAS 36 Impairment of Assets, goodwill and oil
and gas assets have been reviewed for impairment at the year end.
In assessing whether goodwill and oil and gas assets have been
impaired, the carrying amount of the CGU for goodwill and at field
level for oil and gas assets is compared with their recoverable
amounts.
The recoverable amounts of the CGU and fields have been
determined on a fair value less costs to sell basis. Discounted
cash flow models comprising asset-by-asset life of field
projections using Level 3 inputs (based on IFRS 13 fair value
hierarchy) have been used to determine the recoverable amounts. The
cash flows have been modelled on a post-tax and
post-decommissioning basis at the Group's post-tax discount rate of
10.0% (2017: 10.0%). Risks specific to assets within the CGU are
reflected within the cash flow forecasts.
The goodwill on the acquisition of Magnus is assessed to be
fully recoverable as at 31 December 2018.
Key assumptions used in calculations
The key assumptions required for the calculation of the
recoverable amounts are:
-- Oil prices;
-- Currency exchange rates;
-- Production volumes;
-- Discount rates; and
-- Opex, capex and decommissioning costs.
Oil prices are based on an internal view of forward curve prices
for the first three years and thereafter at $75/bbl inflated at 2%
per annum from 2023.
Production volumes are based on life of field production
profiles for each asset within the CGU. The production volumes used
in the calculations were taken from the report prepared by the
Group's independent reserves auditor.
Operating expenditure, capital expenditure and decommissioning
costs are derived from the Group's Business Plan adjusted for
changes in timing based on the production model used for the
assessment of proven and probable ('2P') reserves.
The discount rate reflects management's estimate of the Group's
weighted average cost of capital ('WACC'). The WACC takes into
account both debt and equity. The cost of equity is derived from
the expected return on investment by the Group's investors. The
cost of debt is based on its interest-bearing borrowings. Segment
risk is incorporated by applying a beta factor based on publicly
available market data. The post-tax discount rate applied to the
Group's post-tax cash flow projections was 10.0% (2017: 10.0%).
Management considers this to be the best estimate of a market
participant's discount rate.
Sensitivity to changes in assumptions
The Group's recoverable value of assets is highly sensitive,
inter alia, to oil price achieved and production volumes. The
recoverable amount of the CGU would be equal to the carrying amount
of goodwill if either the oil price or production volumes (on a
CGU-weighted average basis) were to fall by 5% (2017: 7%) from the
prices outlined above and volumes disclosed in the Annual Report.
Goodwill would need to be fully impaired if the oil price or
production volumes (on a CGU-weighted average basis) were to fall
by 31% from the prices outlined above (2017: 16%). The above
sensitivities have flexed revenues and tax cash flows, but
operating costs and capital expenditures have been kept
constant.
12. Intangible oil and gas assets
Accumulated Net carrying
Cost impairment amount
$'000 $'000 $'000
---------------------------------------------- -------- ----------- ------------
At 1 January 2017 229,524 (179,192) 50,332
---------------------------------------------- -------- ----------- ------------
Additions 1,076 - 1,076
---------------------------------------------- -------- ----------- ------------
Write off of relinquished licences previously
impaired (3,076) 3,076 -
---------------------------------------------- -------- ----------- ------------
Unsuccessful exploration expenditure written
off - 159 159
---------------------------------------------- -------- ----------- ------------
Change in decommissioning provision (see note
22) 502 - 502
---------------------------------------------- -------- ----------- ------------
Impairment charge for the year - 34 34
---------------------------------------------- -------- ----------- ------------
At 31 December 2017 228,026 (175,923) 52,103
---------------------------------------------- -------- ----------- ------------
Additions 1,393 - 1,393
---------------------------------------------- -------- ----------- ------------
Write off of relinquished licences previously
impaired (63,547) 63,547 -
---------------------------------------------- -------- ----------- ------------
Unsuccessful exploration expenditure written
off - (1,009) (1,009)
---------------------------------------------- -------- ----------- ------------
Change in decommissioning provision (see note
22) (286) - (286)
---------------------------------------------- -------- ----------- ------------
Impairment charge for the year - (398) (398)
---------------------------------------------- -------- ----------- ------------
At 31 December 2018 165,586 (113,783) 51,803
---------------------------------------------- -------- ----------- ------------
During the year ended 31 December 2018, the Group relinquished
licences previously impaired resulting in write off of $63.5
million. During 2018, the Group developed the Eagle prospect (2017:
Kraken field) resulting in the additions to intangibles.
13. Investments
$'000
--------------------------------------------------------- --------
Cost:
--------------------------------------------------------- --------
At 1 January 2017, 31 December 2017 and 31 December 2018 19,231
--------------------------------------------------------- --------
Provision for impairment:
--------------------------------------------------------- --------
At 1 January 2017 (19,060)
--------------------------------------------------------- --------
Impairment reversal/(charge) for the year (19)
--------------------------------------------------------- --------
At 31 December 2017 (19,079)
--------------------------------------------------------- --------
Impairment (charge)/reversal for the year (121)
--------------------------------------------------------- --------
At 31 December 2018 (19,200)
--------------------------------------------------------- --------
Net carrying amount:
--------------------------------------------------------- --------
At 31 December 2018 31
--------------------------------------------------------- --------
At 31 December 2017 152
--------------------------------------------------------- --------
At 1 January 2017 171
--------------------------------------------------------- --------
The accounting valuation of the Group's shareholding (based on
the quoted share price of Ascent) resulted in a non-cash impairment
charge of $0.1 million in the year to 31 December 2018 (2017: $0.02
million).
14. Inventories
2018 2017
$'000 $'000
-------------- ------- -------
Crude oil 23,183 12,422
-------------- ------- -------
Well supplies 77,349 65,623
-------------- ------- -------
100,532 78,045
-------------- ------- -------
During 2018, inventories of $5.8 million (2017: $2.9 million)
were recognised within cost of sales in the statement of
comprehensive income. Included within this balance is $5.8 million
as a result of the write down of inventories to net realisable
value (2017: $2.7 million). The write downs are included in cost of
sales.
15. Trade and other receivables
2018 2017
$'000 $'000
------------------------------- ------- --------
Current
------------------------------- ------- --------
Trade receivables 69,857 80,743
------------------------------- ------- --------
Joint venture receivables 84,745 87,037
------------------------------- ------- --------
Under-lift position 81,173 32,299
------------------------------- ------- --------
VAT receivable - 11,739
------------------------------- ------- --------
Other receivables 14,741 1,844
------------------------------- ------- --------
250,516 213,662
------------------------------- ------- --------
Prepayments and accrued income 25,293 14,092
------------------------------- ------- --------
275,809 227,754
------------------------------- ------- --------
Trade receivables are non-interest-bearing and are generally on
15 to 30 day terms. Trade receivables are reported net of any
provisions for impairment. As at 31 December 2018, no impairment
provision for trade receivables was necessary (2017: $nil).
Joint venture receivables relate to amounts billable to, or
recoverable from, joint venture partners and were not impaired.
Under-lift is valued at market prices prevailing at the balance
sheet date. As at 31 December 2018, no other receivables were
determined to be impaired (2017: none).
The carrying value of the Group's trade, joint venture and other
receivables as stated above is considered to be a reasonable
approximation to their fair value largely due to their short-term
maturities.
As per the application of IFRS 9, an impairment analysis is
performed at each reporting date using a provision matrix to
measure expected credit losses. The provision rates are based on
days past due for groupings of customer segments with similar loss
patterns (i.e. by geographical region, product type, customer type
and rating). The calculation reflects the probability-weighted
outcome, the time value of money and reasonable and supportable
information that is available at the reporting date about past
events, current conditions and forecasts of future economic
conditions. Generally, trade receivables are written off if past
due for more than one year and are not subject to enforcement
activity. The Group evaluates the concentration of risk with
respect to trade receivables and contract assets as low, as its
customers as joint venture partners and there are no indications of
change in risk.
16. Cash and cash equivalents
The carrying value of the Group's cash and cash equivalents is
considered to be a reasonable approximation to their fair value due
to their short-term maturities. Included within the cash balance at
31 December 2018 is restricted cash of $3.4 million (2017: $3.5
million). Of this, $2.8 million relates to cash held in escrow in
respect of the unwound acquisition of the Tunisian assets of PA
Resources (2017: $2.8 million) and the remainder relates to cash
collateral held to issue bank guarantees in Malaysia.
Cash and cash equivalents also include an amount of $3.4 million
(2017: $3.9 million) held in a Malaysian bank account which can
only be used to pay cash calls for the Tanjong Baram asset and
amounts related to the Tanjong Baram project finance loan.
At 31 December 2018, $6.6 million (2017: $7.0 million) was
placed on short-term deposit in order to cash collateralise the
Group's letter of credit.
17. Share capital and premium
The movement in the share capital and share premium of the
Company was as follows:
Ordinary
shares of
GBP0.05 Share Share
each capital premium Total
Authorised, issued and fully paid Number $'000 $'000 $'000
----------------------------------- ------------- -------- -------- -------
At 1 January 2018 1,186,084,304 85,105 125,297 210,402
----------------------------------- ------------- -------- -------- -------
Issuance of equity shares 508,321,844 33,077 105,849 138,926
----------------------------------- ------------- -------- -------- -------
Expenses on issue of equity shares - - (3,997) (3,997)
----------------------------------- ------------- -------- -------- -------
At 31 December 2018 1,694,406,148 118,182 227,149 345,331
----------------------------------- ------------- -------- -------- -------
The share capital comprises only one class of Ordinary share.
Each Ordinary share carries an equal voting right and right to a
dividend.
At 31 December 2018, there were 73,180,394 shares held by the
Employee Benefit Trust (2017: 56,023,671). On 22 October 2018,
22,126,481 shares were acquired by the Employee Benefit Trust
pursuant to the rights issue. The remainder of the movement in the
year is due to shares used to satisfy awards made under the
Company's share-based incentive schemes.
On 22 October 2018, the Company completed a rights issue,
pursuant to which 508,321,844 new Ordinary shares were issued at a
price of GBP0.21 per share, generating gross aggregate proceeds of
$138.9 million. 485,477,620 of the new shares issued resulted from
existing shareholders taking up their entitlement under the rights
issue to acquire three new Ordinary shares for every seven Ordinary
shares previously held. Following the admission to the market of an
additional 508,321,844 Ordinary shares on 22 October 2018, there
were 1,694,406,148 Ordinary shares in issue at the end of the
year.
18. Share-based payment plans
On 18 March 2010, the Directors of the Company approved three
share schemes for the benefit of Directors and employees, being a
Deferred Bonus Share Plan, a Restricted Share Plan and a
Performance Share Plan. A Sharesave Plan was approved in 2012.
The share-based payment expense recognised for each scheme was
as follows:
2018 2017
$'000 $'000
-------------------------------- ------ ------
Deferred Bonus Share Plan 649 1,069
-------------------------------- ------ ------
Restricted Share Plan 668 1,024
-------------------------------- ------ ------
Performance Share Plan 2,126 (68)
-------------------------------- ------ ------
Sharesave Plan 801 230
-------------------------------- ------ ------
Executive Director bonus awards 401 594
-------------------------------- ------ ------
4,645 2,849
-------------------------------- ------ ------
The fair value of awards is calculated at the 'market value',
being the average middle market quotation of a share for the three
immediately preceding dealing days as derived from the Daily
Official List of the London Stock Exchange, provided such dealing
days do not fall within any period when dealings in shares are
prohibited because of any dealing restriction. The fair values of
awards granted to employees during the year are based on the
'market value' on the date of grant, or date of invitation in
respect to the Sharesave Plan.
The following disclosure and tables shows the number of shares
potentially issuable under equity-settled employee share awards,
including the number of options outstanding and those options which
have vested and are exercisable at the end of each year. The awards
have been adjusted for the effect of the rights issue.
Deferred Bonus Share Plan ('DBSP')
Eligible employees are invited to participate in the DBSP
scheme. Participants may be invited to elect or, in some cases, be
required, to receive a proportion of any bonus in Ordinary shares
of EnQuest (invested awards). Following such award, EnQuest will
generally grant the participant an additional award over a number
of shares bearing a specified ratio to the number of his or her
invested shares (matching shares). The awards granted will vest 33%
on the first anniversary of the date of grant, a further 33% after
year two and the final 34% on the third anniversary of the date of
grant. Awards, both invested and matching, are forfeited if the
employee leaves the Group before the awards vest.
The fair values of DBSP awards granted to employees during the
year, based on the defined market value on the date of grant, are
set out below:
2018 2017
-------------------------------------- ---- ----
Weighted average fair value per share 36p 37p
-------------------------------------- ---- ----
The following shows the movement in the number of share awards
held under the DBSP scheme:
2018 2017
Number Number
--------------------------- ----------- -----------
Outstanding at 1 January 2,631,797 2,508,026
--------------------------- ----------- -----------
Granted during the year(i) 1,007,312 1,357,040
--------------------------- ----------- -----------
Vested during the year (1,407,040) (1,214,427)
--------------------------- ----------- -----------
Forfeited during the year (71,342) (18,842)
--------------------------- ----------- -----------
Outstanding at 31 December 2,160,727 2,631,797
--------------------------- ----------- -----------
Exercisable at 31 December - -
--------------------------- ----------- -----------
(i) On 22 October 2018, at its discretion, the Company increased
the number of shares receivable by participants in the DBSP by a
factor of 1.17 so that the value of their rights under outstanding
awards was not adversely affected by the rights issue. This
resulted in the grant of 316,128 additional shares. The fair value
of these awards is being expensed over the remaining vesting period
of the original awards to which they relate
The weighted average contractual life for the share awards
outstanding as at 31 December 2018 was 0.9 years (2017: 0.9
years).
Restricted Share Plan ('RSP')
Under the RSP scheme, employees are granted shares in EnQuest
over a discretionary vesting period at the discretion of the
Remuneration Committee of the Board of Directors of EnQuest, which
may or may not be subject to the satisfaction of performance
conditions. Awards made under the RSP will vest over periods
between one and four years. At present, there are no performance
conditions applying to this scheme nor is there currently any
intention to introduce them in the future.
The fair values of RSP awards granted to employees during the
year, based on the defined market value on the date of grant, are
set out below:
2018 2017
-------------------------------------- ---- ----
Weighted average fair value per share 32p 33p
-------------------------------------- ---- ----
The following table shows the movement in the number of share
awards held under the RSP scheme:
2018 2017
Number Number
--------------------------- ----------- ----------
Outstanding at 1 January 12,180,771 12,564,319
--------------------------- ----------- ----------
Granted during the year(i) 1,789,377 587,216
--------------------------- ----------- ----------
Vested during the year (240,515) (893,465)
--------------------------- ----------- ----------
Forfeited during the year (1,056,880) (77,299)
--------------------------- ----------- ----------
Outstanding at 31 December 12,672,753 12,180,771
--------------------------- ----------- ----------
Exercisable at 31 December 4,037,914 3,451,209
--------------------------- ----------- ----------
(i) On 22 October 2018, at its discretion, the Company increased
the number of shares receivable by participants in the RSP by a
factor of 1.17 so that the value of their rights under outstanding
awards was not adversely affected by the rights issue. This
resulted in the grant of 1,812,650 additional shares. The fair
value of these awards is being expensed over the remaining vesting
period of the original awards to which they relate
The weighted average contractual life for the share awards
outstanding as at 31 December 2018 was 5.0 years (2017: 4.8
years).
Performance Share Plan ('PSP')
Under the PSP, the shares vest subject to performance
conditions. The PSP share awards granted during the year had four
sets of performance conditions associated with them: 30% of the
award relates to Total Shareholder Return ('TSR') against a number
of comparator group oil and gas companies listed on the FTSE 350,
AIM Top 100 and Stockholm NASDAQ OMX; 30% relates to reduction in
net debt; 30% relates to production growth; and 10% relates to 2P
reserve additions over the three-year performance period. Awards
will vest on the third anniversary.
The fair values of PSP awards granted to employees during the
year, based on the defined market value on the date of grant and
which allow for the effect of the TSR condition which is a
market-based performance condition, are set out below:
2018 2017
-------------------------------------- ---- ----
Weighted average fair value per share 32p 33p
-------------------------------------- ---- ----
The following table shows the movement in the number of share
awards held under the PSP scheme:
2018 2017
Number Number
--------------------------- ------------ -----------
Outstanding at 1 January 70,181,724 61,023,323
--------------------------- ------------ -----------
Granted during the year(i) 27,186,417 16,302,086
--------------------------- ------------ -----------
Vested during the year (1,160,744) (2,412,846)
--------------------------- ------------ -----------
Forfeited during the year (14,070,898) (4,730,839)
--------------------------- ------------ -----------
Outstanding at 31 December 82,136,499 70,181,724
--------------------------- ------------ -----------
Exercisable at 31 December 3,540,460 2,816,844
--------------------------- ------------ -----------
(i) On 22 October 2018, at its discretion, the Company increased
the number of shares receivable by participants in the PSP by a
factor of 1.17 so that the value of their rights under outstanding
awards was not adversely affected by the rights issue. This
resulted in the grant of 11,318,326 additional shares. The fair
value of these awards is being expensed over the remaining vesting
period of the original awards to which they relate
The weighted average contractual life for the share awards
outstanding as at 31 December 2018 was 4.0 years (2017: 4.0
years).
Sharesave Plan
The Group operates an approved savings related share option
scheme. The plan is based on eligible employees being granted
options and their agreement to opening a Sharesave account with a
nominated savings carrier and to save over a specified period,
either three or five years. The right to exercise the option is at
the employee's discretion at the end of the period previously
chosen, for a period of six months.
The fair values of Sharesave awards granted to employees during
the year, based on the defined market value on the date the
invitation for the scheme opens, are shown below:
2018 2017
-------------------------------------- ---- ----
Weighted average fair value per share 26p 8p
-------------------------------------- ---- ----
The following shows the movement in the number of share options
held under the Sharesave Plan:
2018 2017
Number Number
--------------------------- ----------- -----------
Outstanding at 1 January 12,834,269 12,657,432
--------------------------- ----------- -----------
Granted during the year(i) 26,069,708 1,299,185
--------------------------- ----------- -----------
Vested during the year (1,614,746) (17,213)
--------------------------- ----------- -----------
Forfeited during the year (1,541,554) (1,105,135)
--------------------------- ----------- -----------
Outstanding at 31 December 35,747,677 12,834,269
--------------------------- ----------- -----------
Exercisable at 31 December - -
--------------------------- ----------- -----------
(i) On 22 October 2018, at its discretion, the Company increased
the number of options receivable by participants in the Sharesave
Plan by a factor of 1.17 so that the value of their rights under
outstanding awards was not adversely affected by the rights issue.
This resulted in the grant of 5,235,954 additional shares. The
exercise price of outstanding options was also reduced by
multiplying by a factor 0.8546. The incremental fair value of these
adjustments is being expensed over the remaining vesting period of
the options to which they relate
The weighted average contractual life for the share options
outstanding as at 31 December 2018 was 2.6 years (2017: 1.7
years).
Executive Director bonus awards
As detailed in the Directors' Remuneration Report, the
remuneration of the Executive Directors includes the participation
in an annual bonus plan. Any bonus amount in excess of 100% of
salary will be deferred into EnQuest shares for two years, subject
to continued employment.
The fair value of the Executive Director bonus awards granted
during the year, based on the defined market value on the date of
grant, are set out below:
2018 2017
-------------------------------------- ---- ----
Weighted average fair value per share 39p 39p
-------------------------------------- ---- ----
The following table shows the movement in the number of share
awards held under the Executive Director bonus plan:
2018 2017
Number Number
--------------------------- ----------- ---------
Outstanding at 1 January 2,445,722 2,869,393
--------------------------- ----------- ---------
Granted during the year(i) 714,064 779,846
--------------------------- ----------- ---------
Cash settled in the year - (726,505)
--------------------------- ----------- ---------
Vested during the year (1,949,074) (477,012)
--------------------------- ----------- ---------
Outstanding at 31 December 1,210,712 2,445,722
--------------------------- ----------- ---------
Exercisable at 31 December 1,949,074 -
--------------------------- ----------- ---------
(i) On 22 October 2018, at its discretion, the Company increased
the number of shares receivable by participants in the PSP by a
factor of 1.17 so that the value of their rights under outstanding
awards was not adversely affected by the rights issue. This
resulted in the grant of 459,112 additional shares. The fair value
of these awards is being expensed over the remaining vesting period
of the original awards to which they relate
The weighted average contractual life for the share awards
outstanding as at 31 December 2018 was 0.6 years (2017: 0.6
years).
19. Loans and borrowings
The Group's loans are carried at amortised cost as follows:
2018 2017
----------------------------- -----------------------------
Principal Fees Total Principal Fees Total
$'000 $'000 $'000 $'000 $'000 $'000
-------------------------------- --------- ------- --------- ---------- ------ ---------
Credit facility 799,444 - 799,444 1,099,966 - 1,099,966
-------------------------------- --------- ------- --------- ---------- ------ ---------
Oz Management facility 178,524 (3,325) 175,199 - - -
-------------------------------- --------- ------- --------- ---------- ------ ---------
Crude oil prepayment 22,222 (111) 22,111 75,556 (378) 75,178
-------------------------------- --------- ------- --------- ---------- ------ ---------
SVT working capital facility 15,747 - 15,747 25,622 - 25,622
-------------------------------- --------- ------- --------- ---------- ------ ---------
Tanjong Baram project financing
facility 31,730 - 31,730 8,531 (292) 8,239
-------------------------------- --------- ------- --------- ---------- ------ ---------
Trade creditor loan 2,500 - 2,500 10,000 - 10,000
-------------------------------- --------- ------- --------- ---------- ------ ---------
Total loans 1,050,167 (3,436) 1,046,731 1,219,675 (670) 1,219,005
-------------------------------- --------- ------- --------- ---------- ------ ---------
Due within one year 311,261 330,012
-------------------------------- --------- ------- --------- ---------- ------ ---------
Due after more than one year 735,470 888,993
-------------------------------- --------- ------- --------- ---------- ------ ---------
Total loans 1,046,731 1,219,005
-------------------------------- --------- ------- --------- ---------- ------ ---------
Credit facility
In October 2013, the Group entered into a six-year $1.7 billion
multi-currency revolving credit facility (the 'RCF'), comprising of
a committed amount of $1.2 billion (subject to the level of
reserves) with a further $500 million available through an
accordion structure. Interest on the RCF was payable at LIBOR plus
a margin of 2.50% to 4.25%, dependent on specified covenant
ratios.
On 21 November 2016, pursuant to restructuring, the Group
entered into an amended and restated credit agreement, which
included the following terms:
-- Commitments split into a term facility of $1.125 billion and
a revolving facility of $75 million (together the 'credit
facility');
-- Maturity date extended to October 2021;
-- Amortisation profile amended, with 1 April 2018 the first scheduled amortisation date;
-- Borrowings subject to mandatory repayment out of excess cash
flow (excluding amounts required for approved capital expenditure),
assessed on a six-monthly basis;
-- Borrowings up to $890.7 million subject to interest at LIBOR
plus a margin of 4.75%, paid in cash;
-- Borrowings in excess of $890.7 million subject to interest at
LIBOR plus a margin of 5.25%, paid in cash, with a further 3.75%
interest accrued and added to the Payment In Kind ('PIK') amount at
maturity of each loan's maturity period;
-- PIK amount repayable at maturity and subject to 9.0%
interest, which is capitalised and added to the PIK amount on each
30 June and 31 December;
-- Accordion feature cancelled; and
-- $12 million waiver fee payable to lenders on 31 March 2018.
The Group concluded that the above amendments to the RCF are a
substantial modification, resulting in the previous loan carrying
amount of $1,002.3 million ($1,017.3 million principal less
unamortised issuance costs of $15.0 million) being derecognised and
a new loan of $1,017.3 million being recognised at fair value. The
difference of $15.0 million, which equated to the unamortised fees
of the previous loan, was recognised as loss on extinguishment. The
$12.0 million waiver fee along with $11.1 million of advisors' fees
were directly attributable to the modification of the RCF and were
also expensed as part of the loss on extinguishment.
During November 2017, the Group agreed additional amendments to
its term loan and revolving credit facility. These changes include
the deferral of the scheduled $140 million reduction in the term
loan facility from 1 April 2018 to 1 October 2018.
At 31 December 2018, the carrying amount of the credit facility
on the balance sheet was $799.4 million, comprising the loan
principal drawn down of $785.0 million, plus $14.4 million of
interest capitalised to the PIK amount (2017: $1,100.0 million,
being loan principal drawn down of $1,095.2 million plus $4.8
million of interest capitalised to the PIK amount).
At 31 December 2018, after allowing for letter of credit
utilisation of $6.6 million, $68.4 million remained available for
drawdown under the credit facility (2017: $7.0 million and $97.8
million respectively).
Oz Management facility
On 24 September 2018, the Group entered into a $175.0 million
financing facility with Oz Management LP. The facility was drawn
down in full and is repayable in five years from initial
availability of the facility. Interest accrues at 6.3% annual
effective rate plus one-month USD LIBOR. The financing is
ring-fenced on a 15% interest in the Kraken oil field and will be
repaid out of the cash flows associated with the interest over a
maximum of five years. If second ranking security interest in
respect of the assets secured under the credit facility is obtained
within 6 months of the financial close of the Oz Management
facility, the interest rate shall decrease to 5.75% annual
effective rate plus one-month USD LIBOR.
Crude oil prepayment transaction
On 25 October 2017, the Group entered into an $80 million crude
oil prepayment with Mercuria Energy Trading SA.
Repayment is made in equal monthly instalments over 18 months,
through the delivery of an aggregate of approximately 1.8 mmbbls of
oil. EnQuest will receive the average Brent price over each month
subject to a floor of $45/bbl and a cap of approximately $64/bbl.
Interest on the prepayment is payable at one-month USD LIBOR plus a
margin of 7.0%. The prepayment transaction is being undertaken on
an unsecured basis.
At 31 December 2018, the carrying amount of the prepayment on
the balance sheet was $22.2 million (2017: $75.6 million).
SVT working capital facility
On 1 December 2017, EnQuest NNS Limited entered into a GBP42
million revolving loan facility with a joint operator partner to
fund the short-term working capital cash requirements on the
acquisition of SVT and other interests (see note 29). The facility
is able to be drawn down against in instalments and accrues
interest at 1.0% per annum plus GBP LIBOR. The facility is
repayable three years from the initial availability of the
facility.
Tanjong Baram project financing facility
On 25 October 2017, the Group entered into a $34.6 million
financing facility in Malaysia with Castleton Commodities Merchant
Asia Co. Pte Ltd. The facility is repayable within five years from
the drawdown date on 28 February 2018 or on termination of the Risk
Services Contract, and is secured against the Tanjong Baram asset.
Interest is payable at USD LIBOR plus a margin of 8% per annum.
Trade creditor loan
In October 2016, the Group borrowed $40 million under a loan
facility with a trade creditor to fund the settlement of deferred
amounts for the Kraken project. The loan will be paid in full in
2019.
Bonds
The Group's bonds are carried at amortised cost as follows:
2018 2017
--------------------------- ----------------------------
Principal Fees Total Principal Fees Total
$'000 $'000 $'000 $'000 $'000 $'000
--------------------------- --------- ------- ------- --------- -------- -------
High yield bond 760,553 (6,475) 754,078 720,827 (8,467) 712,360
--------------------------- --------- ------- ------- --------- -------- -------
Retail bond 237,778 (1,574) 236,204 224,048 (2,057) 221,991
--------------------------- --------- ------- ------- --------- -------- -------
Total bonds due after more
than one year 998,331 (8,049) 990,282 944,875 (10,524) 934,351
--------------------------- --------- ------- ------- --------- -------- -------
High yield bond
In April 2014, the Group issued a $650 million high yield bond
with an originally scheduled maturity of 15 April 2022 and paying a
7.0% coupon semi-annually in April and October.
On 21 November 2016, the high yield bond was amended pursuant to
a scheme of arrangement whereby all existing notes were exchanged
for new notes. The new high yield notes continue to accrue a fixed
coupon of 7.0% payable semi-annually in arrears. The interest will
only be payable in cash if the 'Cash Payment Condition' is
satisfied, being the average of the Daily Brent Oil Prices during
the period of six calendar months immediately preceding the 'Cash
Payment Condition Determination Date' is equal to or above $65/bbl.
The 'Cash Payment Condition Determination Date' is the date falling
one calendar month prior to the relevant interest payment date. If
the 'Cash Payment Condition' is not satisfied, interest will not be
paid in cash but instead will be capitalised and satisfied through
the issue of additional high yield notes ('Additional HY Notes').
$27.5 million of accrued, unpaid interest as at the restructuring
date was capitalised and added to the principal amount of the new
high yield notes issued pursuant to the scheme. The maturity of the
new high yield notes was extended to 15 April 2022 and the Company
has the option to extend the maturity date of the new high yield
notes to 15 April 2023. Further, the maturity date of the new high
yield notes will be automatically extended to 15 October 2023 if
the credit facility is not repaid or refinanced in full prior to 15
October 2020.
At the end of 2016, the modification was not considered to be
significant under IAS 39. As a result, the change in contractual
cash flows on the bonds were amortised over the new life of the
bonds, rather than taken straight to profit or loss. Under IFRS 9,
the refinancing is a modification of the debt in which the
difference in contractual cash flows should be taken straight to
profit or loss. The cash flows were reassessed and, on 1 January
2018 on the adoption of IFRS 9, an adjustment for $15.4 million was
taken through opening reserves and through the amortised value of
the bond. In accordance with the transitional provisions in IFRS 9,
comparative figures have not been restated.
The fair value of the high yield bond was estimated to be $534.4
million (2017: $519.9 million). The price quoted for the retail
bond was used to estimate the fair value of the high yield bond on
the basis that, since the restructuring, both bonds carry similar
rights.
Retail bond
In 2013, the Group issued a GBP155 million retail bond with an
originally scheduled maturity of 15 February 2022 and paying a 5.5%
coupon semi-annually in February and August. For the interest
period commencing 15 August 2016, in accordance with the terms of
the bond, the rate of interest increased to 7.0% following the
determination of the Company's leverage ratio at 31 December
2015.
On 21 November 2016, the retail bond was amended pursuant to a
scheme of arrangement whereby all existing notes were exchanged for
new notes. The new retail notes continue to accrue a fixed coupon
of 7.0% payable semi-annually in arrears. The interest will only be
payable in cash if the 'Cash Payment Condition' is satisfied, being
the average of the Daily Brent Oil Prices during the period of six
calendar months immediately preceding the 'Cash Payment Condition
Determination Date' is equal to or above $65/bbl. The 'Cash Payment
Condition Determination Date' is the date falling one calendar
month prior to the relevant interest payment date. If the 'Cash
Payment Condition' is not satisfied, interest will not be paid in
cash but instead will be capitalised and satisfied through the
issue of additional retail notes ('Additional Retail Notes'). The
maturity of the new retail notes was extended to 15 April 2022 and
the Company has the option to extend the maturity date to 15 April
2023. Further, the maturity date of the new retail notes will be
automatically extended to 15 October 2023 if the credit facility is
not repaid or refinanced in full prior to 15 October 2020.
At the end of 2016, the modification was not considered to be
significant under IAS 39. As a result, the change in contractual
cash flows on the bonds were amortised over the new life of the
bonds, rather than taken straight to profit or loss. Under IFRS 9,
the refinancing is a modification of the debt in which the
difference in contractual cash flows should be taken straight to
profit or loss. The cash flows were reassessed and, on 1 January
2018 on the adoption of IFRS 9, an adjustment for $22.7 million was
taken through opening reserves and through the amortised value of
the bond. In accordance with the transitional provisions in IFRS 9,
comparative figures have not been restated.
The bond had a fair value of $156.8 million (2017: $161.6
million). The fair value of the retail bond has been determined by
reference to the price available from the market on which the bond
is traded.
20. Other financial assets and financial liabilities
(a) Summary
2018 2017
------------------- -------------------
Assets Liabilities Assets Liabilities
$'000 $'000 $'000 $'000
-------------------------------------------- ------ ----------- ------ -----------
Financial liabilities at fair value through
profit or loss:
-------------------------------------------- ------ ----------- ------ -----------
Commodity contracts 54,733 142 - 41,996
-------------------------------------------- ------ ----------- ------ -----------
Foreign exchange contracts 248 - - -
-------------------------------------------- ------ ----------- ------ -----------
Carbon contracts 2,077 - - -
-------------------------------------------- ------ ----------- ------ -----------
Financial liabilities at amortised cost:
-------------------------------------------- ------ ----------- ------ -----------
Other liabilities - - - 19,211
-------------------------------------------- ------ ----------- ------ -----------
Financial assets at fair value through
OCI:
-------------------------------------------- ------ ----------- ------ -----------
Interest rate swap designated as cash
flow hedge - - 36 -
-------------------------------------------- ------ ----------- ------ -----------
Financial assets at amortised cost:
-------------------------------------------- ------ ----------- ------ -----------
Other receivables 9,517 - 61,701 -
-------------------------------------------- ------ ----------- ------ -----------
Total current 66,575 142 61,737 61,207
-------------------------------------------- ------ ----------- ------ -----------
Financial liabilities at amortised cost:
-------------------------------------------- ------ ----------- ------ -----------
Other liabilities - - - 7,121
-------------------------------------------- ------ ----------- ------ -----------
Financial assets at amortised cost:
-------------------------------------------- ------ ----------- ------ -----------
Other receivables 5,958 - 8,191 -
-------------------------------------------- ------ ----------- ------ -----------
Total non-current 5,958 - 8,191 7,121
-------------------------------------------- ------ ----------- ------ -----------
(b) Oil commodity contracts
The Group uses put and call options and swap contracts to manage
its exposure to the oil price.
Commodity derivative contracts are designated as at FVPL, and
gains and losses on these contracts are recognised as a component
of revenue. These contracts typically include bought and sold call
options, bought put options and commodity swap contracts.
For the year ended 31 December 2018, gains totalling $4.4
million (2017: losses of $28.3 million) were recognised in respect
of commodity contracts designated as FVPL. This included losses
totalling $93.0 million (2017: losses of $20.6 million) realised on
contracts that matured during the year, and mark-to-market
unrealised gains totalling $97.4 million (2017: losses of $7.7
million). Of the realised amounts recognised during the year, a
loss of $17.2 million (2017: loss of $10.4 million) was realised in
'Business performance' revenue in respect of the amortisation of
premium income received on sale of these options. The premiums
received are amortised into 'Business performance' revenue over the
life of the option.
In October 2017, the Group entered into an 18-month collar
structure for $80 million (see note 19). The collar includes 18
separate call options and 18 separate put options, subject to a
floor of $45/bbl and a cap of approximately $64/bbl. Included in
the total gains for the year ended 31 December 2018, a loss of $8.0
million was recognised in 'Business performance' revenue (2017:
loss of $5.2 million).
The mark-to-market of the Group's open contracts as at 31
December 2018 was an asset of $54.7 million (2017: liability of
$42.0 million). The position includes a loss of $0.1 million in
respect of fixed price swap contracts for 200,000 barrels of 2019
production at a weighted average price of $54.6/bbl (2017: loss of
$29.2 million in respect of fixed price swap contracts for
4,150,000 barrels of 2018 production at a weighted average price of
$59.1/bbl).
(c) Foreign currency contracts
The Group enters into a variety of foreign currency contracts,
including Sterling, Euros, Swedish Krona, Norwegian Krone and
United Arab Emirates Dirhams. During the year ended 31 December
2018, losses totalling $0.4 million (2017: gain of $0.4 million)
were recognised in the income statement. This included losses
totalling $0.6 million (2017: $nil) realised on contracts maturing
in the year.
The mark-to-market of the Group's open contracts as at 31
December 2018 was $0.2 million (2017: $nil).
(d) Interest rate swap
During the year ended 31 December 2015, the Group entered an
interest rate swap which effectively swaps 50% of floating USD
LIBOR rate interest on the Group's Malaysian loan into a fixed rate
of 1.035% until 2018. The swap, which is effective from a hedge
accounting perspective, completed in the year with a loss of $0.4
million recognised within finance expenses on the income statement
(2017: gain of $0.02 million). The net asset fair value at 31
December 2017 was $0.04 million.
(e) Carbon commodity contracts
During the year the Group entered forward carbon commodity
contracts to manage its exposure to compliance with European
emissions regulations. The contracts are designated as at FVPL and
gains and losses on these contracts are recognised as a component
of cost of sales.
For the year ended 31 December 2018, unrealised gains of $2.1
million (2017: $nil) were recognised in respect of carbon commodity
contracts designated as FVPL. No contracts matured during the
year.
The mark-to-market of the Group's open contracts as at 31
December 2018 was $2.1 million (2017: $nil).
(f) Income statement impact
The income/(expense) recognised for commodity, currency and
interest rate derivatives are as follows:
Revenue and
other operating
income Cost of sales Finance costs
-------------------- -------------------- --------------------
Year ended 31 December 2018 Realised Unrealised Realised Unrealised Realised Unrealised
$'000 $'000 $'000 $'000 $'000 $'000
------------------------------- -------- ---------- -------- ---------- -------- ----------
Commodity options (29,309) 63,022 - - - -
------------------------------- -------- ---------- -------- ---------- -------- ----------
Commodity swaps (47,740) 29,016 - - - -
------------------------------- -------- ---------- -------- ---------- -------- ----------
Commodity futures (7,951) 84 - - - -
------------------------------- -------- ---------- -------- ---------- -------- ----------
Commodity collar on prepayment
transaction (8,035) 5,310 - - - -
------------------------------- -------- ---------- -------- ---------- -------- ----------
Foreign exchange contracts - - (615) 248 - -
------------------------------- -------- ---------- -------- ---------- -------- ----------
Carbon forwards - - - 2,062 - -
------------------------------- -------- ---------- -------- ---------- -------- ----------
Interest rate swap - - - - (353) -
------------------------------- -------- ---------- -------- ---------- -------- ----------
(93,035) 97,432 (615) 2,310 (353) -
------------------------------- -------- ---------- -------- ---------- -------- ----------
Revenue and
other operating
income Cost of sales Finance costs
-------------------- -------------------- --------------------
Year ended 31 December 2017 Realised Unrealised Realised Unrealised Realised Unrealised
$'000 $'000 $'000 $'000 $'000 $'000
--------------------------------- -------- ---------- -------- ---------- -------- ----------
Call options 880 (18,670) - - - -
--------------------------------- -------- ---------- -------- ---------- -------- ----------
Commodity swaps (23,754) 14,144 - - - -
--------------------------------- -------- ---------- -------- ---------- -------- ----------
Commodity futures (437) (363) - - - -
--------------------------------- -------- ---------- -------- ---------- -------- ----------
Purchase and sale of crude
oil 2,736 (2,827) - - - -
--------------------------------- -------- ---------- -------- ---------- -------- ----------
Foreign exchange swap contracts - - - 433 - -
--------------------------------- -------- ---------- -------- ---------- -------- ----------
Other forward currency contracts - - (4,848) 9,293 - -
--------------------------------- -------- ---------- -------- ---------- -------- ----------
Interest rate swap - - - - 15 (38)
--------------------------------- -------- ---------- -------- ---------- -------- ----------
(20,575) (7,716) (4,848) 9,726 15 (38)
--------------------------------- -------- ---------- -------- ---------- -------- ----------
(g) Other receivables and liabilities
Other receivables Other
$'000 liabilities
$'000
--------------------------------------- ----------------- ------------
At 1 January 2017 59,757 19,767
--------------------------------------- ----------------- ------------
Additions on acquisition 38,420 6,742
--------------------------------------- ----------------- ------------
Disposed during the year (3,561) -
--------------------------------------- ----------------- ------------
Change in fair value 627 (340)
--------------------------------------- ----------------- ------------
Utilised during the year (27,209) -
--------------------------------------- ----------------- ------------
Unwinding of discount 1,832 163
--------------------------------------- ----------------- ------------
Foreign exchange 26 -
--------------------------------------- ----------------- ------------
At 31 December 2017 69,892 26,332
--------------------------------------- ----------------- ------------
Exercised on acquisition (see note 29) (509,447) -
--------------------------------------- ----------------- ------------
Change in fair value 488,426 (7,283)
--------------------------------------- ----------------- ------------
Utilised during the year (66,194) (14,907)
--------------------------------------- ----------------- ------------
Unwinding of discount (1,081) 72
--------------------------------------- ----------------- ------------
Foreign exchange 980 -
--------------------------------------- ----------------- ------------
Classification update 32,899 (4,214)
--------------------------------------- ----------------- ------------
At 31 December 2018 15,475 -
--------------------------------------- ----------------- ------------
Current 9,517 -
--------------------------------------- ----------------- ------------
Non-current 5,958 -
--------------------------------------- ----------------- ------------
15,475 -
--------------------------------------- ----------------- ------------
Other receivables
2018 2017
Comprised of: $'000 $'000
------------------------------- ------ ------
BUMI receivable 15,475 24,407
------------------------------- ------ ------
Purchase option - 22,300
------------------------------- ------ ------
Thistle decommissioning option - 16,120
------------------------------- ------ ------
Kufpec receivable - 7,065
------------------------------- ------ ------
Total 15,475 69,892
------------------------------- ------ ------
In August 2016, EnQuest agreed with Armada Kraken PTE Ltd
('BUMI') that BUMI would refund $65 million (EnQuest's share being
$45.8 million) of a $100.0 million lease prepayment made in 2014
for the FPSO for the Kraken field. This refund is receivable from
2018 and onwards. Included within other receivables at 31 December
2018 is an amount of $15.5 million representing the discounted
value of EnQuest's share of these repayments (2017: $24.4 million).
A total of $9.1 million was collected during the period. Unwinding
of discount of $0.2 million (2017: $1.6 million) is included within
finance costs in the 12 months ended 31 December 2018.
As part of the Magnus and other interests' acquisition (see note
29), the Group had an option to acquire the remaining 75% of the
Magnus oil field and BP's interest in the associated
infrastructure. The option was exercised on 1 December 2018 and in
line with the accounting for step acquisitions the option was
remeasured at fair value resulting in a loss of $1.3 million which
was recognised through other income in 'Remeasurements and
exceptional items' in the statement of comprehensive income.
As part of the Magnus and other interests' acquisition, the
Group also entered into an option to undertake the decommissioning
of Thistle. At 31 December 2017, the receivable had a carrying
value of $16.1 million. The option was exercised in the year and a
total of $50 million was received with the corresponding liability
of $33.6 million recognised within provisions (see note 22).
As part of the 2012 farm-out to the Kuwait Foreign Petroleum
Exploration Company ('KUFPEC') of 35% of the Alma/Galia
development, KUFPEC agreed to pay EnQuest a total of $23.3 million
over a 36-month period after Alma/Galia is deemed to be fully
operational. During the year ended 31 December 2018, the
arrangement was completed and $7.1 million was received. At 31
December 2017, the receivable had a carrying value of $7.1
million.
Other liabilities
2018 2017
Comprised of: $'000 $'000
----------------------------------------------------- ------ ------
Accrued waiver fee - 12,000
----------------------------------------------------- ------ ------
Financial carry - 7,211
----------------------------------------------------- ------ ------
Decommissioning of Magnus and other interests option - 4,214
----------------------------------------------------- ------ ------
Other - 2,907
----------------------------------------------------- ------ ------
Total - 26,332
----------------------------------------------------- ------ ------
As part of the agreement to acquire an interest in the
PM8/Seligi assets in Malaysia, the Group agreed to carry Petronas
Carigali for its share of exploration or appraisal well
commitments. Well commitments were performed during the year and
the liability was released during the year. At 31 December 2017,
the liability had a carrying value of $7.2 million.
21. Fair value measurement
The following table provides the fair value measurement
hierarchy of the Group's assets and liabilities:
Quoted
prices Significant Significant
in active observable unobservable
markets inputs inputs
(Level (Level (Level
Total 1) 2) 3)
31 December 2018 $'000 $'000 $'000 $'000
------------------------------------------ --------- ---------- ----------- -------------
Financial assets measured at fair value:
------------------------------------------ --------- ---------- ----------- -------------
Derivative financial assets at FVPL
------------------------------------------ --------- ---------- ----------- -------------
Oil commodity derivative contracts(i) 54,733 - 54,733 -
------------------------------------------ --------- ---------- ----------- -------------
Foreign currency derivative contracts(ii) 248 - 248 -
------------------------------------------ --------- ---------- ----------- -------------
Carbon commodity derivative contracts(ii) 2,077 - 2,077 -
------------------------------------------ --------- ---------- ----------- -------------
Other financial assets at FVPL
------------------------------------------ --------- ---------- ----------- -------------
Quoted equity shares 31 31 - -
------------------------------------------ --------- ---------- ----------- -------------
Liabilities measured at fair value:
------------------------------------------ --------- ---------- ----------- -------------
Derivative financial liabilities at FVPL
------------------------------------------ --------- ---------- ----------- -------------
Oil commodity derivative contracts(i) 142 - 142 -
------------------------------------------ --------- ---------- ----------- -------------
Other financial liabilities measured at
FVPL
------------------------------------------ --------- ---------- ----------- -------------
Contingent consideration 660,436 - - 660,436
------------------------------------------ --------- ---------- ----------- -------------
Liabilities for which fair values are
disclosed
------------------------------------------ --------- ---------- ----------- -------------
Interest-bearing loans and borrowings 1,050,167 - - 1,050,167
------------------------------------------ --------- ---------- ----------- -------------
Obligations under finance leases 708,950 - - 708,950
------------------------------------------ --------- ---------- ----------- -------------
Retail bond 156,764 156,764 - -
------------------------------------------ --------- ---------- ----------- -------------
High yield bond 534,363 - 534,363 -
------------------------------------------ --------- ---------- ----------- -------------
Quoted
prices Significant Significant
in active observable unobservable
markets inputs inputs
(Level (Level (Level
Total 1) 2) 3)
31 December 2017 $'000 $'000 $'000 $'000
---------------------------------------------- --------- ---------- ----------- -------------
Financial assets measured at fair value:
---------------------------------------------- --------- ---------- ----------- -------------
Derivative financial asset at FVPL
---------------------------------------------- --------- ---------- ----------- -------------
Interest rate swap(ii) 36 - 36 -
---------------------------------------------- --------- ---------- ----------- -------------
Other financial assets at FVPL
---------------------------------------------- --------- ---------- ----------- -------------
Quoted equity shares 152 152 - -
---------------------------------------------- --------- ---------- ----------- -------------
Assets for which fair values are disclosed
---------------------------------------------- --------- ---------- ----------- -------------
Thistle decommissioning option 16,120 - - 16,120
---------------------------------------------- --------- ---------- ----------- -------------
Purchase option 22,300 - - 22,300
---------------------------------------------- --------- ---------- ----------- -------------
Liabilities measured at fair value:
---------------------------------------------- --------- ---------- ----------- -------------
Derivative financial liabilities at FVPL
---------------------------------------------- --------- ---------- ----------- -------------
Commodity derivative contracts(i) 41,996 - 41,996 -
---------------------------------------------- --------- ---------- ----------- -------------
Other financial liability at FVPL
---------------------------------------------- --------- ---------- ----------- -------------
Decommissioning of Magnus and other interests
option 4,214 - - 4,214
---------------------------------------------- --------- ---------- ----------- -------------
Contingent consideration 83,166 - - 83,166
---------------------------------------------- --------- ---------- ----------- -------------
Liabilities for which fair values are
disclosed
---------------------------------------------- --------- ---------- ----------- -------------
Interest-bearing loans and borrowings 1,219,675 - - 1,219,675
---------------------------------------------- --------- ---------- ----------- -------------
Obligations under finance leases 797,933 - - 797,933
---------------------------------------------- --------- ---------- ----------- -------------
Retail bond 161,595 161,595 - -
---------------------------------------------- --------- ---------- ----------- -------------
High yield bond 519,896 - 519,896 -
---------------------------------------------- --------- ---------- ----------- -------------
(i) Valued using readily available information in the public
markets and quotations provided by brokers and price index
developers
(ii) Valued by the counterparties, with the valuations reviewed
internally and corroborated with market data
Fair value hierarchy
All financial instruments for which fair value is recognised or
disclosed are categorised within the fair value hierarchy, based on
the lowest level input that is significant to the fair value
measurement as a whole, as follows:
Level 1: Quoted (unadjusted) market prices in active markets for
identical assets or liabilities;
Level 2: Valuation techniques for which the lowest level input
that is significant to the fair value measurement is directly or
indirectly observable;
Level 3: Valuation techniques for which the lowest level input
that is significant to the fair value measurement is
unobservable.
For assets and liabilities that are recognised at fair value on
a recurring basis, the Group determines whether transfers have
occurred between levels in the hierarchy by reassessing
categorisation (based on the lowest level input that is significant
to the fair value measurement as a whole) at the end of each
reporting period. There have been no transfers between Level 1 and
Level 2 during the period (2017: no transfers).
For recurring and non-recurring fair value measurements
categorised within Level 3 of the fair value hierarchy, the Group
uses the valuation processes to decide its valuation policies and
procedures and analyse changes in fair value measurements from
period to period. Level 3 financial instruments consist of
interest-bearing loans and borrowings (see note 19) and provisions
(see note 22), which are valued in accordance with the Group's
accounting policies.
22. Provisions
Surplus Other provisions
Decommissioning Carry Cost recovery Contingent lease $'000
provision provision provision consideration provision Total
$'000 $'000 $'000 $'000 $'000 $'000
--------------- --------------- --------- ------------------ ------------- --------- ---------------- ---------
At 1 January
2017 493,891 5,491 89,529 22,580 2,816 - 614,307
--------------- --------------- --------- ------------------ ------------- --------- ---------------- ---------
Additions
during the
year 63,613 - 10,329 3,131 - - 77,073
--------------- --------------- --------- ------------------ ------------- --------- ---------------- ---------
Acquisitions
(see note 29) - - - 66,623 - - 66,623
--------------- --------------- --------- ------------------ ------------- --------- ---------------- ---------
Changes in
estimates 80,881 - (77,785) (423) 194 - 2,867
--------------- --------------- --------- ------------------ ------------- --------- ---------------- ---------
Unwinding of
discount 11,471 - 1,838 255 17 - 13,581
--------------- --------------- --------- ------------------ ------------- --------- ---------------- ---------
Utilisation (10,605) (5,491) - (9,000) (394) - (25,490)
--------------- --------------- --------- ------------------ ------------- --------- ---------------- ---------
Foreign
exchange - - - - 253 - 253
--------------- --------------- --------- ------------------ ------------- --------- ---------------- ---------
At 31 December
2017 639,251 - 23,911 83,166 2,886 - 749,214
--------------- --------------- --------- ------------------ ------------- --------- ---------------- ---------
Additions
during the
year - - - - - 41,856 41,856
--------------- --------------- --------- ------------------ ------------- --------- ---------------- ---------
Acquisitions
(see note 29) - - - 625,296 - - 625,296
--------------- --------------- --------- ------------------ ------------- --------- ---------------- ---------
Changes in
estimates 29,908 - (7,947) 21,816 - 657 44,433
--------------- --------------- --------- ------------------ ------------- --------- ---------------- ---------
Unwinding of
discount 12,617 - 260 20 8 - 12,905
--------------- --------------- --------- ------------------ ------------- --------- ---------------- ---------
Utilisation (10,036) - (5,261) (69,862) (409) - (85,568)
--------------- --------------- --------- ------------------ ------------- --------- ---------------- ---------
Classification
update - - (5,068) - - 4,214 (854)
--------------- --------------- --------- ------------------ ------------- --------- ---------------- ---------
Foreign
exchange - - - - (141) - (141)
--------------- --------------- --------- ------------------ ------------- --------- ---------------- ---------
At 31 December
2018 671,740 - 5,895 660,436 2,344 46,727 1,387,142
--------------- --------------- --------- ------------------ ------------- --------- ---------------- ---------
Classified as:
--------------- --------------- --------- ------------------ ------------- --------- ---------------- ---------
Current 10,395 - - 69,680 388 587 81,050
--------------- --------------- --------- ------------------ ------------- --------- ---------------- ---------
Non-current 661,345 - 5,895 590,756 1,956 46,140 1,306,092
--------------- --------------- --------- ------------------ ------------- --------- ---------------- ---------
671,740 - 5,895 660,436 2,344 46,727 1,387,142
--------------- --------------- --------- ------------------ ------------- --------- ---------------- ---------
Decommissioning provision
The Group makes full provision for the future contractual costs
of decommissioning its production facilities and pipelines on a
discounted basis.
The Group's total provision represents the present value of
decommissioning costs which are expected to be incurred up to 2042
assuming no further development of the Group's assets. The
liability is discounted at a rate of 2.0% (2017: 2.0%). The
unwinding of the discount is classified as a finance cost (see note
6).
These provisions have been created based on internal and
third-party estimates. Assumptions based on the current economic
environment have been made which management believe are a
reasonable basis upon which to estimate the future liability. These
estimates are reviewed regularly to take into account any material
changes to the assumptions. However, actual decommissioning costs
will ultimately depend upon future market prices for the necessary
decommissioning works required, which will reflect market
conditions at the relevant time. Furthermore, the timing of
decommissioning liabilities is likely to depend on the dates when
the fields cease to be economically viable. This in turn depends on
future oil prices, which are inherently uncertain.
The Group enters into surety bonds principally to provide
security for its decommissioning obligations. The surety bond
facilities which expired in December 2018 were renewed for 12
months, subject to ongoing compliance with the terms of the Group's
borrowings. At 31 December 2018, the Group held surety bonds
totalling $123.2 million (2017: $129.6 million).
Carry provision
Consideration for the acquisition of 40% of the Kraken field
from Cairn (previously Nautical) and First Oil PLC in 2012 was
through development carries. The 'contingent' carry is dependent
upon a reserves determination which took place in Q2 2016. During
2017, $5.5 million of the carry had been paid, with no remaining
liability recognised on the balance sheet as at 31 December 2018
(2017: $nil).
Cost recovery provision
As part of the KUFPEC farm-in agreement, a cost recovery
protection mechanism was agreed with KUFPEC to enable KUFPEC to
recoup its investment to the date of first production. If, on 1
January 2017, KUFPEC's costs to first production had not been
recovered or deemed to have been recovered, EnQuest would pay
KUFPEC an additional 20% share of net revenue. This additional
revenue is to be paid until the capital costs to first production
have been recovered.
A provision has been made for the expected payments that the
Group will make to KUFPEC. The assumptions made in arriving at the
projected cash payments are consistent with the assumptions used in
the Group's 2018 year end impairment test, and the resulting cash
flows were included in the determination of the recoverable value
of the project. In establishing when KUFPEC has recovered its
capital cost to first oil, the farm-in agreement requires the use
of the higher of the actual oil price, or $90/bbl real, inflated at
2.0% per annum from 2012. These cash flows have been discounted at
a rate of 2.0% (2017: 2.0%).
During 2017, the Group entered into discussions with Petronas in
relation to the prior period PM8 cost recovery. During 2017, a
provision was made for the expected payments that the Group will
make as part of the settlement agreement. During the year ended 31
December 2018, $5.3 million was paid. At 31 December 2018, the
remaining balance to be paid was recognised within accruals for a
value of $5.1 million (2017: $10.3 million).
Contingent consideration
As part of the purchase agreement with the previous owner of the
GKA assets, a contingent consideration was agreed based on
Scolty/Crathes field development plan ('FDP') approval and 'first
oil'. EnQuest paid $3.0 million in November 2015, following FDP
approval in October 2015, and $9.0 million during 2017. During
2018, $8.0 million was paid with no remaining liability recognised
on the balance sheet as at 31 December 2018 (2017: $8.1 million).
Change in estimate of $0.1 million is included within finance costs
for the year ended 31 December 2018 (2017: $0.4 million).
In addition, there was potential consideration due subject to
future exploration success which, having been reassessed, are
deemed not to be probable. No remaining liability has been
recognised on the balance sheet as at 31 December 2018 (2017: $5.3
million). The reversal of provision is included within other income
for the year ended 31 December 2018.
On 1 December 2017, the acquisition of the initial 25% interest
in the Magnus oil field ('Magnus') and associated interests
(collectively the 'Transaction assets') was funded through a vendor
loan from BP (see note 29). The loan is repayable solely out of the
cash flows, which are achieved above operating cash flows from the
acquired assets and is secured over the interests in the
Transaction assets. The loan accrues interest at a rate of 5.0% per
annum on the base consideration. The fair value has been estimated
by calculating the present value of the future expected cash flows,
based on a discount rate of 10.0% (2017: 10.0%) and assumed
repayment of around three years. A total of $61.9 million was
repaid during 2018. Change in fair value of $9.7 million is
recognised within finance costs in the 12 months ended 31 December
2018. The provision of $33.9 million is expected to be paid during
2019, as disclosed within current provisions (2017: $69.8
million).
On 1 December 2018, the acquisition of the additional 75%
interest in the Magnus oil field and associated interests (see note
29) was part funded through a vendor loan and profit share
arrangement with BP, originally recognised at a discounted value of
$626.6 million The loan is repayable solely out of the cash flows
which are achieved above operating cash flows from Magnus and is
secured over the acquired assets. The loan accrues interest at a
rate of 7.5% per annum on the base consideration. The fair value
has been estimated by calculating the present value of the future
expected cash flows, based on a discount rate of 10.0% and assumed
repayment over the life of the field.
Surplus lease provision
In June 2015, the Group entered a 20-year lease in respect of
the Group's office building in Aberdeen, with part of the building
subsequently being sub-let with a rent-free incentive. A provision
has been recognised for the unavoidable costs in relation to the
sub-let space. The provision has been discounted using a 2.0%
discount rate (2017: 2.0%). At 31 December 2018, the provision was
$2.3 million (2017: $2.9 million).
Other provisions
As part of the Magnus and associated interests acquisition (see
note 29), EnQuest agreed to pay additional consideration in
relation to the management of the physical decommissioning costs of
Magnus. At 31 December 2018, the amount due to BP by reference to
7.5% of BP's decommissioning costs on Magnus on an after-tax basis
was $12.6 million (2017: $4.2 million).
The Thistle decommissioning option was exercised during the year
resulting in receipt of cash of $50 million. At 31 December 2018,
the amount due to BP by reference to 7.5% of BP's decommissioning
costs on Thistle and Deveron on an after-tax basis was $33.6
million (2017: $nil). Unwinding of discount of $0.7 million is
included within finance income for the year ended 31 December 2018
(2017: $nil).
23. Trade and other payables
2018 2017
$'000 $'000
------------------------ ------- -------
Current
------------------------ ------- -------
Trade payables 162,686 144,584
------------------------ ------- -------
Accrued expenses 296,758 271,686
------------------------ ------- -------
Over-lift position 12,837 23,173
------------------------ ------- -------
Joint venture creditors 1,701 1,632
------------------------ ------- -------
VAT payable 23,543 -
------------------------ ------- -------
Other payables 4,465 5,014
------------------------ ------- -------
501,990 446,089
------------------------ ------- -------
Classified as:
------------------------ ------- -------
Current 483,781 367,312
------------------------ ------- -------
Non-current 18,209 78,777
------------------------ ------- -------
501,990 446,089
------------------------ ------- -------
Trade payables are normally non-interest-bearing and settled on
terms of between 10 and 30 days. The Group has arrangements with
various suppliers to defer payment of a proportion of its capital
spend. The majority of these deferred payments fall due in 2019 and
the balance is expected to be fully settled in 2020.
Certain trade and other payables will be settled in currencies
other than the reporting currency of the Group, mainly in
Sterling.
Accrued expenses include accruals for capital and operating
expenditure in relation to the oil and gas assets.
The carrying value of the Group's trade and other payables as
stated above is considered to be a reasonable approximation to
their fair value largely due to the short-term maturities.
24. Commitments and contingencies
Commitments
(i) Operating lease commitments - lessee
The Group has financial commitments in respect of
non-cancellable operating leases for office premises. These leases
have remaining non-cancellable lease terms of between one and 20
years. The future minimum rental commitments under these
non-cancellable leases are as follows:
2018 2017
$'000 $'000
------------------------------------------------------- ------ -------
Due in less than one year 5,058 7,177
------------------------------------------------------- ------ -------
Due in more than one year but not more than five years 20,096 27,286
------------------------------------------------------- ------ -------
Due in more than five years 62,238 75,536
------------------------------------------------------- ------ -------
87,392 109,999
------------------------------------------------------- ------ -------
Lease payments recognised as an operating lease expense during
the year amounted to $5.1 million (2017: $5.3 million).
Under the Dons Northern Producer Agreement, a minimum notice
period of 12 months exists whereby the Group expects the minimum
commitment under this agreement to be approximately $7.8 million
(2017: $7.1 million).
(ii) Operating lease commitments - lessor
The Group sub-leases part of its Aberdeen office. The future
minimum rental commitments under these non-cancellable leases are
as follows:
2018 2017
$'000 $'000
------------------------------------------------------- ------ ------
Due in less than one year 1,568 1,638
------------------------------------------------------- ------ ------
Due in more than one year but not more than five years 6,952 7,141
------------------------------------------------------- ------ ------
Due in more than five years 2,927 4,686
------------------------------------------------------- ------ ------
11,447 13,465
------------------------------------------------------- ------ ------
Sub-lease rent recognised during the year amounted to $1.1
million (2017: $1.3 million).
(iii) Finance lease commitments
The Group had the following obligations under finance leases as
at the balance sheet date:
2018 2018 2017 2017
Minimum Present Minimum Present
payments value payments value
$'000 of payments $'000 of payments
$'000 $'000
--------------------------------------- --------- ------------ --------- ------------
Due in less than one year 144,188 93,169 173,846 118,009
--------------------------------------- --------- ------------ --------- ------------
Due in more than one year but not more
than five years 460,960 313,500 460,960 289,949
--------------------------------------- --------- ------------ --------- ------------
Due in more than five years 341,212 302,281 456,374 389,975
--------------------------------------- --------- ------------ --------- ------------
946,361 708,950 1,091,180 797,933
--------------------------------------- --------- ------------ --------- ------------
Less future financing charges 237,410 - 293,247 -
--------------------------------------- --------- ------------ --------- ------------
708,950 708,950 797,933 797,933
--------------------------------------- --------- ------------ --------- ------------
The FPSO finance lease liability is carried at $709.0 million as
at 31 December 2018 (2017: $797.9 million), of which $144.2 million
is classified as a current liability. Finance lease interest of
$55.8 million (2017: $31.3 million) has been recognised within
finance costs. The finance leases has with an effective borrowing
rate of 8.12%.
(iv) Capital commitments
At 31 December 2018, the Group had capital commitments excluding
the above lease commitments amounting to $15.7 million (2017: $33.8
million).
Contingencies
The Group becomes involved from time to time in various claims
and lawsuits arising in the ordinary course of its business. Other
than as discussed below, the Company is not, nor has been during
the past 12 months, involved in any governmental, legal or
arbitration proceedings which, either individually or in the
aggregate, have had, or are expected to have, a material adverse
effect on the Company's and/or the Group's financial position or
profitability, nor, so far as the Company is aware, are any such
proceedings pending or threatened.
The Group is currently engaged in a dispute with KUFPEC, the
Group's field partner in respect of Alma/Galia. KUFPEC has
commenced a court action in the High Court of Justice claiming an
alleged breach of one of the Group's warranties provided under the
Alma/Galia Farm-in Agreement and seeking damages of $91.0 million
(the maximum breach of warranty claim permitted under the
Alma/Galia Farm-in Agreement), together with interest. The court
proceedings are ongoing and the Directors believe that a
considerable period will elapse before a final decision is reached
by the courts.
The Directors consider the merits of the claim to be poor and
the Group is defending itself vigorously. The Group has not made
any provisions in respect of this claim as the Directors believe
the claim is unlikely to be successful; and in any event the
Directors believe the chances of an outcome exposing the Group to
material damages are remote. There can, however, be no assurances
that this claim will not ultimately be successful, or that the
Group would not otherwise seek to enter into a settlement or
compromise in respect of this claim, or that in the event of any
such circumstances the Group would not incur costs and expenses in
excess of its estimates.
The Group is also currently engaged in discussions with EMAS,
one of the Group's contractors on Kraken who performed the
installation of a buoy and mooring system, in relation to the
payment of approximately $15.0 million of variation claims which
EMAS claims is due as a result of soil conditions at the work site
being materially different from those reasonably expected to be
encountered based on soil data previously provided. The Group is
confident that such variation claims are not valid and that
accordingly such amount is not due and payable by the Group under
the terms of the contract with EMAS. The parties are currently in
discussions pursuant to the dispute resolution process under the
contract.
25. Related party transactions
The Group financial statements include the financial statements
of EnQuest PLC and its subsidiaries. A list of the Group's
principal subsidiaries is contained in note 27 to these Group
financial statements.
Balances and transactions between the Company and its
subsidiaries, which are related parties, have been eliminated on
consolidation and are not disclosed in this note.
All sales to and purchases from related parties are made at
normal market prices and the pricing policies and terms of these
transactions are approved by the Group's management. With the
exception of the transactions disclosed below, there have been no
transactions with related parties who are not members of the Group
during the year ended 31 December 2018 (2017: none).
Share subscription
In 2018, subscription for new Ordinary shares pursuant to the
rights issue (see note 17) at the issue price of GBP0.21 per
share:
-- Double A Limited ('Double A'), a company beneficially owned
by the extended family of Amjad Bseisu, took up its entitlement in
the rights issue, subscribing for 43,849,727 shares;
-- Double A participated in the rump placing for 5,000,000 shares; and
-- Directors and key management personnel took up their
entitlement in the rights issue, subscribing for 382,273
shares.
Office sublease
During the year ended 31 December 2018, the Group recognised
$0.1 million (2017: $0.1 million) of rental income in respect of an
office sublease arrangement with Levendi Investment Management, a
company where 72% of the issued share capital is held by Amjad
Bseisu.
Contracted services
During the year ended 31 December 2018, the Group obtained
contracting services from Influit UK Production Solutions for a
value of $0.06 million (2017: $0.04 million). Amjad Bseisu has an
indirect interest in Influit UK Production Solutions.
Compensation of key management personnel
The following table details remuneration of key management
personnel of the Group. Key management personnel comprise of
Executive and Non-Executive Directors of the Company and other
senior personnel. This includes the Executive Committee for the
year ended 31 December 2018.
2018 2017
$'000 $'000
--------------------------------- ------ ------
Short-term employee benefits 7,052 5,057
--------------------------------- ------ ------
Share-based payments 1,300 1,305
--------------------------------- ------ ------
Post-employment pension benefits 218 55
--------------------------------- ------ ------
8,570 6,417
--------------------------------- ------ ------
26. Risk management and financial instruments
Risk management objectives and policies
The Group's principal financial assets and liabilities comprise
trade and other receivables, cash and short-term deposits,
interest-bearing loans, borrowings and finance leases, derivative
financial instruments and trade and other payables. The main
purpose of these financial instruments is to manage short-term cash
flow and raise finance for the Group's capital expenditure
programme.
The Group's activities expose it to various financial risks
particularly associated with fluctuations in oil price, foreign
currency risk, liquidity risk and credit risk. Management reviews
and agrees policies for managing each of these risks, which are
summarised below. Also presented below is a sensitivity analysis to
indicate sensitivity to changes in market variables on the Group's
financial instruments and to show the impact on profit and
shareholders' equity, where applicable. The sensitivity has been
prepared for periods ended 31 December 2018 and 2017, using the
amounts of debt and other financial assets and liabilities held at
those reporting dates.
Commodity price risk - oil prices
The Group is exposed to the impact of changes in Brent oil
prices on its revenues and profits generated from sales of crude
oil.
The Group's policy is to have the ability to hedge oil prices up
to a maximum of 75% of the next 12 months' production on a rolling
annual basis, up to 60% in the following 12-month period and 50% in
the subsequent 12-month period.
Details of the commodity derivative contracts entered into
during and on hand at the end of 2018 are disclosed in note 20.
The following table summarises the impact on the Group's pre-tax
profit and total equity of a reasonably possible change in the
Brent oil price, on the fair value of derivative financial
instruments, with all other variables held constant. As the
derivatives on hand at 31 December 2018 have not been designated as
hedges, there is no impact on equity.
Pre-tax profit Total equity
----------------- -------------------- --------------------
+$10/bbl -$10/bbl +$10/bbl -$10/bbl
increase decrease increase decrease
$'000 $'000 $'000 $'000
----------------- --------- --------- --------- ---------
31 December 2018 (40,310) 45,146 - -
----------------- --------- --------- --------- ---------
31 December 2017 (68,350) 48,320 - -
----------------- --------- --------- --------- ---------
Foreign exchange risk
The Group is exposed to foreign exchange risk arising from
movements in currency exchange rates. Such exposure arises from
sales or purchases in currencies other than the Group's functional
currency (US Dollars) and the bond which is denominated in
Sterling. To mitigate the risks of large fluctuations in the
currency markets, the hedging policy agreed by the Board allows for
up to 70% of the non-US Dollar portion of the Group's annual
capital budget and operating expenditure to be hedged. For specific
contracted capital expenditure projects, up to 100% can be hedged.
Approximately 3% (2017: 1%) of the Group's sales and 42% (2017:
81%) of costs (including capital expenditure) are denominated in
currencies other than the functional currency.
The Group also enters into foreign currency swap contracts from
time to time to manage short-term exposures.
The following table summarises the sensitivity to a reasonably
possible change in the US Dollar to Sterling foreign exchange rate,
with all other variables held constant, of the Group's profit
before tax due to changes in the carrying value of monetary assets
and liabilities at the reporting date. The impact in equity is the
same as the impact on profit before tax. The Group's exposure to
foreign currency changes for all other currencies is not
material:
Pre-tax profit
----------------- --------------------
+$10% -$10%
rate rate
increase decrease
$'000 $'000
----------------- --------- ---------
31 December 2018 (41,852) 41,852
----------------- --------- ---------
31 December 2017 (43,100) 43,100
----------------- --------- ---------
Credit risk
Credit risk is managed on a Group basis. Credit risk in
financial instruments arises from cash and cash equivalents and
derivative financial instruments where the Group's exposure arises
from default of the counterparty, with a maximum exposure equal to
the carrying amount of these instruments (see maturity table within
liquidity risks in note 26). For banks and financial institutions,
only those rated with an A-/A3 credit rating or better are
accepted. Cash balances can be invested in short-term bank deposits
and AAA-rated liquidity funds, subject to Board approved limits and
with a view to minimising counterparty credit risks.
In addition, there are credit risks of commercial counterparties
including exposures in respect of outstanding receivables. The
Group trades only with recognised international oil and gas
companies and at 31 December 2018 there were $5.0 million of trade
receivables past due (2017: $23.6 million), $1.6 million of joint
venture receivables past due (2017: $1.7 million) and $nil (2017:
$nil) of other receivables past due but not impaired. Subsequent to
year end, $4.6 million of these outstanding balances have been
collected (2017: $1.5 million). Receivable balances are monitored
on an ongoing basis with appropriate follow-up action taken where
necessary.
2018 2017
Ageing of past due but not impaired receivables $'000 $'000
------------------------------------------------ ------ ------
Less than 30 days 4,649 1,726
------------------------------------------------ ------ ------
30-60 days 16 -
------------------------------------------------ ------ ------
60-90 days 8 253
------------------------------------------------ ------ ------
90-120 days - -
------------------------------------------------ ------ ------
120+ days 1,933 23,301
------------------------------------------------ ------ ------
6,606 25,280
------------------------------------------------ ------ ------
At 31 December 2018, the Group had three customers accounting
for 81% of outstanding trade receivables (2017: four customers,
84%) and two joint venture partners accounting for 41% of
outstanding joint venture receivables (2017: three joint venture
partners, 97%).
Liquidity risk
The Group monitors its risk to a shortage of funds by reviewing
its cash flow requirements on a regular basis relative to its
existing bank facilities and the maturity profile of its
borrowings. Specifically, the Group's policy is to ensure that
sufficient liquidity or committed facilities exist within the Group
to meet its operational funding requirements and to ensure the
Group can service its debt and adhere to its financial covenants.
At 31 December 2018, $68.4 million (2017: $97.8 million) was
available for drawdown under the Group's credit facility (see note
19).
The following tables detail the maturity profiles of the Group's
non-derivative financial liabilities including projected interest
thereon. The amounts in these tables are different from the balance
sheet as the table is prepared on a contractual undiscounted cash
flow basis and include future interest payments.
On demand Up to 1 to 2 2 to 5 Over 5 Total
$'000 1 year years years years $'000
Year ended 31 December 2018 $'000 $'000 $'000 $'000
---------------------------- --------- ------- ------- --------- ------- ---------
Loans and borrowings - 364,135 272,189 546,611 - 1,182,935
---------------------------- --------- ------- ------- --------- ------- ---------
Bonds(i) - 34,234 36,521 1,229,314 - 1,300,069
---------------------------- --------- ------- ------- --------- ------- ---------
Obligations under finance
leases - 93,169 69,689 243,811 302,282 708,951
---------------------------- --------- ------- ------- --------- ------- ---------
Trade and other payables - 419,855 18,209 - 50,412 488,476
---------------------------- --------- ------- ------- --------- ------- ---------
- 911,393 396,608 2,019,736 352,694 3,680,431
---------------------------- --------- ------- ------- --------- ------- ---------
On demand Up to 1 to 2 2 to 5 Over 5 Total
$'000 1 year years years years $'000
Year ended 31 December 2017 $'000 $'000 $'000 $'000
---------------------------- --------- ------- ------- --------- ------- ---------
Loans and borrowings - 424,886 347,603 667,975 - 1,440,464
---------------------------- --------- ------- ------- --------- ------- ---------
Bonds(i) - 66,141 66,141 1,112,842 - 1,245,124
---------------------------- --------- ------- ------- --------- ------- ---------
Obligations under finance
leases - 118,009 64,142 225,807 389,975 797,933
---------------------------- --------- ------- ------- --------- ------- ---------
Trade and other payables - 364,472 157,554 - - 522,026
---------------------------- --------- ------- ------- --------- ------- ---------
Other financial liabilities - 7,211 - - - 7,211
---------------------------- --------- ------- ------- --------- ------- ---------
- 980,719 635,440 2,006,624 389,975 4,012,758
---------------------------- --------- ------- ------- --------- ------- ---------
(i) Maturity analysis profile for the Group's bonds includes
semi-annual coupon interest. This interest is only payable in cash
if the average dated Brent oil price is equal to or greater than
$65/bbl for the six months preceding one month before the coupon
payment date (see note 19)
The following tables detail the Group's expected maturity of
payables and receivables for its derivative financial instruments.
The amounts in these tables are different from the balance sheet as
the table is prepared on a contractual undiscounted cash flow
basis. When the amount receivable or payable is not fixed, the
amount disclosed has been determined by reference to a projected
forward curve at the reporting date.
Less than 3 to 12 1 to 2 Over
On demand 3 months months years 2 years Total
Year ended 31 December 2018 $'000 $'000 $'000 $'000 $'000 $'000
------------------------------- --------- --------- ------- ------ -------- ------
Commodity derivative contracts 10,069 52,382 1,852 - - 64,303
------------------------------- --------- --------- ------- ------ -------- ------
Foreign exchange derivative
contracts - 249 - - - 249
------------------------------- --------- --------- ------- ------ -------- ------
Carbon derivative contracts (837) 9,542 - - - 8,705
------------------------------- --------- --------- ------- ------ -------- ------
9,232 62,173 1,852 - - 73,257
------------------------------- --------- --------- ------- ------ -------- ------
Less than 3 to 12 1 to 2 Over
On demand 3 months months years 2 years Total
Year ended 31 December 2017 $'000 $'000 $'000 $'000 $'000 $'000
------------------------------- --------- --------- -------- ------- -------- --------
Commodity derivative contracts (4,991) (29,616) (10,850) (1,531) - (46,988)
------------------------------- --------- --------- -------- ------- -------- --------
Chooser contract (1,035) - - - - (1,035)
------------------------------- --------- --------- -------- ------- -------- --------
Interest rate swaps - (13) (19) - - (32)
------------------------------- --------- --------- -------- ------- -------- --------
(6,026) (29,629) (10,869) (1,531) - (48,055)
------------------------------- --------- --------- -------- ------- -------- --------
Capital management
The capital structure of the Group consists of debt, which
includes the borrowings disclosed in note 19, cash and cash
equivalents and equity attributable to the equity holders of the
parent company, comprising issued capital, reserves and retained
earnings as in the Group statement of changes in equity.
The primary objective of the Group's capital management is to
optimise the return on investment, by managing its capital
structure to achieve capital efficiency whilst also maintaining
flexibility. The Group regularly monitors the capital requirements
of the business over the short, medium and long term, in order to
enable it to foresee when additional capital will be required. On
21 November 2016, the Group completed a comprehensive package of
financial restructuring measures (see notes 17 and 19 for further
details).
The Group has approval from the Board to hedge foreign exchange
risk on up to 70% of the non-US Dollar portion of the Group's
annual capital budget and operating expenditure. For specific
contracted capex projects, up to 100% can be hedged. In addition,
the Group's policy is to have the ability to hedge oil prices up to
a maximum of 75% of the next 12 months production on a rolling
annual basis, up to 60% in the following 12-month period and 50% in
the subsequent 12 month period. This is designed to reduce the risk
of adverse movements in exchange rates and market prices eroding
the return on the Group's projects and operations.
The Board regularly reassesses the existing dividend policy to
ensure that shareholder value is maximised. Any future payment of
dividends is expected to depend on the earnings and financial
condition of the Company and such other factors as the Board
considers appropriate.
The Group monitors capital using the gearing ratio and return on
shareholders' equity as follows:
2018 2017
$'000 $'000
---------------------------------------------------------- --------- ---------
Loans, borrowings and bond(i) (A) 2,048,498 2,164,550
---------------------------------------------------------- --------- ---------
Cash and short-term deposits (240,605) (173,128)
---------------------------------------------------------- --------- ---------
Net debt/(cash) (B) 1,807,894 1,991,422
---------------------------------------------------------- --------- ---------
Equity attributable to EnQuest PLC shareholders (C) 983,552 760,866
---------------------------------------------------------- --------- ---------
Profit/(loss) for the year attributable to EnQuest PLC
shareholders (D) 127,278 (60,830)
---------------------------------------------------------- --------- ---------
Profit/(loss) for the year attributable to EnQuest PLC
shareholders excluding exceptionals (E) 78,195 (33,554)
---------------------------------------------------------- --------- ---------
Gross gearing ratio (A/C) 2.1 2.8
---------------------------------------------------------- --------- ---------
Net gearing ratio (B/C) 1.8 2.6
---------------------------------------------------------- --------- ---------
Shareholders' return on investment (D/C) 13% (8%)
---------------------------------------------------------- --------- ---------
Shareholders' return on investment excluding exceptionals
(E/C) 8% (4%)
---------------------------------------------------------- --------- ---------
(i) Principal amounts drawn, excludes netting off of fees (see note 19)
27. Subsidiaries
At 31 December 2018, EnQuest PLC had investments in the
following subsidiaries:
Proportion
of
nominal
value
of issued
shares
Country controlled
of by
Name of company Principal activity incorporation the Group
-------------------------------- --------------------------------------- --------------- -----------
Intermediate holding company
and provision of Group manpower
EnQuest Britain Limited and contracting/procurement services England 100%
--------------------------------- ---------------------------------------- ------------- -----------
Exploration, extraction and production
EnQuest Heather Limited(i) of hydrocarbons England 100%
--------------------------------- ---------------------------------------- ------------- -----------
Exploration, extraction and production
EnQuest Thistle Limited(i) of hydrocarbons England 100%
--------------------------------- ---------------------------------------- ------------- -----------
Stratic UK (Holdings)
Limited(i) Intermediate holding company England 100%
--------------------------------- ---------------------------------------- ------------- -----------
Grove Energy Limited1 Intermediate holding company Canada 100%
--------------------------------- ---------------------------------------- ------------- -----------
Exploration, extraction and production
EnQuest ENS Limited(i) of hydrocarbons England 100%
--------------------------------- ---------------------------------------- ------------- -----------
Exploration, extraction and production
EnQuest UKCS Limited(i) of hydrocarbons England 100%
--------------------------------- ---------------------------------------- ------------- -----------
Exploration, extraction and production
EnQuest Norge AS(i)2 of hydrocarbons Norway 100%
--------------------------------- ---------------------------------------- ------------- -----------
EnQuest Heather Leasing
Limited(i) Leasing England 100%
--------------------------------- ---------------------------------------- ------------- -----------
Exploration, extraction and production
EQ Petroleum Sabah Limited(i) of hydrocarbons England 100%
--------------------------------- ---------------------------------------- ------------- -----------
EnQuest Dons Leasing Limited(i) Dormant England 100%
--------------------------------- ---------------------------------------- ------------- -----------
Exploration, extraction and production
EnQuest Energy Limited(i) of hydrocarbons England 100%
--------------------------------- ---------------------------------------- ------------- -----------
Exploration, extraction and production
EnQuest Production Limited(i) of hydrocarbons England 100%
--------------------------------- ---------------------------------------- ------------- -----------
EnQuest Global Limited Intermediate holding company England 100%
--------------------------------- ---------------------------------------- ------------- -----------
Exploration, extraction and production
EnQuest NWO Limited(i) of hydrocarbons England 100%
--------------------------------- ---------------------------------------- ------------- -----------
EQ Petroleum Production Exploration, extraction and production
Malaysia Limited(i) of hydrocarbons England 100%
--------------------------------- ---------------------------------------- ------------- -----------
Construction, ownership and operation
NSIP (GKA) Limited3 of an oil pipeline Scotland 100%
--------------------------------- ---------------------------------------- ------------- -----------
Provision of Group manpower and
EnQuest Global Services contracting/procurement services
Limited(i)4 for the International business Jersey 100%
--------------------------------- ---------------------------------------- ------------- -----------
EnQuest Marketing and Marketing and trading of crude
Trading Limited oil England 100%
--------------------------------- ---------------------------------------- ------------- -----------
NorthWestOctober Limited(i) Dormant England 100%
--------------------------------- ---------------------------------------- ------------- -----------
EnQuest UK Limited(i) Dormant England 100%
--------------------------------- ---------------------------------------- ------------- -----------
EnQuest Petroleum Developments Exploration, extraction and production
Malaysia SDN. BHD(i)5 of hydrocarbons Malaysia 100%
--------------------------------- ---------------------------------------- ------------- -----------
EnQuest NNS Holdings Limited(i) Intermediate holding company England 100%
--------------------------------- ---------------------------------------- ------------- -----------
Exploration, extraction and production
EnQuest NNS Limited(i) of hydrocarbons England 100%
--------------------------------- ---------------------------------------- ------------- -----------
EnQuest Advance Holdings
Limited(i) Intermediate holding company England 100%
--------------------------------- ---------------------------------------- ------------- -----------
Exploration, extraction and production
EnQuest Advance Limited(i) of hydrocarbons England 100%
--------------------------------- ---------------------------------------- ------------- -----------
(i) Held by subsidiary undertaking
The Group has three branches outside the UK (all held by
subsidiary undertakings): EnQuest Global Services Limited (Dubai);
EnQuest Petroleum Production Malaysia Limited (Malaysia); and EQ
Petroleum Sabah Limited (Malaysia).
Registered office addresses:
1 Suite 2200, 1055 West Hastings Street, Vancouver, British Columbia, V6E 2E9
2 Fabrikkveien 9, Stavanger, 4033, Norway
3 Annan House, Palmerston Road, Aberdeen, Scotland, AB11 5QP, United Kingdom
4 Ground Floor, Colomberie House, St Helier, JE4 0RX, Jersey
5 c/o TMF, 10th Floor, Menara Hap Seng, No 1 & 3, Jalan P. Ramlee 50250 Kuala Lumpur, Malaysia
28. Cash flow information
Cash generated from operations
Year ended Year ended
31 December 31 December
2018 2017
Notes $'000 $'000
------------------------------------------------------ ------- ------------ ------------
Profit/(loss) before tax 93,985 (243,773)
------------------------------------------------------ ------- ------------ ------------
Depreciation 5(c) 5,287 4,500
------------------------------------------------------ ------- ------------ ------------
Depletion 5(b) 437,104 224,698
------------------------------------------------------ ------- ------------ ------------
Exploration costs impaired/(reversed) and written
off 5(d) 1,407 (193)
------------------------------------------------------ ------- ------------ ------------
Net impairment (reversal)/charge to oil and gas
assets 4 126,046 171,971
------------------------------------------------------ ------- ------------ ------------
Write down of inventory 4 5,837 (2,682)
------------------------------------------------------ ------- ------------ ------------
Write down of asset 4 3,602 2,808
------------------------------------------------------ ------- ------------ ------------
Excess of fair value over consideration 4 - (48,734)
------------------------------------------------------ ------- ------------ ------------
Loss on fair value of purchase option 4 1,329 -
------------------------------------------------------ ------- ------------ ------------
Gain on step acquisition accounting for 25% of
Magnus and other interests 4 (74,345) -
------------------------------------------------------ ------- ------------ ------------
Gain on disposal of loan notes 5(d) - (1,263)
------------------------------------------------------ ------- ------------ ------------
Impairment (reversal)/charge to investments 4 121 19
------------------------------------------------------ ------- ------------ ------------
Share-based payment charge 5(f) 4,645 2,849
------------------------------------------------------ ------- ------------ ------------
Shares purchased on behalf of Employee Benefit
Trust 17 - (1,763)
------------------------------------------------------ ------- ------------ ------------
Change in deferred consideration 5(d) 14,028 -
------------------------------------------------------ ------- ------------ ------------
Change in surplus lease provision 22 8 (200)
------------------------------------------------------ ------- ------------ ------------
Change in decommissioning provision 5(d) 12,617 -
------------------------------------------------------ ------- ------------ ------------
Change in other provisions 22 (3,907) 10,161
------------------------------------------------------ ------- ------------ ------------
Amortisation of option premiums 20 17,208 (10,445)
------------------------------------------------------ ------- ------------ ------------
Unrealised (gain)/loss on commodity financial
instruments 5(a)(b) (97,432) (2,010)
------------------------------------------------------ ------- ------------ ------------
Unrealised (gain)/loss on other financial instruments 5(a)(b) (2,310) -
------------------------------------------------------ ------- ------------ ------------
Unrealised exchange loss/(gain) 5(e) (21,911) 23,910
------------------------------------------------------ ------- ------------ ------------
Net finance (income)/expense 6 219,191 147,079
------------------------------------------------------ ------- ------------ ------------
Operating profit before working capital changes 742,510 276,932
------------------------------------------------------ ------- ------------ ------------
Decrease/(increase) in trade and other receivables 6,844 (13,611)
------------------------------------------------------ ------- ------------ ------------
(Increase)/decrease in inventories 22,255 2,039
------------------------------------------------------ ------- ------------ ------------
(Decrease)/increase in trade and other payables 17,020 61,674
------------------------------------------------------ ------- ------------ ------------
Cash generated from operations 788,629 327,034
------------------------------------------------------ ------- ------------ ------------
Changes in liabilities arising from financing activities
Loans Finance
and borrowings Bonds leases
(see note (see note (see note
19) 19) 24) Total
Year ended 31 December 2018 $'000 $'000 $'000 $'000
---------------------------------- --------------- ------------------ ---------- -----------
At 1 January 2017 (1,102,366) (868,740) - (1,971,106)
---------------------------------- --------------- ------------------ ---------- -----------
Cash flows (112,001) - - (112,001)
---------------------------------- --------------- ------------------ ---------- -----------
Additions - - (771,975) (771,975)
---------------------------------- --------------- ------------------ ---------- -----------
Foreign exchange adjustments (552) (18,828) - (19,380)
---------------------------------- --------------- ------------------ ---------- -----------
Capitalised PIK - (58,242) - (58,242)
---------------------------------- --------------- ------------------ ---------- -----------
Unwind of finance discount - - (31,273) (31,273)
---------------------------------- --------------- ------------------ ---------- -----------
Other non-cash movements (4,756) 935 5,315 1,494
---------------------------------- --------------- ------------------ ---------- -----------
At 31 December 2017 (1,219,675) (944,875) (797,933) (2,962,483)
---------------------------------- --------------- ------------------ ---------- -----------
Adjustment on adoption of IFRS 9 - (38,117) - (38,117)
---------------------------------- --------------- ------------------ ---------- -----------
At 1 January 2018 (1,219,675) (982,992) (797,933) (3,000,600)
---------------------------------- --------------- ------------------ ---------- -----------
Cash flows 357,072 - 144,820 501,892
---------------------------------- --------------- ------------------ ---------- -----------
Additions (175,000) - - (175,000)
---------------------------------- --------------- ------------------ ---------- -----------
Foreign exchange adjustments 814 11,745 - 12,559
---------------------------------- --------------- ------------------ ---------- -----------
Capitalised interest and PIK (13,179) (16,220) - (29,399)
---------------------------------- --------------- ------------------ ---------- -----------
Unwind of finance discount - - (55,837) (55,837)
---------------------------------- --------------- ------------------ ---------- -----------
Other non-cash movements (199) (10,864) - (11,063)
---------------------------------- --------------- ------------------ ---------- -----------
At 31 December 2018 (see note 19) (1,050,167) (998,331) (708,950) (2,757,448)
---------------------------------- --------------- ------------------ ---------- -----------
29. Business combinations
Acquisitions in 2018
Acquisition of 75% interest in Magnus oil field and associated
interests
On 1 December 2018, EnQuest completed the acquisition from BP of
the remaining 75% interest in the Magnus oil field ('Magnus'), an
additional 9.0% interest in Sullom Voe Oil terminal and supply
facility ('SVT') and other additional interests in associated
infrastructure (collectively the 'Transaction assets'). This
acquisition followed from the acquisition of initial interests
completed in December 2017 (see below). The transaction is in
keeping with EnQuest's strategy of maximising value from late life
assets with significant remaining resource potential.
The Transaction assets constitute a business and the acquisition
has been accounted for using the acquisition method, in accordance
with IFRS 3 Business Combinations. The consolidated financial
statements include the fair values of the identifiable assets and
liabilities as at the date of acquisition and the results of the
assets for the one month period from the acquisition date. Each
identifiable asset and liability is measured at its acquisition
date fair value based on guidance in IFRS 13 Fair Value
Measurement. The standard defines fair value as the price that
would be received to sell an asset or transfer a liability in an
orderly fashion between willing market participants at the
measurement date.
Accounts receivable are recognised at gross contractual amounts
due, as they relate to large and creditworthy customers.
Historically, there has been no significant uncollectible accounts
receivable in the Transaction assets. At 31 December 2018, none of
the trade receivables have been impaired.
The fair value of the identifiable assets and liabilities of the
Transaction assets as at the date of acquisition were:
Fair value
recognised
on acquisition
$'000
------------------------------------------------------------- ---------------
Assets
------------------------------------------------------------- ---------------
Property, plant and equipment (see note 10) 745,350
------------------------------------------------------------- ---------------
Inventory 50,977
------------------------------------------------------------- ---------------
Trade and other receivables (see note 15) 2,927
------------------------------------------------------------- ---------------
Liabilities
------------------------------------------------------------- ---------------
Trade and other payables (see note 23) (44,616)
------------------------------------------------------------- ---------------
Financial liabilities (see note 20) (8,370)
------------------------------------------------------------- ---------------
Deferred tax liability (see note 7) (94,634)
------------------------------------------------------------- ---------------
Total identifiable net assets 651,633
------------------------------------------------------------- ---------------
Technical goodwill arising on acquisition 94,633
------------------------------------------------------------- ---------------
Purchase option derecognition (20,970)
------------------------------------------------------------- ---------------
Purchase consideration 725,296
------------------------------------------------------------- ---------------
Purchase consideration transferred:
------------------------------------------------------------- ---------------
Cash transferred 100,000
------------------------------------------------------------- ---------------
Deferred consideration: Vendor loan 116,530
------------------------------------------------------------- ---------------
Contingent consideration: Future cash flow share arrangement 508,766
------------------------------------------------------------- ---------------
Total purchase consideration 725,296
------------------------------------------------------------- ---------------
(i) The initial accounting for the acquisition of the
Transaction assets has only been provisionally determined at the
end of the reporting period. At the date of finalisation of these
financial statements, the necessary market valuations and other
calculations had not been finalised and they have therefore only
been provisionally determined based on the Directors' best
estimates. Thus, the fair value of the net assets may be
subsequently adjusted, with a corresponding adjustment to goodwill
prior to 1 December 2019 (one year after the transaction)
Goodwill arising on acquisition
The option to purchase the remaining 75% in Magnus and other
interests was included with the acquisition of the initial 25%
interest. As at 31 December 2017, the option was recognised as a
financial asset of $22.3 million. The option was revalued on
exercise on 1 December 2018 to the fair value of the acquisition
assets, resulting in a financial asset of $21.0 million. The
revaluation of the option in the year resulted in an expense of
$1.3 million and has been recognised in the statement of
comprehensive income through other income in 'Remeasurements and
exceptional items'. The option value captures the ability of
EnQuest to extend the life of existing mature assets and from the
Group's ability to maximise the value from the late life assets
with significant remaining resource potential and the increase in
underlying oil prices during the year.
On acquisition, the option was derecognised as part of the
acquisition assets and liabilities. The goodwill of $94.6 million
arises principally due to the requirement to recognise deferred tax
assets and liabilities for the difference between the assigned fair
values and the tax bases of assets acquired and liabilities assumed
in a business combination. The assessment of the fair value of
property, plant and equipment is based on cash flows after tax.
Nevertheless, in accordance with IAS 12 sections 15 and 19, a
provision is made for deferred tax corresponding to the tax rate
multiplied with the difference between the acquisition cost and the
tax base. The offsetting entry to this deferred tax is goodwill.
Hence, goodwill arises as a technical effect of deferred tax
('technical goodwill'). None of the goodwill recognised will be
deductible for income tax purposes.
Fair value of consideration
The consideration for the acquisition of the Transaction assets
was $300 million, consisting of $100 million cash contribution,
paid from the funds received through the rights issue undertaken in
October 2018, and $200 million deferred consideration financed by
BP, which are to be repaid out of future cash flows from the
assets. With an effective date of 1 January 2017, the deferred
consideration was adjusted for the interim period and working
capital adjustments, resulting in contingent consideration of
$116.5 million as at 1 December 2018. The deferred consideration is
secured over the interests in the Transaction assets and accrues
interest at a rate of 7.5% per annum on the base consideration.
The consideration also included a cash flow sharing arrangement
whereby EnQuest and BP share the net cash flow generated by the 75%
interest on a 50:50 basis, subject to a cap of $1 billion received
by BP. The present value of the contingent future cash flow share
arrangement over the estimated life of the field has resulted in
the recognition of contingent consideration of $508.8 million.
The present value of the deferred and contingent profit share
consideration is calculated from the future expected cash flows, at
a discount rate of 10.0%. These are recognised within contingent
consideration within provisions (see note 22).
From the date of acquisition, the Transaction assets have
contributed $41.7 million of revenue and a $1.2 million gain to the
profit before tax from continuing operations of the Group. If the
combination had taken place at the beginning of 2018, revenue from
continuing operations would have been an additional $264.7 million
and the profit before tax from continuing operations would have
been an additional $103.7 million. In determining these amounts,
management has assumed that the fair value adjustments, determined
provisionally, that arose on the date of acquisition would have
been the same if the acquisition had occurred on 1 January
2018.
Fair value uplift
The acquisition of the remaining 75% interest is considered a
step acquisition as per IFRS 3 Business Combinations. The property,
plant and equipment acquired with the initial 25% has been fair
valued as at 1 December 2018, recognising an uplift of $123.9
million to property, plant and equipment and a corresponding
deferred tax liability of $49.6 million. The gain on uplift of
$74.3 million has been recognised through other income in
'Remeasurements and exceptional items' in the statement of
comprehensive income.
Acquisitions in 2017
Acquisition of 25% interest in Magnus oil field and associated
interests
On 1 December 2017, EnQuest completed the acquisition from BP of
an initial 25% interest in the Magnus oil field ('Magnus') as well
as a 3.0% interest in SVT, 9.0% of Northern Leg Gas Pipeline
('NLGP'), and 3.8% of Ninian Pipeline System ('NPS') (collectively
the 'Transaction assets').
The fair value of the identifiable assets and liabilities of the
Transaction assets as at the date of acquisition were:
Fair value
recognised
on acquisition
$'000
------------------------------------------------------------ ---------------
Assets
------------------------------------------------------------ ---------------
Property, plant and equipment (see note 10) 124,542
------------------------------------------------------------ ---------------
Purchase option(i) 22,300
------------------------------------------------------------ ---------------
Financial asset(ii) 16,120
------------------------------------------------------------ ---------------
Inventory 14,884
------------------------------------------------------------ ---------------
177,846
------------------------------------------------------------ ---------------
Liabilities
------------------------------------------------------------ ---------------
Trade and other payables (see note 23) (8,459)
------------------------------------------------------------ ---------------
Financial liabilities(iii) (4,214)
------------------------------------------------------------ ---------------
Deferred tax liability (see note 7) (49,816)
------------------------------------------------------------ ---------------
(62,489)
------------------------------------------------------------ ---------------
Total identifiable net assets at fair value 115,357
------------------------------------------------------------ ---------------
Excess of fair value over cost arising on acquisition:
------------------------------------------------------------ ---------------
Purchase option(i) (22,300)
------------------------------------------------------------ ---------------
Thistle decommissioning option(ii) (16,120)
------------------------------------------------------------ ---------------
25% acquisition value (10,314)
------------------------------------------------------------ ---------------
Total excess of fair value over cost arising on acquisition (48,734)
------------------------------------------------------------ ---------------
Purchase consideration through vendor loan 66,623
------------------------------------------------------------ ---------------
(i) The financial asset related to the purchase option to
acquire the remaining 75% of Magnus oil field and BP's interest in
the associated infrastructure for a value of $300 million. At 31
December 2017, the option was recognised as a financial asset of
$22.3 million (see note 20)
(ii) The financial asset related to the Thistle decommissioning
option, and represents the difference between the $50 million cash
that BP would transfer to EnQuest upon exercise of the option, and
the net present value of the estimated cash outflow to settle the
liability assumed
(ii) The financial liability related to the amount due to BP by
reference to 7.5% of BP's actual decommissioning costs on an
after-tax basis. The additional consideration EnQuest may pay is
capped at the amount of cumulative positive cash flows received by
EnQuest from the Transaction assets
The new assets recognised in the 31 December 2017 financial
statements were based on a provisional assessment of their fair
value while the Group determined the necessary market valuations
and other calculations. During 2018, the calculations were
completed resulting in a $1.5 million decrease to accruals and
underlift, with the corresponding balance taken through acquisition
property, plant and equipment.
In addition to the above identifiable assets and liabilities,
under the terms of the agreement, the Group had the option to
acquire the remaining 75% of the Magnus oil field and BP's interest
in the associated infrastructure as exercised and described above.
EnQuest also had the option to receive $50 million from BP in
exchange for undertaking the management of the physical
decommissioning activities for Thistle and Deveron and making
payments by reference to 6.0% of the gross decommissioning costs of
Thistle and Deveron fields. The option was exercised in full during
2018 (see note 20).
The excess of fair value of the net assets acquired over the
purchase consideration has arisen primarily due to BP's strategic
decision to partner with EnQuest to extend the life of existing
mature assets and from the Group's ability to maximise the value
from the late life assets with significant remaining resource
potential. The gain has been immediately recognised through
exceptionals in the statement of comprehensive income.
Fair value of consideration
The consideration payable has been satisfied via a vendor loan
from BP. The loan is repayable solely out of the cash flows which
are achieved above operating cash flows from the Transaction assets
and is secured over the interests in the Transaction assets. The
loan accrues interest at a rate of 5.0% per annum on the base
consideration. The base consideration was $85 million, which was
adjusted for the interim period and working capital adjustments
since the economic date of 1 January 2017, resulting in contingent
consideration of $66.6 million. The present value of the deferred
consideration was calculated from the future expected cash flows,
at a discount rate of 10.0% and assumed repayment of around three
years. This is recognised within contingent consideration within
provisions (see note 22).
During 2017 from the date of acquisition, the Transaction assets
contributed $14.0 million of revenue and $2.1 million to the profit
before tax from continuing operations of the Group. If the
combination had taken place at the beginning of 2017, revenue from
continuing operations would have been $73.9 million and the profit
before tax from continuing operations would have been $25.9
million. In determining these amounts, management has assumed that
the fair value adjustments, determined provisionally, that arose on
the date of acquisition would have been the same if the acquisition
had occurred on 1 January 2017. At 31 December 2017, none of the
trade receivables have been impaired.
This information is provided by RNS, the news service of the
London Stock Exchange. RNS is approved by the Financial Conduct
Authority to act as a Primary Information Provider in the United
Kingdom. Terms and conditions relating to the use and distribution
of this information may apply. For further information, please
contact rns@lseg.com or visit www.rns.com.
END
FR LFFEIVLIIFIA
(END) Dow Jones Newswires
March 21, 2019 03:01 ET (07:01 GMT)
Enquest (LSE:ENQ)
Historical Stock Chart
From Mar 2024 to Apr 2024
Enquest (LSE:ENQ)
Historical Stock Chart
From Apr 2023 to Apr 2024