TIDMENQ
RNS Number : 2117I
EnQuest PLC
20 March 2018
Results for the year ended 31 December 2017 and 2018 outlook
20 March 2018
Unless otherwise stated, all figures are on a Business
performance basis and are in US Dollars.
2017 performance
-- Kraken first oil delivered in Q2; full cycle gross project
capital expenditure further reduced
-- Acquisition of interests in Magnus and the Sullom Voe Oil Terminal completed in December
-- Group production averaged 37,405 Boepd in 2017, down 5.9% on 2016
-- Revenue of $635.2 million (2016: $849.6 million) and EBITDA
of $303.6 million (2016: $477.1 million); lower realised prices,
reflecting the favourable impact of commodity hedges in 2016
-- Cash generated from operations of $327.0 million (2016: $408.3 million)
-- Cash capital expenditure of $367.6 million (2016: $609.2 million)
-- Cash* and available bank facilities amounted to $244.4
million at 31 December 2017, with net debt of
$1,991.4 million. Excluding Payment in Kind interest, net debt
was $1,900.9 million
-- Reported post-tax non-cash impairments of $107.2 million
-- Net 2P reserves of 210 MMboe at the end of 2017
* Excluding $26.5 million of cash from the ring fenced working
capital facility associated with SVT.
2018 outlook
-- Guidance range of c.50,000 to 58,000 Boepd; Kraken gross
production has averaged around 38,000 Bopd in the first two months
of the year
-- Unit opex expected to be c.$24/Boe, including costs associated with planned workovers
-- Cash capital expenditure expected to be c.$250 million;
includes drilling programmes at Kraken (DC4), PM8/Seligi and
Heather
-- Kraken full cycle gross project capital expenditure further
reduced to c.$2.3 billion, more than 25% lower than originally
sanctioned
-- The Group has hedged c.7.5 MMbbls of oil at an average price of c.$62/bbl
EnQuest Chief Executive, Amjad Bseisu, said:
"2017 was a transformational year for EnQuest. The Group
delivered the complex Kraken project on schedule and expects full
cycle gross capital expenditure to be significantly below budget,
while the acquisition of the Magnus oil field and Sullom Voe Oil
Terminal is aligned with the Group's asset life extension
capabilities and provides further opportunities for synergies and
growth.
"Production performance in January and February was strong and
the Group expects a material increase in production in 2018. This
growth, combined with a focus on cost control and a substantially
reduced cash capital expenditure programme, should see the Group
generate increased cash flow, enabling it to manage its liquidity
and reduce debt.
"Beyond 2018, the Group has significant potential within the
existing portfolio, in particular at Magnus and PM8/Seligi, but
also with potential future developments at Kraken, positioning
EnQuest to deliver long-term sustainable growth."
Production and financial information
2017 2016 Change
%
Production (Boepd) 37,405 39,751 (5.9)
---------------------------------- ---------- ---------- -------
Revenue and other operating
income ($m)(***) 635.2 849.6 (25.2)
---------------------------------- ---------- ---------- -------
Realised oil price ($/bbl)(***) 52.2 63.8 (18.2)
---------------------------------- ---------- ---------- -------
Gross profit ($m) 65.7 196.1 (66.5)
---------------------------------- ---------- ---------- -------
Profit before tax & net
finance costs ($m) 47.3 237.1 (80.1)
---------------------------------- ---------- ---------- -------
EBITDA ($m)** 303.6 477.1 (36.4)
---------------------------------- ---------- ---------- -------
Cash generated from operations
($m) 327.0 408.3 (19.9)
---------------------------------- ---------- ---------- -------
Reported basic earnings
per share (cents) (5.4) 22.7 -
---------------------------------- ---------- ---------- -------
Cash capex ($m)**** 367.6 609.2 (39.7)
---------------------------------- ---------- ---------- -------
End 2017 End 2016
---------------------------------- ---------- ---------- -------
Net (debt)/cash ($m)(*****) (1,991.4) (1,796.5) 10.8
---------------------------------- ---------- ---------- -------
**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 and the realised gains/loss on foreign
currency derivatives related to capital expenditure. *** Including
losses of $20.6 million (2016: revenue of $255.8 million)
associated with EnQuest's oil price hedges. ****Cash capex is
stated net of proceeds received from the disposal of tangible and
intangible fixed assets of $nil (2016: $1.5 million). ***** Net
(debt)/cash represents cash and cash equivalents less borrowings,
stated excluding accrued interest and the net-off of unamortised
fees.
Production details
Production Net daily Net daily
on a working average average
interest basis 1 Jan' 1 Jan'
2017 to 2016 to
31 Dec' 31 Dec'
2017 2016
----------------- ---------- ----------
(Boepd) (Boepd)
Northern North
Sea 15,627(1) 18,885
Central North
Sea 8,131 11,718(2)
Kraken 4,709(3) -
---------- ----------
Total UKCS 28,467 30,603
---------- ----------
Total Malaysia 8,938 9,148
----------
Total EnQuest 37,405 39,751
---------- ----------
(1) Includes net production from Magnus since acquisition on 1
December 2017, averaged over the 12 months to the end of December
2017.
(2) Includes net production from Scolty/Crathes since first oil
on 21 November 2016, averaged over the 12 months to the end of
December 2016.
(3) Net production since first oil on 23 June, averaged over the
12 months to the end of December 2017.
2017 performance summary
The Group's focus during the year was to deliver the Kraken
development, complete the acquisition of assets from BP and
position the Group for profitable growth as it transitions from a
period of heavy investment to one in which the Group can begin to
reduce its debt. First oil from the Kraken project, one of the
largest developments in the North Sea in the last ten years, was
delivered on schedule, with full cycle gross capital expenditure
expected to be significantly below budget. EnQuest completed the
acquisition of initial interests in Magnus, the Sullom Voe Oil
Terminal and associated infrastructure in December.
Production for the year was lower than originally expected at
37,405 Boepd, impacted by Electrical Submersible Pump performance
at Alma/Galia and lower contributions from the Scolty/Crathes and
Kraken developments.
The Group's focus on cost control and management of commercial
agreements resulted in lower operating expenditures of $349.3
million, with unit opex of $25.6/boe. However, lower realised
prices, reflecting the forward prices available at the time at
which the commodity hedge programme was implemented, combined with
lower production reduced EnQuest's revenue, EBITDA and cash
generated by operations.
As expected, cash capital expenditure of $367.6 million was
materially lower than 2016. The majority of the expenditure was at
Kraken, with the remaining spend largely reflecting the settlement
of deferred invoices in respect of the Alma/Galia and
Scolty/Crathes developments and the Eagle discovery. Excellent
drilling performance at Kraken has delivered the first three drill
centres ('DC's) significantly ahead of schedule, which, along with
lower market rates for the remaining subsea campaign, resulted in a
reduction of approximately $100 million in the expected full life
gross project capital expenditure estimate.
Liquidity and net debt
EnQuest's lending banks continued their support of the Group and
agreed to relax the Company's covenants and to amend the
amortisation schedule of its Term Loan and Revolving Credit
Facility. EnQuest also agreed an $80 million oil prepayment
transaction and execution of a $37.25 million refinancing agreement
in relation to its Tanjong Baram project. EnQuest finished the year
with net debt of $1,991.4 million, with cash and available bank
facilities of
$244.4 million, excluding $26.5 million of cash from the ring
fenced working capital facility associated with SVT.
Reserves
Net 2P reserves at the end of 2017 were 210 MMboe, (2016: 215
MMboe) representing a reserve life of 17 years. The slight
reduction in reserves was driven by some changes in long-term
assumptions combined with lower production performance in the North
Sea, largely offset by the benefit of the acquisition of an initial
25% equity interest in Magnus and better production performance in
Malaysia.
2018 performance and additional outlook details
Production performance in the first two months of 2018 was
strong across the portfolio, with Kraken gross average production
around 38,000 Bopd in this period. Extreme cold weather in early
March resulted in brief shutdowns at a number of the Group's North
Sea fields. While Kraken was shut down, the Group has undertaken
much of the workscope previously scheduled for the planned shutdown
in April and, as a result, this planned shutdown is no longer
required. The Group continues to have planned maintenance shutdowns
at a number of the Group's fields, including Kraken, in the third
quarter. The drilling programmes at Magnus and PM8/Seligi, along
with the workover programme at Alma/Galia are expected to deliver
production improvements later in the year, with the DC4 programme
at Kraken expected to come into production in 2019. The Group
expects material net production growth in 2018 to within the
guidance range of c.50,000 to 58,000 Boepd.
The Group continues to expect unit operating expenditures of
approximately $24/Boe, including the impact of planned workovers at
Alma/Galia, while the depletion and depreciation charge is
anticipated to be around $22/Boe, reflecting the impact of a full
year's contribution from Kraken.
2017 general and administration costs reflect the Group's
ongoing efforts to reduce costs across the organisation. 2018 costs
are expected to be in the 'single digit' millions.
Cash capital expenditure is still expected to be around $250
million, largely reflecting the drilling programmes at Kraken,
Heather and PM8/Seligi. The renegotiation of the drilling rig
contract with Transocean, reducing both the contract duration and
day rate, has resulted in net cash capital expenditure savings of
c.$60 million in 2019. Kraken full cycle gross project capital
expenditure is now expected to be c.$2.3 billion, more than 25%
lower than originally sanctioned.
EnQuest continues to take prudent measures to improve its
liquidity position. In January, EnQuest received $30 million in
cash in exchange for agreeing to undertake the management of the
physical decommissioning at Thistle and Deveron and being liable to
make payments to BP by reference to 3.7% of the gross
decommissioning costs of these assets. The Group has an outstanding
option, exercisable over a 12 month period, to receive a further
$20 million in cash in exchange for making additional payments by
reference to 2.4% of the gross decommissioning costs of these
fields. In February, the Group completed the $37.25 million
refinancing agreement in relation to its Tanjong Baram project,
providing approximately $25 million in additional liquidity.
Summary financial review of 2017
(all figures quoted are in US Dollars and relate to Business
performance unless otherwise stated)
Total revenue for 2017 was $635.2 million, 25.2% lower than 2016
($849.6 million). This reduction was largely as a result of lower
realised prices, which reflected the forward prices available at
the time at which the commodity hedge programme was implemented.
The commodity hedge programme resulted in realised losses of $20.6
million in 2017 compared to realised gains of $255.8 million in
2016. As a result, the Group's blended average realised oil price
was $52.2/bbl in 2017, compared to $63.8/bbl during 2016. Excluding
this hedging impact, the average realised oil price was $53.9/bbl
in 2017, 21.8% higher than 2016 ($44.3/bbl), reflecting higher
market prices. Revenue is predominantly derived from crude oil
sales which totalled $637.0 million for 2017, 10.2% higher than
2016 ($577.8 million). This increase in crude oil revenue reflected
a higher market oil price, partially offset by lower
production.
Total cost of sales for 2017 was $569.5 million, 12.9% lower
than 2016 ($653.5 million). This included depletion expense of
$223.1 million (2016: $240.6 million).
Operating expenditures of $349.3 million were 2.3% lower than
2016 ($357.4 million), reflecting the Group's focus on cost control
and management of commercial agreements and includes net lease
charter payment credits of
$19.5 million arising from the non-availability of the Kraken
FPSO and the absence of the 2016 loss on operating expense foreign
exchange derivatives, partially offset by a full year of operations
at Scolty/Crathes, which came onstream in November 2016. The
Group's average unit operating cost for 2017 was $25.6/Boe, 4.0%
higher than 2016 ($24.6/Boe) primarily as a result of the 5.9%
reduction in production.
Realised losses on foreign currency derivatives related to
capital expenditure were $4.8 million, down 89.9% compared to 2016
(losses of $47.3 million) reflecting weaker Sterling:US Dollar
exchange rates during the year.
At 31 December 2017, the Group had moved to a net underlift
position compared to the prior year end net overlift position,
resulting in a $20.4 million credit to cost of sales (2016: charge
of $2.8 million).
Other net expenses of $17.6 million (2016: income of $51.9
million) primarily comprise net foreign exchange losses, as a
result of revaluing Sterling-denominated amounts on the balance
sheet following the strengthening of Sterling against the US
Dollar. The prior year included foreign exchange gains of $51.9
million.
EBITDA for 2017 was $303.6 million, 36.4% lower than 2016
($477.1 million) largely as a result of lower realised prices and
lower production.
The tax credit for 2017 of $66.0 million (2016: $5.2 million tax
credit), excluding exceptional items, is due predominantly to the
Ring Fence Expenditure Supplement on UK activities.
Exceptional items resulting in a net post-tax loss of $27.3
million have been disclosed separately for 2017 (2016: profit of
$63.7 million). These largely reflect tangible oil and gas non-cash
impairments of $107.2 million, primarily arising from some changes
in assumptions combined with lower production performance in the
North Sea, partially offset by the recognition of accounting for
the excess of fair value over consideration of $48.7 million
associated with the acquisition of initial interests in assets from
BP.
Net debt at 31 December 2017 was $1,991.4 million, an increase
of 10.8% compared to 2016 ($1,796.5 million) primarily as a result
of the capital expenditure programme for 2017 of $367.6 million
(2016: $609.2 million), principally at Kraken. Excluding Payment in
Kind interest ('PIK'), net debt was $1,900.9 million (2016:
$1,768.8 million).
UK corporate tax losses at the end of the year increased to
$3,121.3 million (2016: $2,893.7 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)330 336 9105
USA: +1 323 794 2093
Confirmation Code: EnQuest
Notes to editors
This announcement has been determined to contain inside
information.
ENQUEST
EnQuest is one of the largest UK independent producers in the UK
North Sea. EnQuest PLC trades on both the London Stock Exchange and
the NASDAQ OMX Stockholm. Its 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 2017, EnQuest had interests in 25 UK production
licences and was the operator of 23 of these licences.
EnQuest believes that the UKCS represents a significant
hydrocarbon basin, which continues to benefit from an extensive
installed infrastructure base and skilled labour. EnQuest believes
that its assets offer material organic growth opportunities, driven
by exploitation of current infrastructure on the UKCS and the
development of low risk near field opportunities.
EnQuest is replicating its model in the UKCS by targeting
previously underdeveloped assets in a small number of other
maturing regions; complementing its operations and utilising its
deep skills in the UK North Sea. In which context, EnQuest has
interests in Malaysia where its operated assets include the
PM8/Seligi Production Sharing Contract and the Tanjong Baram Risk
Services Contract.
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
EnQuest delivered a number of commendable operational
achievements in 2017, combined with another year of strong safety
performance. In June, first oil was achieved at the Kraken project,
a critical turning point for the Company in delivering improved
operating cash flow and marking the start of a material reduction
in the Group's capital investment requirements. While the
subsequent ramp-up in production took longer than anticipated
following initial commissioning and operational efficiency issues,
by the end of the year, this large and complex development had
produced over 40,000 Bopd (gross). In the first two months of 2018,
average gross production was around 38,000 Bopd, and has reached
50,000 Bopd with improving operational efficiency as we continue to
optimise performance.
Group production of 37,405 Boepd in 2017 was disappointing,
primarily caused by performance issues at Alma/Galia and lower than
planned production from both Kraken and Scolty/Crathes.
Despite the challenges presented by the prevailing
macro-economic environment, the Group undertook further steps to
set the platform to improve the balance sheet. The Group delivered
operating and capital expenditures in line with targets,
demonstrating the team's focus on cost control and managing
commercial agreements. EnQuest also completed a crude oil
prepayment transaction and executed a refinancing agreement for its
Tanjong Baram project in Malaysia, which combined improve the
Group's liquidity by more than $100 million.
The Group continued to pursue its vision and advance its
long-term growth plan, agreeing and completing the acquisition of
interests in the Magnus oil field and the Sullom Voe Oil Terminal
('SVT') from BP. This innovatively structured transaction required
no immediate cash payment from EnQuest and limits the Group's
exposure to negative cash flows from Magnus, capitalising on
EnQuest's strengths in realising value from maturing oil fields
with large volumes in place.
This transaction adds to the material growth potential of
EnQuest's asset base. By the end of 2017, EnQuest had a net 2P
reserve base of 210 MMboe, which represents average growth of
approximately 13% per annum since EnQuest's formation eight years
ago and a reserve life of around 17 years.
Industry context
Oil & Gas UK's Economic Report 2017 showed that since 2014
the cost of lifting oil from the North Sea has almost halved, an
improvement in unit operating costs highlighted as being greater
than the improvements achieved by any other basin. EnQuest's cost
conscious approach has been central to its business model since its
inception and the Group remains focused on driving innovative and
collaborative ways of operating to deliver cost savings across its
business. While that quantum of reduction in operating costs cannot
be repeated, a focus on improving costs and driving efficiencies is
a fundamental requirement in ensuring EnQuest is able to deliver
profitable growth over the long term.
The opportunity for long-term growth in the North Sea is clear:
The UK Oil & Gas Authority recently announced they expect 11.7
billion barrels of oil and gas to be produced from the UK
Continental Shelf ('UKCS') over the period 2016 to 2050, an
increase of 2.8 billion barrels of oil and gas from that previously
forecast; and the UK Department for Business, Energy &
Industrial Strategy forecasts oil and gas will still be supplying
around two-thirds of domestic energy demand by 2035, confirming
their place as vital sources of energy supply.
EnQuest is supportive of the UK Government's proposals to
introduce a mechanism to transfer tax history on the sale and
purchase of North Sea oil assets. We welcome the removal of a
potential tax barrier to the conclusion of deals. EnQuest has
demonstrated the dramatic and positive impact on production,
production efficiency and field life which can be achieved when
assets move into the right hands. If implemented in the right way,
these measures will be another positive step by the Government in
supporting the strategy for Maximising Economic Recovery for the
UK.
The UKCS remains a compelling basin in which to invest. It has
exciting hydrocarbon opportunities, established infrastructure,
access to a world-class supply chain and a highly skilled
workforce, all supported by a globally competitive fiscal regime. A
similar investment proposition continues to prevail in Malaysia,
where the Group has a strong partnership with PETRONAS. These
opportunities provide EnQuest with long-term potential for
growth.
The EnQuest Board
With the Board's focus on succession planning, and after
rigorous search processes, I was delighted to welcome three new
Non-Executive Directors to the Company since the start of 2017:
Carl Hughes joined the Board on 1 January 2017, having previously
been an energy and resources audit partner of Deloitte; John
Winterman, who has extensive leadership experience in global
exploration, business development and asset management, was
appointed on
7 September 2017; and Laurie Fitch, who has worked in a variety
of investment and corporate finance roles, joined us on 8 January
2018. All three bring considerable and varied expertise to the
Company and I look forward to working with them.
In July 2017, Dr Philip Nolan stepped down from his role as
Non-Executive Director, having joined the Board in 2012.
I thank Philip for his valuable contribution to the Company,
especially in its development over the past five years.
I would also like to thank Neil McCulloch, who stepped down as
Chief Operating Officer and Executive Director in December 2017,
for his unstinting contribution to EnQuest during a challenging
period for both the Company and industry.
EnQuest's people
In 2017, the Group remained focused on positioning the business
for the prevailing oil price environment, whilst at the same time
ensuring it continued to achieve its operational targets.
Management of matters pertaining to the Kraken and Magnus projects
required significant amounts of the Board and management's time and
attention, while compliance with debt covenants and review of
liquidity options also remained a priority. The Group's
achievements against these objectives have only been possible due
to EnQuest's people. The Board and I would like to express our
gratitude to everyone at EnQuest for having continued to work with
such energy and dedication to address the challenges presented in
recent years, ensuring that EnQuest can move forward, to create
further value from opportunities in maturing oil fields.
The Board and I would also like to take this opportunity to
thank all those who worked on the acquisition of assets from BP,
and extend a particularly warm welcome to our new colleagues and
contractor workforce who joined EnQuest as a result.
Strategy and governance
The Directors provide strategic guidance to executive management
and take key decisions on the implementation of the Group's
strategy. During 2017, the Board reviewed and refined the
presentation of the Company's purpose, vision, strategy and
business model. In addition, a number of 'tenets' were developed to
guide the Company's pursuit of its strategy in accordance with the
Group's appetite for risk and within its Risk Management
Framework.
Ensuring that the Board works effectively remains a key focus of
the Company. 2017 saw the Risk Committee, established in 2016,
fully embedded into the governance structure of the Company. The
primary purpose of the Risk Committee is to provide a forum for
in-depth examination of non-financial risk areas. EnQuest's
governance framework also contains several non-Board Committees,
which provide advice and support to the Chief Executive, including
an Executive Committee, Operations Committee and Investment
Committee.
The Board believes that the manner in which it conducts its
business is important and it is committed to delivering the highest
standards of corporate governance for the benefit of all of its
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 and 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.
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, and
of our suppliers, contractors, agents and partners. This year, it
has been updated with guidance on preventing the facilitation of
tax avoidance.
EnQuest's company values underpin a working environment where
people are safe, creative and passionate, with a relentless focus
on results. Inductions for all employees transferring from BP were
run in September to ensure that all those impacted understood the
EnQuest business, how we work and how they can contribute to
EnQuest's success. Alongside this, time was invested to understand
the culture of our business through an online survey and subsequent
focus groups. Following a review of the results from these
activities, the Executive Committee is working on identifying the
next steps to develop the culture and ensure that EnQuest is an
attractive place to work.
Dividend
The Company has not declared or paid any dividends since
incorporation and does not plan to pay dividends in the near
future. Any future payment of dividends is expected to depend on
the earnings and financial condition of the Company meeting the
conditions for dividend payments which the Company has agreed with
its lenders and such other factors as the Board of Directors of the
Company considers appropriate.
2018: A new chapter
In 2018, EnQuest is entering a new phase. Kraken is progressing
well, the Magnus integration and drilling programmes are well
underway, plans are being developed to enhance performance at our
other producing assets, and the period of heavy capital investment
is largely behind us. These material advances should result in
EnQuest generating positive net cash flow after investment and tax,
allowing us to continue to manage our capital structure and
liquidity position. Despite the current improvement in the near
term oil price environment, we recognise we must maintain our focus
on financial discipline, cost efficiencies and managing Group
liquidity. Consequently, it is important that we prioritise our
resources to those key projects which maximise cash flow to
facilitate debt reduction, continuing the Company's progress
towards a more sustainable balance sheet and enabling the long-term
growth of the business.
Chief Executive's report
EnQuest's priorities and performance in 2017
2017 was a transformational year for EnQuest, positioning the
Group for profitable growth and transitioning from a period of
heavy capital investment to one in which the Group can begin to
reduce its debt. The Group focused on the Kraken development,
completion of the asset acquisitions from BP, delivery against our
financial and operational targets and the effective management of
the Group's financial position.
Operational performance
EnQuest was proud to deliver first oil from Kraken on schedule
while significantly reducing full cycle gross capital expenditure.
Kraken is one of the largest developments in the North Sea in the
last ten years, comprising a phased drilling campaign of 25 wells
tied back to a complex new Floating Production, Storage and
Offloading ('FPSO') vessel. The drilling performance has been
excellent, with the first three programmes completed early and at a
lower cost than originally planned. The FPSO has taken longer than
expected to commission, leading to lower operational efficiency
than planned. A systematic process to resolve these issues has
improved uptime and, with the reservoir performing in line with
expectations, production increased throughout 2017 and into
2018.
On 1 December 2017, EnQuest completed the acquisition of initial
interests in Magnus, SVT and associated infrastructure from BP and
assumed operatorship. This large and complex transition was
achieved safely and efficiently, delivered on time and on budget,
with the integration of these assets into the EnQuest business
progressing well.
EnQuest's average production of 37,405 Boepd reflected
Electrical Submersible Pump ('ESP') performance issues at
Alma/Galia and lower than planned production from both Kraken and
Scolty/Crathes. Overall the Group's production performance was
disappointing and led to EnQuest reducing its 2017 production
guidance in August last year. However, the combination of improving
performance at Kraken, planned drilling and workover campaigns at a
number of assets and a full year's contribution from Magnus
underpins EnQuest's expectation of material production growth in
2018.
Net 2P reserves of 210 MMboe at the end of 2017 represented a
2.4% decrease on the 215 MMboe at the end of 2016. This small
decline reflects some changes in long-term assumptions, combined
with lower production performance in the North Sea, partially
offset by the Magnus acquisition related increase and better
performance in Malaysia. When EnQuest was formed in 2010, it had 81
MMboe of reserves. Our ability to exploit, develop, convert and
selectively acquire or dispose of reserves has meant that by the
end of 2017, EnQuest had produced almost the entirety of this
initial reserve base, and still has 2P reserves with a current
production life of around 17 years.
Financial performance
The Group's focus on financial discipline resulted in total
operating expenditures of $349.3 million, unit opex of $25.6/Boe
and cash capital expenditure of $367.6 million. While it is
becoming more challenging to deliver the large decreases in
operating costs of recent years, the Group will continue to pursue
further operating cost reduction initiatives.
EBITDA of $303.6 million was materially lower than 2016. This
reduction was driven by lower realised prices, which reflected the
forward prices available at the time at which the commodity hedge
programme was implemented, combined with lower production. The
commodity hedge programme resulted in realised losses of $20.6
million in 2017 compared to realised gains of $255.8 million in
2016.
EnQuest's ongoing programme of prudent measures to improve
liquidity included the completion of an $80 million oil prepayment
transaction and execution of a $37.25 million refinancing agreement
in relation to its Tanjong Baram project, which completed in
February 2018. Combined, this provides over $100 million of
additional financial resources. EnQuest continued its close
dialogue with its lending banks, agreeing a relaxation of the
Company's covenants and amending the amortisation schedule of its
Term Loan and Revolving Credit Facility; these changes provided
additional flexibility while Kraken continued to increase
production rates. EnQuest finished the year with net debt of
$1,900.9 million, excluding Payment in Kind interest.
Health, Safety, Environment and Assurance ('HSE&A')
EnQuest delivered on its commitment to continual improvement in
HSE&A performance, achieving good year-on-year improvement in
2017 with excellent results in many areas and meeting the majority
of our performance targets.
In occupational safety, our Lost Time Incident ('LTI')
performance remained strong in both Malaysia and the UK, with many
assets recording an LTI-free year. We had no reportable hydrocarbon
releases during 2017 on our UK operated assets having increased our
focus on asset integrity and implemented hydrocarbon prevention
plans across our sites. Our drive for operational excellence saw
continued focus in the UK on coaching our workforce to identify and
understand control of Major Accident Hazards ('MAH'), embedding our
life saving rules and transitioning to a new control of work tool
which enhances both system and behavioural compliance. In March,
members of the Board visited a contractor's emergency response
centre to help benchmark and refine EnQuest's own emergency
response and crisis management plans.
EnQuest's focus on HSE&A is always a priority. Under our
continual improvement programme, activities in 2018 focus further
on control of MAH and developing and empowering employees to
deliver safe results.
North Sea operations
In December, Faysal Hamza and Bob Davenport took over management
of EnQuest's North Sea operations as Interim Head of North Sea and
Managing Director, North Sea respectively.
Production in 2017 from the North Sea averaged 28,467 Boepd,
down 7.0% compared to 2016. This reduction was driven by lower
volumes from Alma/Galia reflecting ESP related well shut-ins,
storm-related production outages and natural declines. Production
at other assets was also reduced by lower water injection, natural
declines and an unscheduled shutdown in December of the third-party
operated Forties Pipeline.
Partially offsetting this decline was production from Kraken, a
full year of production from Scolty/Crathes, limited by wax in the
flowline, and the initial contribution from Magnus. Various
production enhancement activities were successfully undertaken
during the year, improving performance at a number of fields by
year end.
The Kraken development
Following first oil on 23 June 2017, production increased
throughout the second half of the year as both production and
injection wells performed in line with expectations and the
commissioning and operational efficiency issues, encountered during
the initial production build up, were addressed. The second
processing train, which was brought online during November,
assisted in bringing gross production rates to over 40,000 Bopd.
All production and water injection wells from the first three drill
centres ('DCs') have been brought online and operational efficiency
has significantly improved. Whilst production has been constrained,
FPSO charter rates have been reduced in accordance with production
levels. We continue to work with the operator to maximise
production from Kraken.
The combination of excellent delivery of the DC3 drilling
programme, lower market rates for the remaining subsea campaign and
the renegotiation of the drilling rig contract with Transocean has
resulted in significant reductions to the full cycle gross project
capital expenditure, which is now expected to be c.$2.3 billion.
This is more than 25% lower than originally sanctioned.
Magnus and Sullom Voe Oil Terminal
The acquisition is a good strategic and operational fit for
EnQuest, providing opportunities for synergies and growth. We
invest safely to realise value from opportunities presented in
maturing assets, applying our differential capabilities to deliver
high levels of production efficiency, asset life extension and cost
control. The transaction is aligned with the UK's strategy of
Maximising Economic Recovery by getting the right assets into the
right hands. Magnus is a good quality reservoir with large volumes
in place, providing opportunities for infill drilling and the
revitalisation of wells. BP's confidence in EnQuest taking over
operatorship underlines EnQuest's capabilities as an asset life
extension expert.
Malaysia operations
Production in 2017 was broadly in line with 2016 at 8,938 Boepd,
reflecting good operational uptime across PM8/Seligi and Tanjong
Baram and the execution of key work scopes, such as the compression
reliability improvement and well interventions at PM8/Seligi. Given
the natural decline rates of these mature fields, this performance
is testament to the team's capabilities in maximising hydrocarbon
recovery in advance of the Group's first drilling campaign in
PM8/Seligi, planned for 2018.
2018 performance and outlook
The Group expects material production growth in 2018 to between
50,000 and 58,000 Boepd, largely driven by performance at Kraken
and a full year's contribution from Magnus, partially offset by
natural declines elsewhere in the portfolio. Production performance
in the first two months of 2018 was strong across the portfolio,
with Kraken gross production averaging around 38,000 Bopd in this
period. Extreme cold weather in early March resulted in brief
shutdowns at a number of the Group's North Sea fields. While Kraken
was shut down, the Group has undertaken much of the workscope
previously scheduled for the planned shutdown in April and, as a
result, this planned shutdown is no longer required. The Group
continues to have planned maintenance shutdowns at a number of the
Group's fields, including Kraken, in the third quarter. During
2018, EnQuest expects to drill three wells at Magnus and two wells
at PM8/Seligi which, along with the workover programme at
Alma/Galia, should result in an improved production performance
later in the year, with the DC4 programme expected to come onstream
in 2019, sustaining Kraken production.
Unit opex is expected to be approximately $24/Boe. Cash capital
expenditure is expected to be lower than 2017 at approximately $250
million and primarily relates to drilling campaigns at Kraken,
Heather and PM8/Seligi.
With production growing, a strong focus on cost control and a
substantially reduced cash capital expenditure programme, the Group
should generate positive net cash flow which will enable it to
start reducing debt.
In January 2018, EnQuest received $30 million in cash in
exchange for agreeing to undertake the management of the physical
decommissioning at Thistle and Deveron and being liable to make
payments to BP by reference to 3.7% of the gross decommissioning
costs of these assets.
Future growth opportunities
With Kraken delivering and the Group transitioning from a period
of heavy investment, our focus is now turning towards the next
stage of EnQuest's development. The Group has significant potential
within the existing portfolio, in particular at Magnus, PM8/Seligi
and, in the longer term, Kraken. Each of these fields has
substantial reserves and resources in place and with EnQuest's
proven capabilities in enhancing hydrocarbon recovery from mature
and underdeveloped assets, the Group is well placed to deliver
long-term sustainable growth.
Operating review
North Sea operations overview
EnQuest delivered some notable achievements during the year,
particularly the delivery of first oil from Kraken on schedule and
completing the acquisition of initial interests in the Magnus oil
field, the Sullom Voe Oil Terminal ('SVT') and associated
infrastructure assets from BP.
Kraken is a landmark heavy oil development project, one of the
largest developments in the North Sea in the last ten years. The
drilling performance has been excellent, with programmes completed
early and at a lower cost than originally planned. Although there
were some initial issues with a prolonged commissioning of the
Floating Production, Storage and Offloading vessel leading to lower
operational efficiency, substantial progress has since been made
and performance continues to improve.
On 1 December 2017, EnQuest completed the acquisition of assets
from BP. Following a period of extensive preparation, the assets
and operations were transitioned safely and smoothly to EnQuest and
the integration programme is now well underway. Both assets offer
excellent opportunities for EnQuest and the wider industry and are
in the spirit of Maximising Economic Recovery in the UK Continental
Shelf. Magnus is a good operational fit and is close to EnQuest's
existing operated assets in the Northern North Sea. It has high
quality reservoirs with significant future opportunities. EnQuest
is drilling three wells in 2018 to deliver increased volumes. At
SVT, approximately
one-third of the Group's North Sea production flows through the
terminal. As such, it has the potential to play an important role
in EnQuest's future growth.
The Group's North Sea production declined to 28,467 Boepd, down
7.0% on 2016. Underperformance at Alma/Galia and natural declines
elsewhere were partially offset by a full year's contribution from
Scolty/Crathes and initial contributions from Kraken and
Magnus.
A focus on cost control and commercial agreements resulted in
operating costs being in line with the Company's expectations. Such
financial discipline is an essential part of the way in which
EnQuest does business. Unit operating costs have reduced
significantly from historical levels, particularly when the price
of oil was above $100/bbl, but the Group recognises the need to
continue to work on delivering further cost efficiencies.
Northern North Sea operations
Daily average net production:
- 2017: 15,627 Boepd*
- 2016: 18,885 Boepd
* Includes net production from Magnus since the acquisition on 1
December 2017, averaged over the 12 months to the end of December
2017.
2017 performance summary
Production in 2017 of 15,627 Boepd was 17.3% lower than 2016.
This reduction was primarily driven by lower water injection at
Heather/Broom and Thistle/Deveron, combined with natural declines
at these and the Dons fields. Production efficiency at
Heather/Broom and the Dons fields was very good, and the
contribution from Magnus also helped mitigate the reduced
production.
During the year, work programmes to improve the reliability of
water injection on Heather/Broom, Thistle/Deveron and the Dons were
successful, delivering improved performance by year end. Water
injection was reinstated at the Dons in December 2017 following the
replacement of the water injection pipelines. On Thistle, work was
undertaken to improve the reliability of water injection and shut
off areas of the reservoir in which high volumes of water were
being produced. The resulting improved water injection performance
significantly increased reservoir pressure. Shutting off some water
production from four wells that produced high levels of water
increased oil production by around a thousand barrels per day,
doubling the target uplift from this work scope. When combined with
better plant uptime, these programmes enabled Thistle production
rates to finish the year strongly.
Reservoir performance and production were above expectations at
Don Southwest, with production improving chemical treatments
completed at West Don and Don Southwest.
Average gross production of c.16,000 Boepd from Magnus during
the full year 2017 was similar to 2016; a good result during this
intensive period of preparation for transition. Upon completion of
the acquisition on 1 December 2017, EnQuest became duty holder and
operator.
As part of EnQuest's asset life extension strategy, a series of
idle well reservoir abandonments were successfully undertaken at
Thistle and Heather to reduce integrity risks and provide
opportunities for future drilling of infill wells. The abandonment
programme on Heather partially abandoned legacy wells which should
safeguard sustained high water injection reservoir efficiency. The
programme was well executed, delivered ahead of schedule and under
budget. This allowed the team to include an additional well within
the programme cost estimate. These programmes, co-funded by
EnQuest's partners, demonstrate EnQuest's ability to execute
low-cost well work and is an important new component of the
strategy to extend the lives of these fields, benefiting all
stakeholders in these fields.
Asset data and 2018 work programme
Thistle/Deveron
-- Working interest at end 2017: 99%
-- Decommissioning related costs: 3.7% (as defined below)(1)
-- Fixed steel platform
(1) EnQuest is liable for the decommissioning costs associated
with investment since it assumed operatorship, with the balance
remaining with the former owners. Following the exercise of the
Thistle decommissioning option in January 2018, EnQuest will
undertake the management of the physical decommissioning of Thistle
and Deveron and is liable to make payments to BP by reference to
3.7% of the gross decommissioning costs of Thistle and Deveron.
EnQuest has an outstanding option to receive $20 million in cash in
exchange for making payments by reference to a further 2.4% of the
gross decommissioning costs of the Thistle and Deveron fields.
2018 and beyond
A shutdown is planned in Q3, the timing of which is driven by
the third-party shutdown of the Cormorant Alpha pipeline, which is
Thistle's oil export route. EnQuest will co-ordinate this shutdown
with its own planned programme of maintenance work on Thistle.
The well abandonment programme is continuing in 2018.
The Dons fields
-- Working interest at end 2017:
- Don Southwest 60%
- Conrie 60%
- West Don 78.6%
- Ythan 60%
-- Decommissioning liabilities: As per working interests
-- Floating production unit with subsea wells
2018 and beyond
A shutdown is planned in Q3, the timing of which is driven by
the third-party shutdown of the Cormorant Alpha pipeline, which is
the Dons' oil export route. EnQuest will co-ordinate this shutdown
with its own planned programme of maintenance work on the Dons.
A water injection optimisation programme will be undertaken
during 2018.
Heather/Broom
-- Working interest at end 2017:
- Heather 100%
- Broom 63%
-- Decommissioning liabilities:
- Heather 37.5%
- Broom 63%
-- Fixed steel platform
2018 and beyond
Additional drilling is taking place on Heather. The H-67
sidetrack was completed in March following initial spud in January,
while further well abandonments will take place later in the
year.
A maintenance shutdown is planned in Q2.
Magnus
-- Working interest at end 2017: 25%
-- Decommissioning related costs: 7.5% (as defined below)(1)
-- Fixed steel platform
(1) BP has retained the decommissioning liability in respect of
the existing Magnus wells and infrastructure. EnQuest will pay BP
additional deferred consideration by reference to 7.5% of BP's
actual decommissioning costs on an after-tax basis. The additional
consideration payable is capped at the amount of cumulative
positive cash flows received by EnQuest from Magnus, SVT and the
associated infrastructure assets.
2018 and beyond
The post-acquisition integration programme will continue into
2018, ensuring the team understands the Group's culture, processes
and controls, and how the team can contribute to EnQuest's
success.
Following an upgrade of the drilling rig, the 2018 drilling
programme includes a well intervention plan (logging and
potentially also perforations) then two production wells and one
injection well set to come onstream during 2018. In early Q1, the
first wireline intervention was successfully completed, prior to
the spudding of the first new sidetrack well.
New production efficiency enhancement opportunities are also
being assessed.
Sullom Voe Oil Terminal
A strategic infrastructure hub
SVT was commissioned in 1978 and receives East of Shetland
('EoS') oil via the Brent Pipeline System, which services Brent,
Thistle, Northern Producer, Alwyn and TENCCA, and the Ninian
Pipeline System, which services Ninian, Magnus and Heather. Since
1998, the terminal has also provided services to West of Shetland
('WoS') fields, including Schiehallion, Clair and Foinaven. Gas
from these three fields is 'sweetened' at SVT before being shipped
to Magnus, for Enhanced Oil Recovery and onward export. The
terminal also now processes condensate from the Laggan-Tormore
development.
Following the safe and efficient transfer of operatorship to
EnQuest on 1 December 2017, steady operations have continued.
Building on the work that BP as operator and EnQuest and other
owners have undertaken in recent years, EnQuest is targeting cost
improvements and exploring terminal life extension opportunities
which could benefit wider Northern North Sea and WoS
operations.
Central North Sea operations
Daily average net production:
- 2017: 8,131 Boepd
- 2016: 11,718 Boepd*
* Includes net production from Scolty/Crathes since first oil on
21 November 2016, averaged over the 12 months to the end of
December 2016.
2017 performance summary
Production in 2017 of 8,131 Boepd was 30.6% lower than 2016.
This reduction was primarily driven by lower volumes at Alma/Galia
reflecting Electric Submersible Pump ('ESP') related well shut-ins,
storm-related production outages and natural declines. Field
performance improved in the second half of the year following
completion of the optimisation projects for power, produced water
and sea water injection.
Good production has been delivered from the Greater Kittiwake
Area ('GKA'), with high levels of plant uptime and production
efficiency. The GKA work programme was focused on optimising
production across the assets, including replacement of the
Mallard/Gadwall water injection flowline and the E gas compressor
crank shaft. The GKA team delivered a good HSE&A performance
and was proud to have delivered 12 years of operations without an
LTI.
In line with previous updates, the full year contribution from
Scolty/Crathes was limited due to wax in the flowline. These wax
issues continue to be managed with chemical and lift gas
treatments. Full year production uptime has been very high with the
reservoir performing well. The unscheduled shutdown in December of
the third-party operated Forties Pipeline resulted in the GKA and
Scolty/Crathes fields being shut down for approximately three
weeks, during which time opportunistic maintenance work was
undertaken.
Asset data and 2018 work programme
Greater Kittiwake Area ('GKA')
-- Working interest at end 2017 of 50% in each of:
- Kittiwake
- Grouse
- Mallard
- Gadwall
- Goosander
-- Decommissioning liabilities:
- Kittiwake 25%
- Mallard 30.5%
- Grouse, Gadwall and Goosander 50%
-- Fixed steel platform
-- 100% interest in export pipeline from GKA to Forties Unity
platform
2018 and beyond
A maintenance shutdown is scheduled for Q3 2018. The work
programme includes the installation of a new gas compressor.
Evaluation of the potential from the Eagle discovery (100%
EnQuest) is ongoing, with the licence having been extended in early
2018.
Scolty/Crathes
-- Working interest at end 2017 of 50% in each of:
- Scolty
- Crathes
-- Decommissioning liabilities: As per working interests
-- Tied back to the Kittiwake platform
2018 and beyond
A maintenance shutdown is scheduled for Q3 2018. EnQuest
continues to undertake technical work with its partners in
developing a permanent solution to debottleneck production in
2019.
Alma/Galia
-- Working interest at end 2017:
- 65% in both fields
-- Decommissioning liabilities: As per working interest
-- Floating Production, Storage and Offloading unit ('FPSO')
with subsea wells
2018 and beyond
A well workover campaign is scheduled for the summer of 2018,
aiming to increase production levels by replacing three failed
ESPs.
Alba (non-operated)
The Alba oil field is operated by Chevron.
-- Working interest at end 2017: 8%
-- Decommissioning liabilities: As per working interest
-- Fixed steel platform
The Kraken development
-- Daily average net production:
- 2017: 4,709 Boepd(2)
- 2016: N/A
(2) Net production since first oil on 23 June, averaged over the
12 months to the end of December 2017.
2017 performance summary
The Kraken FPSO arrived in the North Sea in early January and
was on-station and securely moored by mid-February, with first oil
delivered on 23 June 2017. The four wells from the first drill
centre ('DC') and the three wells from DC2 produced at initial
gross rates above expectations and with stabilised flow rates which
confirmed the field development plan. Water injection wells
performed in line with expectations.
During the period after first oil, prolonged commissioning of
the complex Kraken FPSO vessel led to lower than expected
production efficiency and to initial production volumes being lower
than expected. EnQuest continued with its plan of bringing wells
onstream in a phased manner, in line with good reservoir management
practices aimed at maximising long-term productivity and value. The
second processing train, which was brought online during November,
assisted in bringing gross production rates to over 40,000 Bopd.
Since late December, all DC3 wells have been brought online and
operational uptime has improved.
Following the excellent delivery of the DC3 drilling programme
and lower market rates for the remaining subsea campaign, full
cycle gross Kraken project capital expenditure was further reduced
during 2017.
Cargo offloads started in September and one was successfully
completed in each subsequent month. The quality of the crude has
been well received by buyers. By as early as November, a sale of
cargo had been contracted at a discount to Brent of less than
$5/bbl, this level of pricing being achieved earlier than
targeted.
Asset data and 2018 work programme
-- Working interest at end 2017: 70.5%.
-- Decommissioning liabilities: As per working interest
-- Floating Production, Storage and Offloading ('FPSO') unit
with subsea wells
2018 and beyond
Average gross production for the first two months of 2018 was
around 38,000 Bopd, and has reached the targeted 50,000 Bopd, with
improving production efficiency as we continue to optimise
performance. The DC4 well campaign, which was not anticipated to
impact 2018 production, is expected to commence in the second half
of 2018, coming onstream in 2019 to sustain production.
Extreme cold weather in early March resulted in Kraken being
shut down. During this period, the Group has undertaken much of the
previously planned April shutdown workscope and, as a result, this
planned shutdown is no longer required. EnQuest continues to have a
summer shutdown planned for one week in September.
In early 2018, EnQuest agreed renegotiated terms with Transocean
for the Transocean Leader drilling rig, reducing both the contract
duration and the day rates, saving c.$60 million of net cash
payments for capital expenditure in 2019. Full cycle gross project
capital expenditure has been reduced by approximately $100 million
and is now expected to be c.$2.3 billion, more than 25% lower than
originally sanctioned.
Malaysian operations
-- Daily average net production:
- 2017: 8,937 Boepd (working interest): 5,884 Boepd (entitlement)
- 2016: 9,148 Boepd (working interest): 6,426 Boepd (entitlement)
2017 performance summary
At PM8/Seligi, EnQuest continued to enhance production by
investing in low-cost well interventions and facility projects to
improve production efficiency, including gas compression package
major overhauls, well test improvements with Multi-Phase Flow
Meters and process simplifications to improve overall reliability.
In addition, robust maintenance and integrity inspection campaigns
of platform structures, topsides and subsea pipelines continued to
ensure safe operations.
During 2017, the first new drilling projects were defined for
execution in 2018, and significant progress was made on rebuilding
of static and dynamic reservoir simulation models in support of
longer-term field redevelopment. At Tanjong Baram, the focus
remained on steady, safe and low-cost operations with high levels
of production efficiency and uptime throughout the year.
Asset data and 2018 work programme
PM8/Seligi
-- Working interest at end 2017: 50%
-- Decommissioning liabilities:
- PM8 50%
- Seligi 50% of partial liability allocated based on ratio of
remaining oil reserves and to estimated ultimate recovery
In addition to the main production platform and separate gas
compression platform, there are 11 minimum facility satellite
platforms tied back to the main platform.
2018 and beyond
EnQuest will commence its first drilling campaign with two
PM8/Seligi commitment wells (appraisal and development) to be
drilled around the middle of 2018, with first production in Q3.
Idle well restoration and surveillance campaigns are planned for Q2
and Q3.
A maintenance shutdown is scheduled in Q3.
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.
Tanjong Baram
-- Working interest at end 2017: 70%
-- Decommissioning liabilities: None
2018 and beyond
Maintenance shutdowns are scheduled in Q1 and Q3.
Financial review
(all figures quoted are in US Dollars and relate to Business
performance unless otherwise stated)
Financial overview
EnQuest has continued to focus on project execution and
financial discipline. The Company delivered first oil from the
Kraken development in June 2017 and completed the acquisition of
initial interests in the Magnus oil field and Sullom Voe Oil
Terminal ('SVT') through an innovatively structured transaction in
December. EnQuest also continues to focus on cost control and cash
management, and as operating cash flows grow and capital
expenditure reduces, this should facilitate reductions in debt.
These key milestones, along with the effective management of the
Group's liquidity position, continue to ensure that the Company is
well placed to deliver value to stakeholders in the medium and long
term.
Production on a working interest basis decreased by 5.9% to
37,405 Boepd, compared to 39,751 Boepd in 2016. Lower production at
Alma/Galia and natural declines at the Group's other North Sea
fields were partially offset by production from Kraken and a full
year of production from Scolty/Crathes, which came onstream in
November 2016.
Total revenue for 2017 was $635.2 million, 25.2% lower than 2016
($849.6 million). This was as a result of lower realised oil
prices, reflecting the forward prices available at the time at
which the commodity hedge programme was implemented, combined with
lower production. The commodity hedge programme resulted in
realised losses of
$20.6 million in 2017 compared to realised gains of $255.8
million in 2016.
The Group's operating expenditures of $349.3 million were 2.3%
lower than 2016 ($357.4 million), but unit operating costs
increased by 4.0% to $25.6/Boe as a result of lower production.
Business performance
-----------------------
2017 2016
$ million $ million
Profit from operations before tax and finance income/(costs) 47.3 237.1
Depletion and depreciation 227.6 244.6
Net foreign exchange (gain)/loss 23.9 (51.9)
Realised (gain)/loss on FX derivatives related to capital expenditure(1) 4.8 47.3
EBITDA 303.6 477.1
----------- ----------
(1) Realised (gain)/loss on FX derivatives are 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.
EBITDA for 2017 was $303.6 million, down 36.4% compared to 2016
($477.1 million), primarily as a result of lower revenue.
Business performance loss after tax for 2017 was $33.6 million
(2016: profit of $121.5 million). After re-measurements and
exceptional items, the Group recorded a net loss of $60.8 million
(2016: net profit of $185.2 million).
Reflecting the ongoing investments EnQuest has made to develop
its assets, notably Kraken, EnQuest's net debt increased from
$1,796.5 million at the end of 2016 to $1,991.4 million at 31
December 2017. This includes $90.5 million of interest that has
been capitalised to the principal of the facilities pursuant to the
terms of the Group's November 2016 refinancing ('PIK').
Net debt/(cash)
--------------------------
31 December 31 December
2017 2016
$ million $ million
Bonds(1) 944.9 868.7
Multi-currency Revolving Credit Facility(1) ('RCF') 1,100.0 1,037.5
Tanjong Baram Project Finance Facility(1) 8.5 24.9
Mercuria Prepayment Facility 75.5 -
SVT Working Capital Facility 25.6 -
Other loans(1) 10.0 40.0
Cash and cash equivalents (173.1) (174.6)
Net debt 1,991.4 1,796.5
============ ============
(1) Stated excluding accrued interest and excluding the net-off
of unamortised fees (refer to note 19 of the consolidated financial
statements).
There are no significant debt maturities until October 2018,
when a single amortisation of the RCF of $270 million is due.
As at 31 December 2017, total cash and available facilities
totalled $244.4 million, excluding $26.5 million of cash from the
ring fenced working capital facility associated with SVT (2016:
$330.9 million excluding $nil cash from the ring fenced SVT working
capital facility).
UK corporate tax losses at the end of the year increased to
$3,121.3 million. In the current environment, no material
corporation tax or supplementary corporation tax is expected to be
paid on UK operational activities for the foreseeable future. The
Group 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
Net working interest production of 37,405 Boepd was 5.9% lower
than 2016 (39,751 Boepd). This reduction primarily reflects the
impact of ESP performance issues at Alma/Galia, natural declines in
the Group's assets where there has been no recent drilling,
partially offset by the impact of commencement of production at
Kraken in June 2017 and a full year of production from
Scolty/Crathes, which achieved first oil in November 2016.
On average, market prices for crude oil in 2017 were higher than
in 2016. The Group's blended average realised oil price excluding
the impacts of hedging was $53.9/bbl for 2017, 21.8% higher than
2016 ($44.3/bbl). Revenue is predominantly derived from crude oil
sales and for 2017, crude oil sales totalled $637.0 million, 10.2%
higher than 2016 ($577.8 million). The increase in revenue
reflected higher market prices for crude oil, partially offset by
lower production. Revenue from the sale of condensate and gas was
$2.8 million (2016: $3.6 million) while tariffs and other income
generated $16.0 million (2016: $12.4 million).
The Group's commodity hedges and other oil derivatives generated
$20.6 million of realised losses (2016 income: $255.8 million),
including $10.4 million of non-cash amortisation of option premiums
(2016: $31.2 million).
Cost of sales
Business performance
-----------------------
2017 2016
$ million $ million
Production costs 287.1 279.7
Tariff and transportation expenses 62.2 58.1
Realised (gain)/loss on FX derivatives related to operating costs - 19.6
----------- ----------
Operating costs 349.3 357.4
Realised (gain)/loss on FX derivatives related to capital expenditure 4.8 47.3
Credit/(charge) relating to the Group's lifting position and inventory (20.4) 2.8
Depletion of oil and gas assets 223.1 240.6
Other cost of sales 12.7 5.4
----------- ----------
Cost of sales 569.5 653.5
----------- ----------
Operating cost per barrel(1) $/Boe $/Boe
-Production costs 21.0 20.4
-Tariff and transportation expenses 4.6 4.2
25.6 24.6
----------- ----------
(1) Calculated on a working interest basis.
Cost of sales were $569.5 million for the year ended 31 December
2017, 12.9% lower than 2016 ($653.5 million). Operating costs
decreased by $8.1 million, reflecting the benefit of a weaker
Sterling exchange rate and net lease charter payment credits of
$19.5 million arising from the non-availability of the Kraken FPSO,
partially offset by a full year of operations at Scolty/Crathes.
The Group's average unit operating cost has increased by 4.0% to
$25.6/Boe, primarily due to the 5.9% reduction in production
volumes.
At 31 December 2017, the Group had moved to a net underlift
position compared to the prior year end net overlift position,
resulting in a $20.4 million credit to cost of sales (2016: charge
of $2.8 million). The Group's change in lifting position and
inventory reflected the unwind of the overlift balance that had
accrued at 31 December 2016, primarily on Thistle and GKA,
partially offset by the unwind of underlift at Alma/Galia and the
build up of an overlift at Scolty/Crathes.
Depletion expense of $223.1 million was 7.3% lower than 2016
($240.6 million), reflecting lower production in 2017. The average
unit depletion rate decreased slightly from $16.6/Boe to
$16.3/Boe.
Other cost of sales of $12.7 million were higher than 2016 ($5.4
million), principally driven by the impact of higher oil prices on
the supplemental payment due on profit oil in Malaysia.
General and administrative expenses
General and administrative expenses were $0.8 million (2016:
$10.9 million), reflecting the Group's ongoing efforts to reduce
costs across the organisation.
Other income and expenses
Net other expenses of $17.6 million (2016: income of $51.9
million) primarily comprises net foreign exchange losses, which
relate to the revaluation of Sterling denominated amounts in the
balance sheet following the strengthening of Sterling against the
US Dollar, offset by one-off general and administration recovery
impacts. The prior year income comprised almost entirely of net
foreign exchange gains.
Finance costs
Finance costs of $149.0 million were 21.9% higher than 2016
($122.2 million). The charges include $137.9 million of bond and
loan interest payable (2016: $110.5 million), $13.5 million
unwinding of discount on provisions and liabilities, largely in
respect of decommissioning (2016: $14.2 million), $2.8 million
amortisation of arrangement fees for the bank facilities and bonds
(2016: $5.9 million) and other financial expenses of $5.9 million
(2016: $10.5 million), primarily commitment and letter of credit
fees.
The Group capitalised interest of $42.3 million in 2017 in
relation to the interest payable on borrowing costs on its capital
development projects, primarily the Kraken development (2016: $55.3
million).
In June 2017, in line with first oil from Kraken, the Group's
lease for the FPSO vessel from Armada Kraken PTE Limited ('BUMI')
commenced. Finance lease interest of $31.3 million has been
recognised within finance costs. In 2016, $36.5 million of finance
costs related to the amortisation of put option premium related to
the Group's oil hedge portfolio were recognised. No corresponding
charge existed in 2017 as no put options had been used to hedge
2017 production.
Finance income
Finance income of $2.2 million (2016: $1.4 million) includes
$1.8 million from the unwind of the discount on financial assets
(2016: $1.0 million) and $0.4 million of bank interest receivable
(2016: $0.3 million).
Taxation
The tax credit for 2017 of $66.0 million (2016: $5.2 million tax
credit), excluding exceptional items, is mainly due to the Ring
Fence Expenditure Supplement ('RFES') on UK activities.
Remeasurement and exceptional items
Revenue included unrealised losses of $7.7 million in respect of
the mark to market movement on the Group's commodity contracts
(2016: unrealised loss of $51.5 million).
Non-cash impairment charge on the Group's oil and gas assets
arising from changes in assumptions combined with lower production
performance in the North Sea totalled $172.0 million (2016:
reversal of non-cash impairment of $147.9 million).
Other income and expense included the recognition of the
accounting for the excess of fair value over consideration of $16.1
million associated with the Thistle decommissioning option and
$10.3 million associated with the accounting impact of the
acquisition of initial interests in assets from BP and the related
discounted purchase option valuation of $22.3 million (see note
29). Other items include a $1.3 million gain from the disposal of
Ascent Resources loan notes, a $10.3 million charge arising from a
cost recovery settlement in Malaysia, a $6.4 million charge arising
from the cancellation of contracts and a $2.8 million provision in
relation to restricted cash.
A tax credit of $117.0 million (2016: charge of $37.3 million)
has been presented as exceptional, representing the tax impact of
the above items, together with a net write-back of $47.2 million of
tax losses which had been previously impaired.
Earnings per share
The Group's reported basic loss per share was 5.4 cents (2016:
earnings per share of 22.7 cents) and reported diluted loss per
share was 5.4 cents (2016: earnings per share of 22.1 cents).
Cash flow and liquidity
Net debt at 31 December 2017 amounted to $1,991.4 million,
including PIK of $90.5 million, compared with net debt of $1,796.5
million at 31 December 2016, including PIK of $27.7 million. The
Group has remained in compliance with financial covenants under its
debt facilities throughout the year and managing ongoing compliance
remains a priority. Where necessary or appropriate, the Group has
and would seek waivers and/or consents.
The movement in net debt was as follows:
Net debt 1 January 2017 (1,796.5)
Operating cash flows 301.8
Cash capital expenditure (367.6)
Proceeds on disposal of Ascent Resources loan notes 3.6
Net interest and finance costs paid (52.0)
Non-cash capitalisation of interest to principal of bond and credit facility (PIK) (62.8)
Other movements, primarily net foreign exchange loss on cash and debt (17.9)
Net debt 31 December 2017 (1,991.4)
------------------------------------------------------------------------------------ ----------
The Group's reported operating cash flows for the year ended 31
December 2017 were $301.8 million, down 20.5% compared to 2016
($379.5 million). The main driver for this reduction is the reduced
contribution from commodity price hedging, where total cash flows
received in 2017 were $3.6 million as compared to $198.8 million
for 2016. This reduced cash flow was partially offset by the impact
of higher market oil prices on revenue and reduced operating and
general and administrative expenses.
Cash outflow on capital expenditure is set out in the table
below:
Year ended Year ended
31 December 2017 31 December 2016
$ million $ million
North Sea development expenditure 355.3 592.2
Malaysia development expenditure 3.1 8.2
Exploration and evaluation capital expenditure 9.2 8.9
Other capital expenditure - 1.4
Other proceeds - (1.5)
367.6 609.2
================== ============================
In the North Sea, a total of $252.2 million was spent during the
year on the Kraken development, primarily related to drilling and
completing 14 wells across Drill Centres ('DC') 2 and 3. Excellent
drilling performance resulted in the delivery of the wells ahead of
schedule. In early 2018, EnQuest also agreed renegotiated terms for
the drilling rig, reducing both the contract duration and day
rates. Full cycle gross project capital expenditure is now expected
to be c.$2.3 billion. The remaining 2017 cash capital expenditure
is primarily the settlement of deferred invoices in respect of the
Alma/Galia and Scolty/Crathes developments and the Eagle
discovery.
Balance Sheet
The Group's total asset value has increased by $1,112.5 million
to $5,038.5 million at 31 December 2017
(2016: $3,926.0 million), mainly attributable to the recognition
of the $772.0 million Kraken FPSO finance lease asset in property,
plant and equipment ('PP&E'). Net current liabilities have
increased to $377.9 million as at 31 December 2017 (2016: $45.1
million), primarily driven by the scheduled $270 million RCF
amortisation due in October 2018 and the impact of the Kraken FPSO
finance lease commitments due within one year.
Property, plant and equipment
PP&E has increased by $885.2 million to $3,848.6 million at
31 December 2017 from $2,963.4 million at
31 December 2016 (see note 10).
This increase is explained by the recognition of the Kraken FPSO
finance lease in June 2017 of $772.0 million, capital additions to
PP&E of $323.6 million, additions of $124.5 million for the
acquisition of interests in the Magnus oil field, SVT and
associated infrastructure assets (see note 29), a net increase of
$66.2 million for changes in estimates for decommissioning and
other provisions, including the KUFPEC cost recovery provision,
offset by depletion and depreciation charges of $229.2 million and
non-cash impairments of $172.0 million.
The PP&E capital additions during the period, including capitalised interest, are set out 2017
in the table below:
$ million
Kraken 275.8
Thistle/Deveron 15.1
Other North Sea 30.4
Malaysia 2.3
323.6
==========
Intangible oil and gas assets
Intangible oil and gas assets marginally increased to $52.1
million at 31 December 2017 from $50.3 million at
31 December 2016 (see note 12).
Trade and other receivables
Trade and other receivables have increased by $25.1 million to
$227.8 million at 31 December 2017 compared with $202.7 million at
31 December 2016. The increase relates mainly to the timing of
crude oil sales, increased underlift and higher oil prices,
partially offset by other working capital movements (see note
15).
Cash and net debt(1)
The Group had $173.1 million of cash and cash equivalents at 31
December 2017 and $1,991.4 million of net debt, including PIK of
$90.5 million (2016: $174.6 million of cash and cash equivalents
and $1,796.5 million of net debt, including PIK of $27.7 million).
Net debt(1) comprises the following liabilities:
-- $224.1 million principal outstanding on the GBP155 million
retail bond (2016: $191.3 million) including $14.9 million of
interest capitalised as an amount payable in kind ('PIK') in the
year;
-- $720.8 million principal outstanding on the high yield bond,
including capitalised interest (PIK) of $70.8 million pursuant to
the Restructuring (2016: $677.5 million and $27.5 million
respectively);
-- $1,100.0 million carrying value of credit facility,
comprising amounts drawn down of $1,095.2 million and PIK interest
of $4.8 million (2016: $1,037.5 million comprising amounts drawn
down of $1,037.3 million and PIK interest of $0.2 million);
-- $25.6 million relating to the SVT Working Capital Facility (2016: $nil);
-- $75.5 million relating to the Mercuria Prepayment Facility (2016: $nil);
-- $10.0 million outstanding from a trade creditor loan (2016: $40.0 million); and
-- $8.5 million principal outstanding on the Tanjong Baram
Project Finance Facility (2016: $24.9 million).
(1) Net debt excludes accrued interest and the net-off of
unamortised fees (see note 19 of the consolidated financial
statements).
Provisions
The Group's decommissioning provision increased by $145.4
million to $639.3 million at 31 December 2017
(2016: $493.9 million). The movement is explained by additions
to Kraken of $63.6 million based on drilling and developments
carried out in the period, an increase of $80.9 million due to
changes in estimates (including the impact of oil prices and
foreign exchange rates) and $11.5 million unwinding of discount,
partially offset by reductions of
$10.6 million for decommissioning carried out in the period.
Other key movements in provisions during the period include the
addition of $66.6 million of outstanding contingent consideration
for the acquisition of the Magnus oil field, SVT and associated
infrastructure assets from BP completed in December 2017 (see note
29) and $10.3 million for PM8/Seligi cost recovery. This is largely
offset by a $77.8 million reduction for changes in estimates and
the fair value of cost recovery provisions combined with payments
of $9.0 million contingent consideration to Centrica pursuant to
the Greater Kittiwake Area acquisition agreement and $5.5 million
for the final settlement due to Cairn under the carry agreement
(see note 22).
Income tax
The Group had no UK corporation tax or supplementary corporation
tax liability at 31 December 2017, which remains unchanged from 31
December 2016. The income tax asset at 31 December 2017 represents
UK corporation tax receivable in relation to non-upstream
activities and the income tax payable is in relation to the Group's
activities in Malaysia (see note 7).
Deferred tax
The Group's net deferred tax asset has increased from $191.7
million at 31 December 2016 to $335.6 million at
31 December 2017. The increase is mainly due to the RFES,
together with the recognition of $9.7 million of previously
derecognised tax losses. Total UK tax losses carried forward at the
year end amount to $3,121.3 million
(2016: $2,893.7 million) (see note 7).
Trade and other payables
Trade and other payables of $446.1 million at 31 December 2017
are $6.7 million lower than at 31 December 2016 ($452.8 million).
$367.3 million are payable within one year (2016: $410.2 million)
and $78.8 million are payable after more than one year (2016: $42.6
million). The decrease in current payables mainly reflects the
settlement of deferred invoices and an $11.9 million reduction in
the overlift position, offset by accruals (see note 23).
Other financial liabilities
Other current financial liabilities have increased by $16.9
million to $61.2 million. The increase primarily relates to mark to
market movements on the Group's commodity derivatives following the
strengthening of the oil price, waiver fees payable to credit
facility lenders due in March 2018 (previously non-current) and the
Group's liability to carry PETRONAS Carigali for its share of
exploration or appraisal well commitments in relation to the
PM8/Seligi asset in Malaysia (previously non-current).
Other non-current financial liabilities of $7.1 million (2016:
$19.8 million) relate mainly to the Magnus field liabilities
acquired as part of the transaction that completed in December 2017
(see note 20).
Financial risk management
Oil price
The Group is exposed to the impact of changes in Brent crude oil
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 reinvestment in capital
programmes that are driving business growth.
In November 2017, the Group entered into an 18-month collar
structure for the Mercuria Prepayment Facility of
$80 million (see note 19). Repayment will be 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 per barrel
and a cap of approximately $64 per barrel. Losses totalling $5.2
million were included within unrealised revenue in the income
statement.
The marking to market of the Group's open contracts as at 31
December 2017 gave rise to a loss of $29.2 million in respect of
fixed price swap contracts for 4.15 MMbbls of 2018 production at a
weighted average price of $59.1/bbl (2016: loss of $40.5 million in
respect of fixed price swap contracts for 5.99 MMbls of 2017
production at a weighted average price of $51.3/bbl).
During 2016, the Group entered into commodity hedging contracts
to hedge a portion of its 2017 production against fluctuations in
oil prices. This hedging generated cash outflows of $0.9 million
(including $2.0 million outflow in respect of the settlement of
December 2016 hedges) while revenue and other operating income
included a loss of
$31.1 million during 2017. These amounts were mostly in respect
of the settlement of swaps in respect of 6.0 MMbbls, plus the
maturity of certain other commodity derivatives. The Group's
marketing and trading activities, which are designed to manage
price exposures on certain individual cargos, generated $6.7
million of cash, and contributed $10.6 million to revenue and other
operating income.
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.
During 2017, the Group has continued to use an exchange
structure to manage risk. The first exchange structure was entered
into in 2016 and allowed the counterparty to elect to sell GBP47.5
million to EnQuest at an exchange rate of $1.4:GBP1, or purchase
1.3 MMbbls of oil at $58/bbl. This structure expired on 30 June
2017. The second exchange structure allowed the counterparty to
elect to sell GBP66.0 million to EnQuest at an exchange rate of
$1.2:GBP1 or purchase 1.5 MMbbls of oil at $60/bbl. This structure
expired on 31 December 2017. As a result of these exchange
structures, $4.4 million was recognised within other foreign
currency contracts and no costs within other operating income
during the year (2016: $9.3 million and $nil respectively).
EnQuest continually reviews its currency exposures and when
appropriate looks at opportunities to enter into foreign exchange
hedging contracts.
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 any
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, general and
administrative and capital expenditures in 2017 and 2018. At 31
December 2017, the Group had cash and available bank facilities of
$244.4 million, excluding $26.5 million of cash from the ring
fenced working capital facility associated with SVT.
The Group's business plan ('Base case'), which underpins this
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.$67/bbl
throughout 2018 and c.$63/bbl for the first quarter of 2019. This
has been further stressed 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 Group has historically reviewed farm down options and
continues to do so. The Base case and Downside case indicate that
the Company is covenant compliant and will be 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 there be any liquidity shortages or covenant breaches due
to events not included in the Base or Downside cases, the Directors
believe that a number of mitigating actions, including assets 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.
Nevertheless, there remains the risk that the Group is unable
successfully to achieve farm down options, other potential asset
sales or other funding options. The risk represents a material
uncertainty that may cast doubt upon the Group's ability to
continue to apply the going concern basis of accounting.
Notwithstanding the material uncertainty 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
will be able to continue in operation and meet its commitments as
they fall due over the going concern period. Accordingly, the
Directors therefore 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 2021. This assessment has taken into
account the Group's financial position as at March 2018, 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 in the
Risks and uncertainties section of this statement.
The period of three years is deemed appropriate as it provides a
sufficient time horizon to assess the performance of the Kraken
project and covers the period within which the Group's Facility
will be largely repaid.
Based on the Group's projections, the Directors have a
reasonable expectation that the Group will be able to continue in
operation and meet its liabilities as they fall due over the period
to March 2021.
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 business plan
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 a recent forward curve. The Base case reflects significant steps
already undertaken to reduce operating and capital expenditure.
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 material 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 c.7.5 million barrels
of 2018 production at an average price of c.$62/bbl. As further
mitigation, the Directors, in line with Group policy, will continue
to pursue hedging at the appropriate time and price.
Kraken production and related asset disposal
All production and injector wells on the first three Drilling
Centres ('DC') are onstream and are, in aggregate, operating as per
the Field Development Plan ('FDP'). Both production processing
trains are also onstream. Kraken gross production averaged around
38,000 Bopd (gross) in the first two months of 2018 and has already
delivered the targeted 50,000 Bopd (gross) as planned. The
remaining development wells (DC4) will be drilled from Q4 2018 and
onstream from Q1 2019, concluding the execution of the FDP. On the
basis of this performance, and subject to delivering on the Group's
plans to further optimise production and improving plant uptime,
EnQuest expects to deliver sustained production rates.
The Group has historically reviewed farm down options and
continues to do so.
Access to funding
The Group's Facility contains certain covenants (based on the
ratio of indebtedness incurred under the term loan and revolving
facility to EBITDA, finance charges to EBITDA, and 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 $1.125 billion
Tranche A Term Loan and a further Tranche B $75 million Revolving
Credit Facility (collectively the 'Facility'). Across the Facility,
$98 million remains available at 31 December 2017.
In addition, the maturity dates of the $721 million high yield
bond and the GBP166 million retail notes (both figures inclusive of
the PIK notes), have been amended to April 2022, with an option
exercisable by the Group (at its absolute discretion) to extend the
maturity date by one year and an automatic further extension of 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 future (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/bbl; 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% discount to the oil price forward curve;
-- a 5% increase in operating costs except for fixed costs related to the Kraken FPSO; and
-- a lower value achieved from the sale of an interest in Kraken.
A scenario has been run illustrating the impact of the above
risks on the Base case. This plausible Downside case indicates no
mitigating actions need be undertaken for the Group to be viable in
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 will be able to continue in operation and meet its
commitments as they fall due over the viability period ending March
2021. Accordingly, the Directors therefore support this viability
statement.
Risks and uncertainties
Management of risks and uncertainties
The Board has articulated EnQuest's vision to be the operator of
choice for maturing and underdeveloped hydrocarbon assets. As
EnQuest moves from a period of heavy investment to one focused on
realising value from existing resources, it will focus on driving
improved cash flow and managing its capital structure and
liquidity.
EnQuest seeks to balance its risk position between investing in
activities that can drive growth with the appropriate returns,
including any appropriate market opportunities that may present
themselves, and the continuing need to remain financially
disciplined. This financial discipline drives cost efficiency and
cash flow generation to reduce the Group's debt. In this regard,
the Board has developed certain strategic tenets to guide the
Company during the current phase of its evolution 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 face and 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
(which has been further refined in light of the Company's strategic
tenets):
-- 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 avoid reputational risk by ensuring that our
operational processes and practices reduce the potential for error
to the greatest extent practicable;
-- 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 manage operational risk 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 exercise and a risk report (focused on the most
critical risks and emerging and changing risk profiles), is
periodically reviewed by the Board (with senior management), to
ensure that key issues are being adequately identified and actively
managed. In addition, a sub-Committee of the Board has been
established (the Risk Committee) to provide a forum for the Board
to review selected individual risk areas in greater depth.
The Board, supported by the Audit Committee, has reviewed the
Group's system of risk management and internal control for the
period from 1 January 2017 to the date of this report, and is
satisfied that it is effective and 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 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 2016 financial restructuring (and
consequent strategic focus on reducing the Company's debt and
strengthening its balance sheet), 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 below 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
prolonged low oil price environment and/or a sustained decline in
oil prices and materially lower than expected production
performance for a prolonged period, particularly at the Kraken
field.
Risk Appetite Mitigation
------------------------------ ---------------------------- ------------------------------
Health, safety The Group's principal The Group maintains,
and environment aim is safe results in conjunction
('HSE') with no harm with its core
Oil and gas development, to people and contractors, a
production and respect for the comprehensive
exploration activities environment. programme of HSE,
are complex and Should operational asset integrity
HSE risks cover results and safety and assurance
many areas including ever come into activities and
Major Accident conflict, employees has implemented
Hazards, personal have a responsibility a continual improvement
health and safety, to choose safety programme, promoting
compliance with over operational a culture of transparency
regulatory requirements, results and are in relation to
asset integrity empowered to HSE matters. HSE
issues and potential stop operations performance is
environmental if required. discussed at each
harm. The Group's desire Board meeting.
is to maintain During 2017, the
Potential impact upper quartile Group continued
- Medium (2016 HSE performance to focus on control
Medium) measured against of Major Accident
Likelihood - suitable industry Hazards and 'Safe
Low (2016 Low) metrics. Behaviours' which
has resulted in
There has been significant improvement
no material change in safety and
in the potential environmental
impact or likelihood performance.
and the Group's In addition, the
overall record Group has a positive
on HSE remains and transparent
robust. relationship with
the UK Health
and Safety Executive
and Department
for Business,
Energy & Industrial
Strategy.
EnQuest's HSE
Policy is now
fully integrated
across all of
our operated sites
and this has enabled
an increased focus
on Health, Safety
and the Environment.
There is a strong
assurance programme
in place to ensure
that EnQuest complies
with its Policy
and Principles
and regulatory
commitments.
EnQuest has now
extended the application
of its HSE policy,
activities and
programmes to
operatorship of
the Magnus oil
field, Sullom
Voe Terminal and
associated pipelines.
------------------------------ ---------------------------- ------------------------------
Production Since production The Group's programme
The Group's production efficiency and of asset integrity
is critical to meeting production and assurance
its success and targets is core activities provide
is subject to to our business leading indicators
a variety of and the Group of significant
risks including: seeks to maintain potential issues
subsurface uncertainties; a high degree which may result
operating in of operational in unplanned shutdowns
a mature field control over or which may ,in
environment; production assets other respects,
potential for in its portfolio, have the potential
significant unexpected EnQuest has a to undermine asset
shutdowns; and very low tolerance availability and
unplanned expenditure for operational uptime. The Group
(particularly risks to its continually assesses
where remediation production (or the condition
may be dependent the support systems of its assets
on suitable weather that underpin and operates extensive
conditions offshore). production). maintenance and
Lower than expected inspection programmes
reservoir performance designed to minimise
or insufficient the risk of unplanned
addition of new shutdowns and
resources may expenditure. The
have a material Group monitors
impact on the both leading and
Group's future lagging KPIs in
growth. relation to its
The Group's delivery maintenance activities
infrastructure and liaises closely
in the UKCS is, with its downstream
to a significant operators to minimise
extent, dependent pipeline and terminal
on the Sullom production impacts.
Voe Terminal. Production efficiency
Longer-term production is continually
is threatened monitored with
if low oil prices losses being identified
bring forward and remedial and
decommissioning improvement opportunities
timelines. undertaken as
required. A continual,
Potential impact rigorous cost
- High (2016 focus is also
High) maintained.
Likelihood - Life of asset
Low (2016 Low) production profiles
are audited by
There has been independent reserves
no material change auditors. The
in the potential Group also undertakes
impact or likelihood. regular internal
Whilst reliance reviews. The Group's
on the Sullom forecasts of production
Voe Terminal are risked to
has decreased reflect appropriate
due to the Scolty/Crathes production uncertainties.
and Kraken projects The Sullom Voe
coming onstream, Terminal has a
production at good safety record
Alma/Galia has and its safety
been below expectations. and operational
Until the Kraken performance levels
project is at are regularly
full production, monitored and
there remains challenged by
a possibility the Group and
that production other terminal
at the field owners and users
could be below to ensure that
expectations. operational integrity
is maintained.
Further, EnQuest
expects to be
well positioned
to manage potential
operational risks
related to Sullom
Voe Terminal having
assumed operatorship
of the terminal
and with the workforce
having transferred
with the asset.
Nevertheless,
the Group actively
continues to explore
the potential
of alternative
transport options
and developing
hubs that may
provide both risk
mitigation and
cost savings.
The Group also
continues to consider
new opportunities
for expanding
production.
------------------------------ ---------------------------- ------------------------------
Project execution The efficient The Group has
and delivery delivery of new project teams
The Group's success project developments which are responsible
will be partially has been a key for the planning
dependent upon feature of the and execution
the successful Group's long-term of new projects
execution and strategy. Following with a dedicated
delivery of development the entry into team for each
projects. production of development. The
the Alma/Galia, Group has detailed
Potential impact Scolty/Crathes controls, systems
- High (2016 and Kraken projects, and monitoring
High) the Company's processes in place
Likelihood - exposure to development to ensure that
Low (2016 Low) risks has now deadlines are
reduced. While met, costs are
The potential the Group necessarily controlled and
impact has been assumes significant that design concepts
partially offset risk when it and the Field
by the Alma/Galia, sanctions a new Development Plan
Scolty/Crathes development (for are adhered to
and Kraken projects example, by incurring and implemented.
coming into production costs against These are modified
in 2015, 2016 oil price assumptions), when circumstances
and 2017 respectively. it requires that require and only
risks to the through a controlled
Further, as the efficient implementation management of
Group focuses of the project change process
on reducing its are minimised. and with the necessary
debt, executing internal and external
new large-scale authorisation
developments and communication.
is not considered The Group also
a strategic priority engages third-party
in the short assurance experts
term. 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.
The Kraken development
was sanctioned
by DECC and EnQuest's
partners in November
2013. First oil
production was
achieved on 23
June 2017. Prior
to sanction, EnQuest
identified and
optimised the
development plan
using EnQuest's
pre-investment
assurance processes.
The Group also
continues to explore
opportunities
to reduce capital
costs and optimise
drilling programmes
with a view to
achieving the
most cost efficient
development outcome
at the field.
------------------------------ ---------------------------- ------------------------------
Subsurface risk Reserves replacement The Group puts
and reserves is an element a strong emphasis
replacement of the sustainability on subsurface
Failure to develop of the Group analysis and employs
its contingent and its ability industry-leading
and prospective to grow. The professionals.
resources or Group has some The Group continues
secure new licences tolerance for to recruit in
and/or asset the assumption a variety of technical
acquisitions of risk in relation positions which
and realise their to the key activities enables it to
expected value. required to deliver manage existing
reserves growth, assets and evaluate
Potential impact such as drilling the acquisition
- High (2016 and acquisitions. of new assets
High) and licences.
Likelihood - All analysis is
Medium (2016 subject to internal
Medium) and, where appropriate,
external review
There has been and relevant stage
no material change gate processes.
in the potential All reserves are
impact or likelihood currently externally
as oil price reviewed by a
volatility and Competent Person.
a focus on strengthening In addition, EnQuest
the balance sheet has active business
continues to development teams
limit business both in the UK
development activity and internationally
to the pursuit developing a range
of reserves enhancing, of opportunities
selective, cash-accretive and liaising with
opportunities. vendors/government.
Low oil prices The Group continues
can potentially to consider potential
affect development opportunities
of contingent to acquire new
and prospective production resources
resources and that meet its
can also affect criteria.
reserve certifications.
------------------------------ ---------------------------- ------------------------------
Financial The Group recognises During the year,
Inability to that significant the Group completed
fund financial leverage has an $80 million
commitments or been required crude oil prepayment
maintain adequate to fund its growth transaction and
cash flow and as low oil prices executed a $37.25
liquidity and/or have impacted million refinancing
reduce costs. revenues. However, for its Tanjong
The Group's term it is intent Baram project
loan and revolving on reducing its in Malaysia; the
credit facility leverage levels, Group also secured
contains certain maintaining liquidity, consents from
financial covenants enhancing profit its term loan
(based on the margins, reducing and revolving
ratio of indebtedness costs and complying credit facility
incurred under with its obligations lenders to waive
the term loan to finance providers certain financial
and revolving while delivering covenants tests
facility to EBITDA, shareholder value, and amend the
finance charges recognising that amortisation schedule
to EBITDA and reasonable assumptions under the facility.
a requirement relating to external These steps, together
for liquidity risks need to with other mitigating
testing). Prolonged be made in transacting actions available
low oil prices, with finance to management,
cost increases providers. are expected to
and production provide the Group
delays or outages with sufficient
could threaten liquidity to strengthen
the Group's liquidity its balance sheet
and/or ability for longer-term
to comply with growth.
relevant covenants. Ongoing compliance
with the financial
Potential impact covenants under
- High (2016 the Group's term
High) loan and revolving
Likelihood - credit facility
Medium (2016 is actively monitored
Medium) and reviewed.
Funding from the
There has been bonds and revolving
no material change credit facility
in the potential is supplemented
impact or likelihood; by operating cash
however, adhering inflow from the
to the RCF amortisation Group's producing
schedule remains assets. The Group
partially dependant reviews its cash
on the successful flow requirements
increase in production on an ongoing
at the Kraken basis to ensure
development, it has adequate
aggregate production resources for
at other assets its needs.
being materially The Group is continuing
in line with to enhance its
expectations financial position
and no significant through maintaining
reduction in a focus on controlling
oil prices. Further and reducing costs
information is through supplier
contained in renegotiations,
the going concern assessing counterparty
and viability credit risk, hedging
paragraphs in and trading, cost-cutting
the Financial and rationalisation.
Review. Where costs are
incurred by external
service providers,
the Group actively
challenges operating
costs. The Group
also maintains
a framework of
internal controls.
------------------------------ ---------------------------- ------------------------------
Human resources As a low-cost, The Group has
The Group's success lean organisation, established an
continues to the Group relies able and competent
be dependent on motivated employee base
upon its ability and high quality to execute its
to attract and employees to principal activities.
retain key personnel achieve its targets In addition to
and develop organisational and manage its this, the Group
capability to risks. The Group seeks to maintain
deliver strategic recognises that good relationships
growth. Industrial the benefits with its employees
action across of a lean and and contractor
the sector could flexible organisation companies and
also impact on require agility regularly monitors
the operations to assure against the employment
of the Group. the risk of skills market to provide
shortages. remuneration packages,
Potential impact bonus plans and
- Low (2016 Low) long-term share-based
Likelihood - incentive plans
Medium (2016 that incentivise
Low) performance and
long-term commitment
The impact has from our employees
remained static to the Group.
due to low oil We recognise that
prices impacting our people are
the buoyancy critical to our
of the employment success and so
market. The likelihood are continually
has increased evolving our end-to-end
due to the erosion people management
in value of long-term processes, including
share-based incentive recruitment and
plans. selection, career
development and
performance management.
This ensures that
we have the right
person for the
job and that we
provide appropriate
training, support
and development
opportunities
with feedback
to drive continuous
improvement whilst
delivering safe
results. The culture
of the Group is
an area of increased
focus given the
rapid growth of
the workforce
as we absorb a
significant number
of personnel into
the business with
the acquisition
of operating interests
in the Magnus
field and the
Sullom Voe Oil
Terminal.
The Group also
maintains market-competitive
contracts with
key suppliers
to support the
execution of work
where the necessary
skills do not
exist within the
Group's employee
base. The Group
recognises that
there is a Gender
Pay gap within
the organisation
but that there
is no issue with
equal pay for
the same tasks.
EnQuest aims to
attract the best
talent, regardless
of gender.
The focus on executive
and senior management
retention, succession
planning and development
remains an important
priority for the
Board. It is a
Board-level priority
that executive
and senior management
possess the appropriate
mix of skills
and experience
to realise the
Group's strategy;
succession planning
therefore remains
a key priority.
------------------------------ ---------------------------- ------------------------------
Reputation The Group has All activities
The reputational no tolerance are conducted
and commercial for conduct which in accordance
exposures to may compromise with approved
a major offshore its reputation policies, standards
incident or non-compliance for integrity and procedures.
with applicable and competence. Interface agreements
law and regulation are agreed with
are significant. all core contractors.
The Group requires
Potential impact adherence to its
- High (2016 Code of Conduct
High) and runs compliance
Likelihood - programmes to
Low (2016 Low) provide assurance
on conformity
There has been with relevant
no material change legal and ethical
in the potential requirements.
impact or likelihood. The Group undertakes
regular audit
activities to
provide assurance
on compliance
with established
policies, standards
and procedures.
All EnQuest personnel
and contractors
are required to
pass an annual
anti-bribery,
corruption and
anti-facilitation
of tax evasion
course.
------------------------------ ---------------------------- ------------------------------
Oil price The Group recognises This risk is being
A material decline that considerable mitigated by a
in oil and gas exposure to this number of measures
prices adversely risk is inherent including hedging
affects the Group's to its business. oil price, renegotiating
operations and supplier contracts,
financial condition. reducing costs
and commitments
Potential impact and institutionalising
- High (2016 a lower cost base.
High) The Group monitors
Likelihood - oil price sensitivity
Medium (2016 relative to its
High) capital commitments
and has a policy
There has been which allows hedging
no material change of its production.
in the potential As at 19 March
impact; the likelihood 2018, the Group
has decreased had hedged approximately
due to rising/stabilising 7.5 million bbls
oil prices. for 2018 at a
price of approximately
$62/bbl. This
ensures that the
Group will receive
a minimum oil
price for its
production.
In order to develop
its resources,
the Group needs
to be able to
fund the required
investment. The
Group will therefore
regularly review
and implement
suitable policies
to hedge against
the possible negative
impact of changes
in oil prices
while remaining
within the limits
set by its term
loan and revolving
credit facility.
The Group has
established an
in-house trading
and marketing
function to enable
it to enhance
its ability to
mitigate the exposure
to volatility
in oil prices.
Further, as described
above, the Group's
focus on production
efficiency supports
mitigation of
a low oil price
environment
------------------------------ ---------------------------- ------------------------------
Fiscal risk and The Group faces It is difficult
government take an uncertain for the Group
Unanticipated macro-economic to predict the
changes in the and regulatory timing or severity
regulatory or environment. of such changes.
fiscal environment Due to the nature However, through
can affect the of such risks Oil & Gas UK and
Group's ability and their relative other industry
to deliver its unpredictability, associations,
strategy/business it must be tolerant the Group engages
plan and potentially of certain inherent with government
impact revenue exposure. and other appropriate
and future developments. organisations
in order to keep
Potential impact abreast of expected
- High (2016 and potential
High) changes; the Group
Likelihood - also takes an
Medium (2016 active role in
Medium) making appropriate
representations.
There has been All business development
no material change or investment
in the potential activities recognise
impact or likelihood. potential tax
implications and
the Group maintains
relevant internal
tax expertise.
At an operational
level, the Group
has procedures
to identify impending
changes in relevant
regulations to
ensure legislative
compliance.
------------------------------ ---------------------------- ------------------------------
Joint venture The Group requires The Group operates
partners partners of high regular cash call
Failure by joint integrity. It and billing arrangements
venture parties recognises that with its co-venturers
to fund their it must accept to mitigate the
obligations. a degree of exposure Group's credit
Dependence on to the creditworthiness exposure at any
other parties of partners and one point in time
where the Group evaluates this and keeps in regular
is not the operator. aspect carefully dialogue with
as part of every each of these
Potential impact investment decision. parties to ensure
- Medium (2016 payment. Risk
Medium) of default is
Likelihood - mitigated by joint
Medium (2016 operating agreements
Medium) allowing the Group
to take over any
There has been defaulting party's
no material change share in an operated
in the potential asset and rigorous
impact or likelihood; and continual
however, due assessment of
to the assumption the financial
of operatorship situation of partners.
at Sullom Voe The Group generally
Terminal, the prefers to be
Group has now the operator.
assumed exposure The Group maintains
to a larger number regular dialogue
of counterparties. with its partners
to ensure alignment
of interests and
to maximise the
value of joint
venture assets.
------------------------------ ---------------------------- ------------------------------
Competition The Group operates The Group has
The Group operates in a mature industry strong technical
in a competitive with well-established and business development
environment across competitors and capabilities to
many areas including aims to be the ensure that it
the acquisition leading operator is well positioned
of oil and gas in the sector; to identify and
assets, the marketing it thus has a execute potential
of oil and gas, high appetite acquisition opportunities.
the procurement for this risk. The Group maintains
of oil and gas good relations
services and with oil and gas
access to human service providers
resources. and constantly
keeps the market
Potential impact under review.
- Medium (2016
Medium)
Likelihood -
Medium (2016
Medium)
There has been
no material change
in the impact
or likelihood.
------------------------------ ---------------------------- ------------------------------
Portfolio concentration Although the This risk is mitigated
The Group's assets extent of portfolio in part through
are concentrated concentration acquisitions.
in the UK North is moderated For all acquisitions,
Sea around a by production the Group uses
limited number generated internationally, a number of business
of infrastructure the majority development resources
hubs and existing of the Group's to evaluate and
production (principally assets remain transact acquisitions
only oil) is relatively concentrated in a commercially
from mature fields. in the UK North sensitive matter.
This amplifies Sea and therefore This includes
exposure to key this risk remains performing extensive
infrastructure intrinsic to due diligence
(including aging the Group. (using in-house
pipelines and and external personnel)
terminals), political/fiscal and actively involving
changes and oil executive management
price movements. in reviewing commercial,
technical and
Potential impact other business
- High (2016 risks together
Medium) with mitigation
Likelihood - measures.
Medium (2016 The Group also
Low) constantly keeps
its portfolio
The acquisition under rigorous
of an interest review and, accordingly,
in the Magnus actively considers
oil field and the potential
Sullom Voe Terminal for making disposals
(and associated and divesting,
pipelines) has executing development
elevated this projects, making
risk in the long international
term (by further acquisitions and
concentrating expanding hubs
the Group's portfolio where such opportunities
in the UK North are consistent
Sea). In addition, with the Group's
although production focus on enhancing
from Kraken represents net revenues,
a new production generating cash
hub for the Group, flow and strengthening
it does further the balance sheet.
extend geographic The acquisition
concentration of the Greater
of the Group's Kittiwake Area
production in in 2014, which
the UK North produces via the
Sea. Forties Pipeline
System ('FPS'),
and the start-up
of Alma/Galia
and Kraken, which
produce to shuttle
tankers, reduced
the Group's prior
concentration
to the Brent Pipeline
System ('BPS')
and the Sullom
Voe Terminal.
Although, due
to successful
completion of
the Group's acquisition
of the Magnus
field and Sullom
Voe Terminal from
BP, the Group
will see a further
concentration
in Sullom Voe.
As the Magnus
field produces
via the Ninian
Pipeline System
('NPS'), this
will not concentrate
risk further in
BPS. It should
also be noted
that the Heather
and Broom fields
also produce via
NPS. Although
the Group has
concentration
risk at Sullom
Voe Terminal,
taking operatorship
of the terminal
will put the Group
in a position
of more direct
control of such
risk.
------------------------------ ---------------------------- ------------------------------
International In light of its Prior to entering
business long-term growth a new country,
While the majority strategy, the EnQuest evaluates
of the Group's Group seeks to the host country
activities and expand and diversify to assess whether
assets are in its production there is an adequate
the UK, the international (geographically and established
business is still and in terms legal and political
material. The of quantum); framework in place
Group's international as such, it is to protect and
business is subject tolerant of assuming safeguard first
to the same risks certain commercial its expatriate
as the UK business risks which may and local staff
(e.g. HSE, production accompany the and, second, any
and project execution); opportunities investment within
however, there it pursues. However, the country in
are additional such tolerance question.
risks that the does not impair When evaluating
Group faces including the Group's commitment international
security of staff to comply with business risks,
and assets, political, legislative and executive management
foreign exchange regulatory requirements reviews commercial,
and currency in the jurisdictions technical and
control, taxation, in which it operates. other business
legal and regulatory, Opportunities risks together
cultural and should enhance with mitigation
language barriers net revenues and how risks
and corruption. and facilitate can be managed
strengthening by the business
Potential impact of the balance on an ongoing
- Medium (2016 sheet. basis.
Medium) EnQuest looks
Likelihood - to employ suitably
Medium (2016 qualified host
Medium) country staff
and work with
There has been good quality local
no material change advisers to ensure
in the impact it complies within
or likelihood. 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.
Where appropriate,
the risks may
be mitigated by
entering into
a joint venture
with partners
with local knowledge
and experience.
After country
entry, EnQuest
maintains a dialogue
with local and
regional government,
particularly with
those responsible
for oil, energy
and fiscal matters,
and may obtain
support from appropriate
risk consultancies.
When there is
a significant
change in the
risk to people
or assets within
a country, the
Group takes appropriate
action to safeguard
people and assets.
------------------------------ ---------------------------- ------------------------------
IT security and The Group endeavours The Group has
resilience to provide a established IT
The Group is secure IT environment capabilities and
exposed to risks that is able endeavours to
arising from to resist and be in a position
interruption withstand any to defend its
to, or failure attacks or unintentional systems against
of, IT infrastructure. disruption that disruption or
The risks of may compromise attack.
disruption to sensitive data, The Risk Committee
normal operations impact operations undertook an analysis
range from loss or destabilise of cyber security
in functionality its financial risks in 2017,
of generic systems systems; it has recognising it
(such as email a very low appetite is one of the
and internet for this risk. Group's key focus
access) to the areas. Work on
compromising assessing the
of more sophisticated cyber security
systems that environment and
support the Group's implementing improvements
operational activities. as necessary will
These risks could be continuing
result from malicious during 2018.
interventions
such as cyber-attacks.
Potential impact
- Medium (2016
N/A)
Likelihood -
Low (2016 N/A)
------------------------------ ---------------------------- ------------------------------
KEY PERFORMANCE INDICATORS
2017 2016 2015
North Sea Lost Time Incident
Frequency ('LTIF') 1.05 0.82 2.14
Malaysia LTIF 0.00 0.00 0.00
--------------------------------------- -------- -------- --------
Production (Boepd) 37,405 39,751 36,567
--------------------------------------- -------- -------- --------
Net 2P reserves (MMboe) 210 215 203
--------------------------------------- -------- -------- --------
Business performance data:
Revenue and other operating income(1)
($ million) 627.5 849.6 906.6
Realised blended average oil
price per barrel(1) ($) 52.2 63.8 72.0
Opex per barrel (production and
transportation costs) ($) 25.6 24.6 29.7
EBITDA(2) ($ million) 303.6 477.1 474.2
Cash capex(3) on property, plant
and equipment oil and gas assets
($ million) 367.6 609.2 751.1
--------------------------------------- -------- -------- --------
Reported data:
Cash generated from operations
($ million) 327.0 408.3 221.7
Net debt including PIK ($ million) 1,991.4 1,796.5 1,548.0
--------------------------------------- -------- -------- --------
(i) Including realised loss of $20.6 million in 2017 associated
with EnQuest's oil price hedges (2016: realised gain of $255.8
million, 2015: realised gain of $261.2 million).
(ii) 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 and the realised gains/loss on foreign
currency derivatives related to capital expenditure.
(iii) Net of proceeds from disposal of $nil million (2016: $1.5
million, 2015: $75.5 million).
OIL AND GAS RESERVES AND RESOURCES
At 31 December 2017
UKCS Other Regions Total
-------------- ---------------- ------
MMboe MMboe MMboe MMboe MMboe
Proven and probable reserves
(notes 1,2,3,6 and 8)
At 31 December 2016 199 17 215
Revisions of previous
estimates (13) 6 (7)
Discoveries, extensions
and additions
Acquisitions and disposals
(note 7) 14 14
Production
Export Meter (10) (3)
Volume Adjustments
(note 5) 0 1
Production during period: (10) (2) (12)
Total at 31 December
2017 190 21 210
Contingent resources
(notes 1,2 and 4)
At 31 December 2016 95 55 151
Revisions of previous
estimates 10 12 22
Discoveries, extensions
and additions
Acquisitions and disposals
(note 7) (8) (8)
Promoted to reserves
Total at 31 December
2017 98 67 164
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 underlying technical data underpinning
proven and probable reserve profiles has been
audited by a recognised Competent Person in
accordance with the definitions set out under
the 2007 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
25% equity in Magnus. Contingent resources:
Acquisition of 25% equity in Magnus offset by
relinquishment of the Group's equity interests
in Crawford, Porter and Elke licences and expiry
of 50% of the Kildrummy licence.
8 The above proven and probable reserves include
5.8 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 2017
2017 2016
------------- ------------------ ---------- ------------- ---------------- ----------
Notes Re-measurements, Re-measurements
Business and exceptional Reported Business and exceptional Reported
performance items (note 4) in year performance items (note 4) in year
$'000 $'000 $'000 $'000 $'000 $'000
Revenue and
other
operating
income 5(a) 635,167 (7,716) 627,451 849,627 (51,504) 798,123
Cost of sales 5(b) (569,506) 5,481 (564,025) (653,518) (2,848) (656,366)
---------------- ------ ------------- ------------------ ---------- ------------- ---------------- ----------
Gross
profit/(loss) 65,661 (2,235) 63,426 196,109 (54,352) 141,757
Net impairment
(charge)/
reversal to
oil and gas
assets 4 - (171,971) (171,971) - 147,871 147,871
(Loss)/gain on
disposal of
intangible oil
and gas assets 4 - - - - (16,178) (16,178)
General and
administration
expenses 5(c) (848) - (848) (10,890) - (10,890)
Other income 5(d) 6,807 50,613 57,420 51,936 31,554 83,490
Other expenses 5(e) (24,363) (20,358) (44,721) (77) (894) (971)
---------------- ------ ------------- ------------------ ---------- ------------- ---------------- ----------
Profit/(loss)
from
operations
before tax and
finance
income/(costs) 47,257 (143,951) (96,694) 237,078 108,001 345,079
Finance costs 6 (149,020) (272) (149,292) (122,232) (7,043) (129,275)
Finance income 6 2,213 - 2,213 1,440 - 1,440
---------------- ------ ------------- ------------------ ---------- ------------- ---------------- ----------
Profit/(loss)
before tax (99,550) (144,223) (243,773) 116,286 100,958 217,244
Income tax 7 65,996 116,947 182,943 5,224 (37,256) (32,032)
---------------- ------ ------------- ------------------ ---------- ------------- ---------------- ----------
Profit/(loss)
for the year
attributable
to owners of
the parent (33,554) (27,276) (60,830) 121,510 63,702 185,212
================ ====== ============= ================== ========== ============= ================ ==========
Other comprehensive
income
Items that may be
reclassified to profit
or loss:
Fair value gains/(losses)
on cash flow hedges - (29,048)
Transfers to income
statement of cash
flow hedges (5) (239,565)
Transfers to balance
sheet of cash flow
hedges - 278
Deferred tax on cash
flow hedges - 134,177
---------------------------------- --------- ------ ----------
Other comprehensive
income for the year,
net of tax (5) (134,158)
---------------------------------- --------- ------ ----------
Total comprehensive
income for the year,
attributable to owners
of the parent (60,835) 51,054
================================== ========= ====== ==========
Earnings $ $ $ $
per share 8
Basic (0.030) (0.054) 0.149 0.227
Diluted (0.030) (0.054) 0.145 0.221
The attached notes 1 to 30 form part of these Group financial
statements.
GROUP BALANCE SHEET
At 31 December 2017
Notes 2017 2016
ASSETS $'000 $'000
Non-current assets
Property, plant and equipment 10 3,848,622 2,963,446
Goodwill 11 189,317 189,317
Intangible oil and gas assets 12 52,103 50,332
Investments 13 152 171
Deferred tax assets 7 398,263 206,742
Other financial assets 20 8,191 23,429
----------- ----------
4,496,648 3,433,437
----------- ----------
Current assets
Inventories 14 78,045 74,985
Trade and other receivables 15 227,754 202,666
Current tax receivable 1,159 925
Cash and cash equivalents 16 173,128 174,634
Other financial assets 20 61,737 39,342
----------- ----------
541,823 492,552
----------- ----------
TOTAL ASSETS 5,038,471 3,925,989
EQUITY AND LIABILITIES
Equity
Share capital and premium 17 210,402 208,639
Merger reserve 662,855 662,855
Cash flow hedge reserve 36 41
Share-based payment reserve (5,516) (6,602)
Retained earnings (106,911) (46,081)
----------- ----------
TOTAL EQUITY 760,866 818,852
----------- ----------
Non-current liabilities
Borrowings 19 888,993 1,052,075
Bonds 19 934,351 855,739
Obligations under finance leases 24 679,924 -
Provisions 22 705,999 584,266
Trade and other payables 23 78,777 42,587
Other financial liabilities 20 7,121 19,767
Deferred tax liabilities 7 62,685 15,027
----------- ----------
3,357,850 2,569,461
----------- ----------
Current liabilities
Borrowings 19 330,012 49,601
Obligations under finance leases 24 118,009 -
Provisions 22 43,215 30,041
Trade and other payables 23 367,312 410,261
Other financial liabilities 20 61,207 44,274
Current tax payable - 3,499
----------- ----------
919,755 537,676
----------- ----------
TOTAL LIABILITIES 4,277,605 3,107,137
TOTAL EQUITY AND LIABILITIES 5,038,471 3,925,989
=========== ==========
The attached notes 1 to 30 form part of these Group financial
statements.
The financial statements were approved by the Board of Directors
on 19 March 2018 and signed on its behalf by:
Jonathan Swinney
Chief Financial Officer
GROUP STATEMENT OF CHANGES IN EQUITY
For the year ended 31 December 2017
Share capital
and share Merger Cash flow hedge Share-based
premium reserve reserve payments reserve Retained earnings Total
$'000 $'000 $'000 $'000 $'000 $'000
Balance at 1
January 2016 113,433 662,855 134,199 (11,995) (231,293) 667,199
Profit for the
year - - - - 185,212 185,212
Other
comprehensive
income - - (134,158) - - (134,158)
------------------ ----------------- --------- ----------------- ----------------- ------------------ ----------
Total
comprehensive
income for the
year - - (134,158) - 185,212 51,054
Issue of share
capital, net of
expenses 95,206 - - - - 95,206
Share-based
payment - - - 8,452 - 8,452
Shares purchased
on behalf of
Employee Benefit
Trust - - - (3,059) - (3,059)
------------------
Balance at 31
December 2016 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 210,402 662,855 36 (5,516) (106,911) 760,866
------------------ ----------------- --------- ----------------- ----------------- ------------------ ----------
The attached notes 1 to 30 form part of these Group financial
statements.
GROUP STATEMENT OF CASH FLOWS
For the year ended 31 December 2017
2017 2016
Notes $'000 $'000
CASH FLOW FROM OPERATING ACTIVITIES
Cash generated from operations 30 327,034 408,247
Cash (paid)/received on sale/(purchase) of financial instruments (1,185) (14,541)
Decommissioning spend 22 (10,605) (6,355)
Income taxes paid (13,463) (7,890)
------------------------------------------------------------------ ------
Net cash flows from/(used) operating activities 301,781 379,461
------------------------------------------------------------------ ------ ----------- ----------
INVESTING ACTIVITIES
Purchase of property, plant and equipment (358,420) (601,696)
Purchase of intangible oil and gas assets (9,171) (8,928)
Proceeds from disposal of intangible oil and gas assets - 1,466
Proceeds from disposal of Ascent loan notes 3,561 -
Interest received 340 422
------------------------------------------------------------------ ------ ----------- ----------
Net cash flows (used)/from in investing activities (363,690) (608,736)
------------------------------------------------------------------ ------ ----------- ----------
FINANCING ACTIVITIES
Proceeds from bank facilities 162,970 174,997
Repayment of bank facilities (50,969) (10,150)
Gross proceeds from issue of shares - 101,628
Shares purchased by Employee Benefit Trust - (3,059)
Share issue and debt restructuring costs paid (1,356) (21,152)
Repayment of obligations under finance leases - (35)
Interest paid (46,052) (83,207)
Other finance costs paid (6,286) (9,842)
------------------------------------------------------------------ ------ ----------- ----------
Net cash flows from/(used) financing activities 58,307 149,180
------------------------------------------------------------------ ------ ----------- ----------
NET (DECREASE)/INCREASE IN CASH AND CASH EQUIVALENTS (3,602) (80,095)
Net foreign exchange on cash and cash equivalents 5,210 (9,385)
Cash and cash equivalents at 1 January 168,060 257,540
------------------------------------------------------------------ ------ ----------- ----------
CASH AND CASH EQUIVALENTS AT 31 DECEMBER 169,668 168,060
================================================================== ====== =========== ==========
Reconciliation of cash and cash equivalents
Cash and cash equivalents per statement of cash flows 169,668 168,060
Restricted cash 16 3,460 6,574
------------------------------------------------------------------ ------ ----------- ----------
Cash and cash equivalents per balance sheet 173,128 174,634
================================================================== ====== =========== ==========
The attached notes 1 to 30 form part of these Group financial
statements.
NOTES TO THE GROUP FINANCIAL STATEMENTS
For the year ended 31 December 2017
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
2017 were authorised for issue in accordance with a resolution of
the Board of Directors on 19 March 2018.
A listing of the Group companies is contained in note 28 to
these Group financial statements.
2. Summary of significant accounting policies
New standards and interpretations
The Group has adopted and applied the following standards that
are relevant to its operations for the first time for the annual
reporting period commencing 1 January 2017:
-- Amendments to IAS 12 Income Taxes - Recognition of Deferred
Tax Assets for Unrealised Losses;
-- Annual Improvements to IFRSs (2014 - 2016 Cycle): IFRS 12
Disclosure of interests in other entities; and
-- Disclosure Initiative Amendments - IAS 7 Statement of Cash Flows.
There were no new standards or interpretations effective for the
first time for periods beginning on or after 1 January 2017 that
had a significant effect on the Group's financial statements,
although an amendment to IAS 7 Statement of Cash Flows has resulted
in a reconciliation of liabilities disclosed for the first time in
note 30.
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 9 Financial Instruments
In July 2014, the IASB issued the final version of IFRS 9
Financial Instruments which replaces IAS 39 Financial Instruments:
Recognition and Measurement and all previous versions of IFRS 9.
The standard introduces new requirements for classification and
measurement, impairment under the 'expected credit loss' ('ECL')
model and hedge accounting. IFRS 9 is effective for annual periods
beginning on or after 1 January 2018, with early application
permitted. The Group plans to adopt the new standard on the
required effective date and will not restate comparative
information.
During 2017, the Group has performed an impact assessment for
the application of IFRS 9. This assessment is based on currently
available information and may be subject to changes arising from
further reasonable and supportable information being made available
to the Group in 2018 when the Group will adopt IFRS 9. The Group
continues to assess its accounting processes, controls and policies
on an on-going basis.
Classification and measurement
The Group expects that all financial assets will continue to be
measured at amortised cost or fair value and will be measured on
the same basis as is currently adopted under IAS 39.
The Group has not designated any financial liabilities at fair
value through profit or loss ('FVTPL') and the assessment did not
indicate any material impact regarding the classification of
financial liabilities. The Group does not currently designate any
hedge relationships for hedge accounting.
Impairment
The Group's receivables have a good credit rating, hence the
expected credit losses are low (see note 15). There has been no
noted change in the credit risk of receivables in the year,
therefore the Group does not believe that the new ECL impairment
methodology will have a material impact on the valuation of
financial assets.
Non-current assets are held with reputable businesses with whom
the Group has good working relationships. The scheduled repayment
of cash flows have been and continue to be received in line with
expectations. There has been no noted change in the credit risk of
receivables in the year, therefore the Group does not believe that
the new ECL impairment methodology will have a material impact on
the valuation of financial assets.
Cash is held with bank and financial institution counterparties,
which are rated with an A-/A3 credit rating or better
(see note 16). The Group considers that the available cash
balances have low credit risk based on the external credit rating
of the counterparties.
2. Summary of significant accounting policies (continued)
Standards issued but not yet effective (continued)
IFRS 9 Financial Instruments (continued)
Modification of debt
In July 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. Any fees and
costs incurred are amortised over the remaining term of the
asset.
During the 2016 refinancing, the modification of the Bonds was
not considered to be significant. 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 (see
note 19). 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. On the implementation of IFRS 9
on 1 January 2018, an adjustment will be taken through opening
reserves and through the value of both bonds, High Yield Bond and
Retail Bond of $34.0m ($9.2m and $24.8m respectively).
IFRS 15 Revenue from Contracts with Customers
IFRS 15 was issued in May 2014, and amended in April 2016, and
establishes a single comprehensive model that will apply to revenue
arising from contracts with customers. IFRS 15 will supersede the
current revenue recognition guidance including IAS 18 Revenue and
related interpretations when it becomes effective, for annual
periods beginning on or after 1 January 2018.
The core principle of IFRS 15 is that an entity should recognise
revenue to depict the transfer of promised goods or services to
customers in an amount that reflects the consideration to which the
entity expects to be entitled to in exchange for those goods or
services. The five step model recognises revenue when (or as) a
performance obligation is satisfied, i.e. when 'control' of the
goods or services underlying the particular performance obligation
is transferred to the customer. Extensive new disclosures are
required by IFRS 15.
During 2017, the Group has performed an impact assessment for
the application of IFRS 15. This assessment is based on currently
available information and may be subject to changes arising from
further reasonable and supportable information being made available
to the Group in 2018 when the Group will adopt IFRS 15. The Group
continues to assess its accounting processes, controls and policies
on an on-going basis. The Group plans to adopt the new standard on
the required effective date using the modified retrospective
method.
The Group recognises revenue from the following major
sources:
-- Sale of crude oil, gas and condensate;
-- Tariff revenue for the use of Group infrastructure;
-- Production imbalances.
Interest income and dividend income from debt and equity
investments were covered by IAS 18. These are now within the scope
of IFRS 9.
Sale of crude oil, gas and condensate
The Directors have assessed the sale of crude oil, gas or
condensate and determined that these represent a single performance
obligation, being the sale of barrels equivalent on collection of a
cargo or on delivery of commodity into an infrastructure. Revenue
will accordingly be recognised for this performance obligation when
control over the corresponding commodity is transferred to the
customer. This is in line with the current recognition of revenue
under IAS 18. 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. Revenue recognition is
therefore consistent with current practice.
A Production Sharing Contract (PSC) is in place in Malaysia with
Petronas, the custodian for Malaysia's national oil and gas
resources. The production is shared in line with the risks and
benefits that result from the activity of the PSC and therefore
this is a collaborative arrangement. Revenue is recognised on the
sale of the crude oil, as per the analysis of sale of crude oil
above. This is in line with the current recognition of revenue
under IAS 18.
2. Summary of significant accounting policies (continued)
Standards issued but not yet effective (continued)
IFRS 15 Revenue from Contracts with Customers (continued)
Tariff revenue for the use of Group infrastructure
The Directors have assessed the revenue arising from tariffs,
which are charged to customers for the use of infrastructure owned
by the Group in the North Sea. There is one contract per customer
which is for a period of 12 months of 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 all dependent on one another in
order to fulfil the contract and no one item of infrastructure can
be individually identified. Revenue will accordingly be recognised
over the performance of the contract as services are provided for
the use of the infrastructure on a throughput basis. Revenue
recognition is therefore consistent with current practice under IAS
18.
Production imbalances
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.
The change in production imbalances is currently taken through cost
of sales (see note 5(b)) at fair value at the date of lifting. All
Group fields are operated through a Joint Venture Agreement ('JVA')
through which production imbalances are settled. These transactions
are settled by the JVA through lifting schedules and are not
settled in cash, with the exception of a misbalance at the
cessation of contract.
These are collaborative agreements through the JVA and
non-monetary exchanges, and therefore do not meet the definition of
a customer under IFRS 15. Production imbalances will continue to be
recognised through cost of sales, as per the current accounting
treatment, with no change on the application of IFRS 15.
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 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. There
are recognition exemptions for short-term leases and leases of
low-value items. Lessor accounting remains similar to the current
standard i.e. lessors continue to classify leases as finance or
operating leases.
The Group has completed an initial assessment of the potential
impact on its consolidated financial statements, but has not yet
completed its detailed assessment. The actual impact of applying
IFRS 16 on the financial statements in the period of initial
application will depending on future economic condition, including
the Group's borrowing rate at
1 January 2019, the composition of the Group's lease portfolio
at that date, the Group's latest assessment of whether it will
exercise any lease renewal options and the extent to which the
Group chooses to use practical expedients and recognition
exemptions.
As at 31 December 2017, the Group has non-cancellable operating
lease commitments of $110 million (see note 24). A preliminary
assessment indicates that these arrangements will meet the
definition of a lease under IFRS 16, and hence the Group will
recognise a right-of-use asset and a corresponding liability in
respect of these leases, unless they qualify for low value or
short-term leases upon the application of IFRS 16. The new
requirement to recognise a
right-of-use asset and a related lease liability is expected to
have a significant impact on the amounts recognised in the Group's
consolidated financial statements and the Directors are currently
assessing its potential impact. It is not practicable to provide a
reasonable estimate of the financial effect until the Directors
complete the review.
The Group plans to apply the practical expedient to grandfather
the definition of a lease on transition. This means that it will
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.
In contrast, for finance leases where the Group is a lessee, as
the Group has already recognised an asset and a related finance
lease liability for the lease arrangement, and in cases where the
Group is a lessor (for both operating and finance leases), the
Directors of the Company do not anticipate that the application of
IFRS 16 will have a significant impact on the amounts recognised in
the Group's consolidated financial statements.
2. Summary of significant accounting policies (continued)
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 2017 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
2017.
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.
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. 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 IAS 39, 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.
2. Summary of significant accounting policies (continued)
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 re-assesses 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 cash generating unit 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 IFRS 13 fair value
hierarchy). Key assumptions and estimates in the impairment models
relate to: commodity prices that are based on forward curve prices
for the first three years and thereafter at $70/bbl inflated at
2.0% per annum from 2022; discount rates derived from the Group's
post-tax weighted average cost of capital of 10.0% (2016: 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.
2. Summary of significant accounting policies (continued)
Critical accounting estimates and judgements (continued)
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 and 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% (2016: 2.0%) and an annual discount
rate of 2.0% (2016: 2.3%).
Debt restructuring
The Group undertook debt restructuring during 2016 resulting in
a substantial modification of the terms of its Revolving Credit
Facility ('RCF') (see note 19). Accordingly, extinguishment
accounting was applied, resulting in the derecognition of the
carrying value of the facility, including any unamortised
arrangement fees, and the recognition of a new financial liability
for the revised facility at fair value. Costs associated with the
renegotiation of the facility were expensed to the income statement
as exceptional finance costs (see note 4).
Going concern
The Directors' assessment of going concern concludes that the
use of the going concern basis is appropriate and that,
notwithstanding the material uncertainty as provided in the 'Going
Concern' section of the Financial Review, 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 any 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 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.
2. Summary of significant accounting policies (continued)
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 5 years
Fixtures and fittings 10 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.
2. Summary of significant accounting policies (continued)
Oil and gas assets (continued)
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
an asset's 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 assets
Financial assets within the scope of IAS 39 are classified as
financial assets at fair value through profit or loss, loans and
receivables, held-to-maturity investments, available-for-sale
financial investments, or as derivatives designated as hedging
instruments in an effective hedge, as appropriate. The Group
determines the classification of its financial assets at initial
recognition.
All assets are recognised initially at fair value plus
transaction costs, except in the case of financial assets recorded
at fair value through profit or loss.
Purchases or sales of financial assets that require delivery of
assets within a timeframe established by regulation or convention
in the marketplace (regular way trades) are recognised on the trade
date.
The Group's financial assets include cash and short-term
deposits, trade and other receivables, loans and other receivables,
quoted and unquoted financial instruments and derivative financial
instruments.
2. Summary of significant accounting policies (continued)
Financial assets (continued)
Subsequent measurement of financial assets depends on their
classification as described below:
Financial assets at fair value through profit or loss
('FVTPL')
Financial assets are classified as at FVTPL when the financial
asset is either held for trading or designated as at FVTPL.
Financial assets are classified as held for trading if they are
acquired for the purpose of selling or repurchasing in the near
term. Derivatives are also classified as held for trading unless
they are designated as effective hedging instruments as defined by
IAS 39.
Financial assets at FVTPL, including commodity and foreign
exchange derivatives, are stated at fair value, with any gains or
losses arising on remeasurement recognised immediately in the
income statement.
Financial assets designated upon initial recognition at FVTPL
are designated at their initial recognition date and only if the
criteria under IAS 39 are satisfied.
Available-for-sale financial investments
Listed and unlisted shares held by the Group that are traded in
an active market are classified as being
available-for-sale and are stated at fair value. Gains and
losses arising from changes in fair value are recognised in other
comprehensive income and accumulated in the available-for-sale
reserve with the exception of impairment losses which are
recognised directly in profit or loss. Where the investment is
disposed of or is determined to be impaired, the cumulative gain or
loss previously recognised in the available-for-sale reserve is
reclassified to profit or loss.
Loans and receivables
These include trade receivables, loans and other receivables
that have fixed or determinable payments that are not quoted in an
active market and are measured at amortised cost using the
effective interest method, less any impairment. Interest income is
recognised by applying the effective interest rate, except for
short-term receivables when the recognition of interest would be
immaterial.
Impairment of financial assets
The Group assesses, at each reporting date, whether there is any
objective evidence that a financial asset is impaired. A financial
asset is deemed to be impaired where there is objective evidence of
impairment that, as a result of one or more events that have
occurred after the initial recognition of the asset, the estimated
future cash flows of the investment have been affected.
For listed and unlisted equity investments classified as
available-for-sale, a significant or prolonged decline in the fair
value of the security below its cost is considered to be objective
evidence of impairment. When an available-for-sale financial asset
is considered to be impaired, cumulative gains and losses
previously recognised in other comprehensive income are
reclassified to profit or loss in the period. In respect of equity
securities, impairment losses previously recognised in profit or
loss are not reversed through profit or loss but through other
comprehensive income. Any increase in fair value subsequent to an
impairment loss is recognised in other comprehensive income.
For financial assets carried at amortised cost, the amount of
the impairment is the difference between the asset's carrying
amount and the present value of estimated future cash flows,
discounted at the financial asset's original effective interest
rate. The carrying amount is reduced through use of an allowance
account and the amount of the loss is recognised in profit or
loss.
Derivatives
Derivatives are initially recognised at fair value on the date a
derivative contract is entered into and are subsequently remeasured
at their fair value. The method of recognising the resulting gain
or loss depends on whether the derivative is designated as a
hedging instrument.
The Group categorises derivatives as follows:
Fair value hedge
Changes in the fair value of derivatives that qualify as fair
value hedging instruments are recorded in the profit or loss,
together with any changes in the fair value of the hedged asset or
liability.
Cash flow hedge
The effective portion of changes in the fair value of
derivatives that qualify as cash flow hedges are recognised in
other comprehensive income. The gain or loss relating to the
ineffective portion is recognised immediately in the profit or
loss. Amounts accumulated in other comprehensive income are
transferred to the profit or loss in the period when the hedged
item will affect the profit or loss. When the hedged item no longer
meets the requirements for hedge accounting, expires or is sold,
any accumulated gain or loss recognised in other comprehensive
income is transferred to profit and loss when the forecast
transaction which was the subject of the hedge occurs.
Where put options are used as hedging instruments, only the
intrinsic value of the option is designated as the hedge, with the
change in time value recorded in finance costs within the income
statement.
2. Summary of significant accounting policies (continued)
Derivatives
Derivatives that do not qualify for hedge accounting
When derivatives do not qualify for hedge accounting, changes in
fair value are recognised immediately in the profit or loss within
'Re-measurements 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
'Re-measurements and exceptional items'.
Option premium
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 options expiry date. This
results in a corresponding reclassification from 'Re-measurements
and exceptional items' revenue.
As noted above, where put options are designated as an effective
hedge, the change in time value is recorded in finance costs. As
the cost of a put option represents the initial time value of that
option, option premium paid for put options which have been
designated as effective hedges are amortised in Business
performance finance costs, with an offsetting reclassification from
'Re-measurements and exceptional items' finance costs.
Trade receivables
Trade receivables are recognised initially at fair value and
subsequently measured at amortised cost less provision for
impairment.
Financial liabilities
Financial liabilities within the scope of IAS 39 are classified
as financial liabilities at fair value through profit or loss or
other financial liabilities at amortised cost. The Group determines
the classification of its financial liabilities at initial
recognition.
All liabilities are recognised initially at fair value net
transaction costs, except in the case of financial liabilities
recorded at fair value through profit or loss.
The Group's financial liabilities include loans and borrowings,
trade and other payables, quoted and unquoted financial instruments
and derivative financial instruments.
Other financial liabilities, including borrowings, are initially
measured at fair value, net of transaction costs. Other financial
liabilities are subsequently measured at amortised cost using the
effective interest method, with interest expense recognised on an
effective yield basis.
Interest bearing loans and borrowings
Interest bearing loans and borrowings are recognised initially
at fair value, net of transaction costs incurred. Transaction costs
are amortised over the life of the facility.
Borrowing costs are stated at amortised cost using the effective
interest method.
The effective interest method is a method of calculating the
amortised cost of a financial liability and of allocating interest
expense over the relevant period. The effective interest rate is
the rate that exactly discounts estimated future cash payments
through the expected life of the financial liability, or a shorter
period to the net carrying amount of the financial liability where
appropriate.
Bonds
Bonds are measured on an amortised cost basis.
Derecognition of financial assets and liabilities
Financial assets
A financial asset (or, where applicable, a part of a financial
asset) is derecognised where:
-- the rights to receive cash flows from the asset have expired;
-- the Group retains the right to receive cash flows from the
asset, but has assumed an obligation to pay them in full without
material delay to a third party under a 'pass-through' arrangement;
or
-- the Group has transferred its rights to receive cash flows
from the asset and either (a) has transferred substantially all the
risks and rewards of the asset, or (b) has neither transferred nor
retained substantially all the risks and rewards of the asset, but
has transferred control of the asset.
2. Summary of significant accounting policies (continued)
Derecognition of financial assets and liabilities
(continued)
Financial liabilities
A financial liability is derecognised when the obligation under
the liability is discharged, cancelled or expires.
If 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 a derecognition of the original
liability and the recognition of a new liability such that the
difference in the respective carrying amounts, together with any
costs or fees incurred, are recognised in profit or loss. IAS 39
Financial Instruments: Recognition and Measurement regards the
terms of exchanged or modified debt as 'substantially different' if
the net present value of the cash flows under the new terms
(including any fees paid net of fees received) discounted at the
original effective interest rate is at least 10.0% different from
the discounted present value of the remaining cash flows of the
original debt instrument. The Group also considers qualitative
factors in assessing whether a modified financial liability is
'substantially different'. Where the modification is substantially
different, it accounts for this as an extinguishment of the
original liability even though a quantitative analysis may indicate
a less than 10.0% cash flow change.
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.
Under/over-lift
Under or over-lifted positions of hydrocarbons 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.
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.
Available-for-sale reserve
Gains and losses (with the exception of impairment losses)
arising from changes in available-for-sale financial investments
are recognised in the available-for-sale reserve until such time
that the investment is disposed of, where it is reclassified 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.
2. Summary of significant accounting policies (continued)
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.
Finance leases that transfer substantially all the risks and
benefits incidental to ownership of the leased item to the Group,
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.
Operating lease payments are recognised as an operating expense
in the income statement on a straight line basis over the lease
term.
Revenue and other operating income
Revenue is recognised to the extent that it is probable economic
benefits will flow to the Group and the revenue can be reliably
measured.
Oil and gas revenues comprise the Group's share of sales from
the processing or sale of hydrocarbons on an entitlement basis,
when the significant risks and rewards of ownership have been
passed to the buyer.
Tariff revenue is recognised in the period in which the services
are provided at the agreed contract rates.
Rental income is accounted for on a straight line basis over the
lease terms and is included in revenue in the income statement.
The Group uses various commodity derivative instruments to
manage some of the risks arising from fluctuations in commodity
prices. Such contracts include options, swaps and futures. Where
these derivatives have been designated as cash flow hedges of
underlying commodity price exposures, certain gains and losses
attributable to these instruments are deferred in other
comprehensive income and recognised in the income statement within
revenue and other operating income when the underlying hedged
transaction crystallises or is no longer expected to occur.
All other commodity derivatives within the scope of IAS 39 are
measured at fair value with changes in fair value recognised in the
income statement within revenue and other operating income.
Unrealised mark to market changes in the remeasurement of
derivative contracts are initially included in exceptional items
within profit or loss. When the derivative reaches maturity, the
gain or loss is realised and recycled to be included within
Business performance.
2. Summary of significant accounting policies (continued)
Re-measurements 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 routinely 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; and
-- 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.
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.
2. Summary of significant accounting policies (continued)
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') 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 allowances
The UK taxation regime provides for a reduction in ring fence
supplementary corporation tax where investments in new or existing
UK assets qualify for a relief known as investment allowances.
Investment allowances are only triggered when production from the
field commences. The Group is eligible for a number of investment
allowances which will materially reduce the level of future
supplementary corporation taxation. Investment allowances are
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 Adjustments and
December 2017 North Sea Malaysia All other segments Total segments eliminations Consolidated
$'000
-------------------- ---------- --------- ------------------- --------------- -------------------- -------------
Revenue:
External customers 535,850 119,892 - 655,742 (28,291) 627,451
Total Group 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
========== ========= =================== =============== ==================== =============
Year ended 31 Adjustments and
December 2016 North Sea Malaysia All other segments Total segments eliminations Consolidated
$'000
-------------------- ----------- ---------- ------------------- --------------- ------------------ -------------
Revenue:
External customers 485,609 108,215 - 593,824 204,299 798,123
Total Group revenue 485,609 108,215 - 593,824 204,299 798,123
=========== ========== =================== =============== ================== =============
Income/(expenses):
Depreciation and
depletion (209,194) (36,582) (33) (245,809) - (245,809)
Net impairment
reversal/(charge)
to oil and gas
assets 167,838 (19,967) - 147,871 - 147,871
Impairment reversal
of investments 48 - - 48 - 48
Exploration write
offs and
impairments (776) - - (776) - (776)
Loss on disposal of
assets (16,178) - - (16,178) - (16,178)
Segment
profit/(loss) 216,658 (5,836) (1,561) 209,261 135,818 345,079
=========== ========== =================== =============== ================== =============
Other disclosures:
Capital expenditure 646,489 4,585 9 651,083 277 651,360
=========== ========== =================== =============== ================== =============
3. Segment information (continued)
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 (loss)/profit:
Year ended 31 December Year ended
2017 31 December 2016
$'000 $'000
Segment profit/(loss) (73,281) 209,261
Finance income 2,213 1,440
Finance expense (149,292) (129,275)
Gains and losses on oil and foreign exchange derivatives (23,413) 135,818
Profit/(loss) before tax (243,773) 217,244
======================= ==================
Revenue from two customers (2016: three customers) each exceed
10% of the Group's consolidated revenue arising from sales of crude
oil and amounted respectively to $206.1 million in the North Sea
operating segment and $105.2 million in the Malaysia operating
segment (2016: $321.0 million and $85.7 million arising in the
North Sea operating segment and $89.9 million in 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 $119.1 million
located in Malaysia (2016: $128.1 million).
4. Re-measurements and exceptional items
Fair value
Year ended 31 December 2017 re-measurement Impairments and write offs Other Total
$'000 (i) (ii) (iii)
----------------------------------------------- ---------------- --------------------------- --------- -----------
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 re-measurements 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 recycling realised gains and losses
(including option premia) out of 'Re-measurements and exceptional
items' and into 'Business performance' profit or loss. In addition
a $1.3 million gain in respect to the disposal of Ascent Resources
loan notes was recognised in 2017. Refer to note 2 for further
details on the Group's accounting policies for derivatives and
'Re-measurements and exceptional items'.
(ii) Impairments and write offs includes an impairment of
tangible oil and gas assets totalling $172.0 million (2016:
impairment reversal of $147.9 million), together with a charge of
$2.7 million in relation to inventory write downs, a $0.02 million
impairment on the investment in Ascent Resources (2016: $0.05
million impairment) and a $0.2 million write back of previously
impaired exploration costs (2016: $0.8 million impairment/write
off). Further details on the tangible impairment are provided in
note 10.
(iii) Other mainly includes a gain in relation to the excess of
fair value over cost arising on the acquisition of the Magnus oil
field and other interests compromising of the $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 (see note 29). Other items include a 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 (see note 16). 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) Other tax exceptional items include $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.
4. Re-measurements and exceptional items (continued)
Impairments
Year ended 31 Fair value and write Debt Surplus lease Loss on
December 2016 re-measurement offs restructuring provision disposal Other Total
$'000 (i) (ii) (iii) (iv)
--------------- --------------- -------------- -------------- -------------- -------------- --------- ---------
Revenue and
other
operating
income (51,504) - - - - - (51,504)
Cost of sales (1,584) - - - - (1,264) (2,848)
Net impairment
reversal on
oil and gas
assets - 147,871 - - - - 147,871
Loss on
disposal of
intangible
oil and gas
assets - - - - (16,178) - (16,178)
Other income 2,837 48 - 22,948 - 5,721 31,554
Other expenses - (776) - - - (118) (894)
Finance costs 31,072 - (38,115) - - - (7,043)
--------------- --------------- -------------- -------------- -------------- -------------- --------- ---------
(19,179) 147,143 (38,115) 22,948 (16,178) 4,339 100,958
Tax on items
above 8,797 (67,037) 10,323 (9,179) - 506 (56,590)
Change in tax
rate (v) - - - - - (29,483) (29,483)
Increase in
the carrying
amount of
deferred tax
assets (vi) - - - - - 48,817 48,817
---------------
(10,382) 80,106 (27,792) 13,769 (16,178) 24,179 63,702
--------------- --------------- -------------- -------------- -------------- -------------- --------- ---------
(i) The Group's restructuring was deemed to result in a
substantial modification of the terms of the Group's credit
facility (see note 19). In accordance with IAS 39, the Group has
accounted for this substantial modification as an extinguishment of
the liability for the original credit facility and the recognition
of a new liability for the revised credit facility. In 2016, this
resulted in $15.0 million of unamortised costs associated with the
previous credit facility being expensed on extinguishment. The
costs of negotiating the modifications to the credit facility,
totalling $11.1 million and a $12.0 million restructuring fee,
payable to the credit facility lenders by March 2018, were
expensed. In 2016, these comprised an aggregate of $38.1 million of
debt restructuring costs.
(ii) The Group had an agreement to hire the Stena Spey drilling
vessel. Based on the drilling forecasts for 2016, it was expected
that the vessel would not be fully utilised over this period and
therefore a provision was recognised for unavoidable contracted
costs of $22.9 million. During the year ended 31 December 2016,
following changes to the Group's drilling schedule, the contracted
days were utilised in full and the provision of $22.9 million was
reversed in full.
(iii) During the year ended 31 December 2016, the Group disposed
of its interest in the Avalon prospect for cash proceeds of $1.5
million, resulting in a loss on disposal of $16.2 million (see note
12).
(iv) In 2016, other primarily included a $3.4 million reversal
of a provision for contingent consideration which was no longer
required following the results of the Eagle well drilled during the
year and a $1.3 million depreciation of the fair value uplift.
(v) The Finance Act 2016 enacted a change in the supplementary
charge tax rate, reducing it from 20% to 10%, and a change to
petroleum revenue tax rate, reducing it from 35% to 0%, both
effective from 1 January 2016. The Finance Act 2016 also enacted a
reduction in the mainstream corporation tax rate reducing it from
18% to 17% with effect from 1 April 2020.
The impact of these changes in tax rates in 2016 was a tax
charge of $29.5 million.
(vi) At the year ended 31 December 2016, the recovery of
deferred tax assets was reviewed which has led to a recognition of
previously impaired tax losses totalling $48.8 million. This write
back reflects the increase in value of the Group's assets following
a partial recovery of oil prices.
5. Revenue and expenses
(a) Revenue and other operating income
Year ended Year ended
31 December 31 December
2017 2016
$'000 $'000
Revenue from crude oil sales 636,966 577,822
Revenue from gas and condensate sales 2,822 3,628
Realised (losses)/gains on oil derivative contracts (see note 20(e)) (20,575) 255,803
Tariff revenue 7,029 4,915
Other operating revenue 1,851 142
Rental income 7,074 7,317
------------- -------------
Business performance revenue 635,167 849,627
Unrealised (losses)/gains on oil derivative contracts* (see note 20(e)) (7,716) (51,504)
------------- -------------
Total revenue and other operating income 627,451 798,123
============= =============
* 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).
(b) Cost of sales
Year ended Year ended
31 December 31 December
2017 2016
$'000 $'000
Cost of operations 299,721 285,040
Tariff and transportation expenses 62,208 58,139
Realised loss/(gain) on foreign exchange derivative contracts(i) (see note 20(e)) 4,848 66,898
Change in lifting position (20,643) 4,656
Crude oil inventory movement 237 (1,830)
Depletion of oil and gas assets (see note 10) 223,135 240,615
------------- -------------
Business performance cost of sales 569,506 653,518
Depletion of oil and gas assets (see note 10) 1,563 1,264
Write down of inventory 2,682 -
Unrealised (gains)/losses on foreign exchange derivative contracts(ii) (see note 20(e)) (9,726) 1,584
------------- -------------
Total cost of sales 564,025 656,366
============= =============
(i) The realised loss on foreign exchange derivative contracts
was $4.8 million for contracts related to capital expenditure
(2016: loss of $19.6 million related to operating expenditure and
loss of $47.3 million related to capital expenditure).
(ii) Unrealised gains and loss on foreign exchange derivative
contracts which are either ineffective for hedge accounting
purposes or 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
2017 2016
$'000 $'000
Staff costs (see note 5(f)) 79,138 86,773
Depreciation (see note 10) 4,500 3,930
Other general and administration costs 20,077 32,355
Recharge of costs to operations and joint venture partners (102,867) (112,168)
------------- -------------
848 10,890
============= =============
5. Revenue and expenses (continued)
(d) Other income
Year ended Year ended
31 December 31 December
2017 2016
$'000 $'000
Net foreign exchange gains - 51,867
Prior year general and administrative expenses recovery 5,101 -
Other income 1,706 69
------------- -------------
Business performance other income 6,807 51,936
Excess of fair value over consideration: Purchase option (see note 29) 22,300 -
Excess of fair value over consideration: Thistle decommissioning option (see note 29) 16,120 -
Excess of fair value over consideration: 25% acquisition value (see note 29) 10,314 -
Release of surplus lease provision - 22,948
Gain on disposal of financial assets 1,263 -
Change in provision for contingent consideration 423 4,056
Fair value movements on financial assets - 2,151
Decommissioning provision reduction - 1,627
Acquisition accounting adjustment - 694
Other exceptional income 193 78
Total other income 57,420 83,490
============= =============
(e) Other expenses
Year ended Year ended
31 December 31 December
2017 2016
$'000 $'000
Net foreign exchange losses 23,910 -
Exploration and evaluation expenses: Pre-licence costs expensed 43 68
Other 410 9
------------- -------------
Business performance other expenses 24,363 77
2014 PM8 cost recovery settlement agreement 10,329 -
Early termination of contracts 6,435 -
Write down of receivable 2,808 118
Exploration and evaluation expenses: written off and impaired - 776
Other expenses 786 -
Total other expenses 44,721 971
============= =============
(f) Staff costs
Year ended Year ended
31 December 31 December
2017 2016
$'000 $'000
Wages and salaries 48,773 47,089
Social security costs 4,686 4,458
Defined contribution pension costs 3,057 3,522
Expense of share-based payments (see note 18) 2,849 8,452
Other staff costs 2,486 2,709
Total employee costs 61,851 66,230
Contractor costs 17,287 20,543
Total staff costs 79,138 86,773
============= =============
The average number of persons employed by the Group during the
year was 506 (2016: 477).
5. Revenue and expenses (continued)
(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
2017 2016
$'000 $'000
Fees payable to the Company's auditor for the audit of the parent company
and Group financial statements 584 515
------------- -------------
Fees payable to the Company's auditor and its associates for other services:
The audit of the Company's subsidiaries 114 74
Audit related assurance services (interim review) 181 71
Tax advisory services 5 58
Corporate finance services(*) - 312
------------- -------------
300 515
------------- -------------
884 1,030
============= =============
*Relates to the reporting accountant's report on the unaudited
pro forma financial information in Company's prospectus for the
placing and open offer (see note 17).
6. Finance costs/income
Year ended Year ended
31 December 31 December
2017 2016
$'000 $'000
Finance costs:
Loan interest payable 74,434 50,789
Bond interest payable 63,463 59,689
Unwinding of discount on decommissioning provisions (see note 22) 11,471 10,724
Unwinding of discount on other provisions (see note 22) 1,838 3,173
Unwinding of discount on financial liabilities (see note 20(f)) 163 279
Fair value (gain)/loss on financial instruments at FVTPL (see note 20(e)) (15) 36,516
Finance charges payable under finance leases 31,273 -
Amortisation of finance fees on loans and bonds 2,760 5,910
Other financial expenses 5,902 10,501
191,289 177,581
Less: amounts capitalised to the cost of qualifying assets (42,269) (55,349)
------------- -------------
Business performance finance expenses 149,020 122,232
Fair value loss on financial instruments at FVTPL (see note 20(e)) - (31,072)
Debt restructuring costs (see note 4) - 38,115
Unwinding of discounts on other provisions 272 -
149,292 129,275
============= =============
Finance income:
Bank interest receivable 381 337
Unwinding of discount on financial asset (see note 20(f)) 1,832 1,017
Other financial income - 86
------------- -------------
2,213 1,440
============= =============
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
2017 2016
$'000 $'000
Current income tax
Current income tax charge 214 -
Adjustments in respect of current income tax of previous years (932) -
Current overseas income tax
Current income tax charge 11,191 11,269
Adjustments in respect of current income tax of previous years 263 (1,294)
------------- -------------
Total current income tax 10,736 9,975
Deferred income tax
Relating to origination and reversal of temporary differences (202,173) (4,756)
Adjustments in respect of changes in tax rates - 29,483
Adjustments in respect of deferred income tax of previous years 14,469 3,021
Deferred overseas income tax
Relating to origination and reversal of temporary differences (5,840) (7,511)
Adjustments in respect of deferred income tax of previous years (135) 1,820
------------- -------------
Total deferred income tax (193,679) 22,057
Income tax (credit)/expense reported in profit or loss (182,943) 32,032
============= =============
(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
2017 2016
$'000 $'000
(Loss)/profit before tax (243,773) 217,244
------------- -------------
Statutory rate of corporation tax in the UK of 40% (2016: 40%) (97,509) 86,898
Supplementary corporation tax non-deductible expenditure 21,170 (11,390)
Non-deductible expenditure(i) (7,673) 32,631
Non-deductible loss on disposals - 4
Petroleum revenue tax (net of income tax benefit)(ii) 3,703 (3,702)
North Sea tax reliefs (93,234) (102,149)
Tax in respect of non-ring fence trade (9,085) 27,653
Tax losses not recognised(iii) (11,230) (39,198)
Deferred tax rate changes - 29,483
Adjustments in respect of prior years 13,665 3,547
Overseas tax rate differences (4,163) 4,362
Share-based payments 1,475 3,154
Other differences (62) 739
------------- -------------
At the effective income tax rate of 75% (2016: 15%) (182,943) 32,032
============= =============
(i) Movement is primarily the impact of the excess of fair value over consideration
(ii) Movement is primarily the derecognition of Alba decommissioning asset
(iii) Current year tax credit is the re-recognition of non-ring
fence losses de-recognised in 2016
7. Income tax (continued)
(c) Deferred income tax
Deferred income tax relates to the following:
(Credit)/charge for the year recognised in profit or loss
Group balance sheet
2017 2016 2017 2016
$'000 $'000 $'000 $'000
Deferred tax liability
Accelerated capital
allowances 1,163,562 1,085,456 28,290 73,310
Other temporary differences - - - (36,850)
------------ ------------
1,163,562 1,085,456
Deferred tax asset
Losses (1,228,034) (1,060,036) (167,998) (59,477)
Decommissioning liability (254,008) (185,418) (68,590) 48,891
Other temporary differences (17,098) (31,717) 14,619 (3,817)
------------ ------------ --------------------------- ---------------------------
(1,499,140) (1,277,171)
Deferred tax expense (193,679) 22,057
=========================== ===========================
Net deferred tax
(assets)/liabilities (335,578) (191,715)
============ ============
Reflected in the balance
sheet as follows:
Deferred tax assets (398,263) (206,742)
Deferred tax liabilities 62,685 15,027
------------ ------------
Net deferred tax
(assets)/liabilities (335,578) (191,715)
============ ============
Reconciliation of net deferred tax assets/(liabilities) 2017 2016
$'000 $'000
At 1 January 191,715 79,327
Tax income/(expense) during the period recognised in profit or loss 193,679 (22,057)
Tax income/(expense) during the period recognised in other comprehensive income - 134,177
Deferred taxes acquired (see note 29) (49,816) 268
--------- ---------
At 31 December 335,578 191,715
========= =========
(d) Tax losses
The Group's deferred tax assets at 31 December 2017 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 2017 with respect to ring fence tax losses and allowances.
The impairment model used to assess the extent to which it is
appropriate to recognise the Group's UK tax losses as deferred tax
assets was run, using an oil price assumption of Dated Brent
forward curve in the years 2018 to 2021 followed by $70/bbl
inflated at 2.0% per annum from 2022. The results of the impairment
model demonstrated that it was appropriate to recognise a deferred
tax asset on $24.2 million
(2016: $214.3 million recognised deferred tax asset) of the
Group's UK ring fence corporate tax losses at
31 December 2017 based on expected future profitability. The
recognised loss amount results in a deferred tax credit of $9.7
million (2016: $85.7 million credit) for the year in respect of
losses and allowances that were previously not recognised as a
deferred tax asset.
The Group has unused UK mainstream corporation tax losses of
$290.2 million (2016: $285.8 million) for which no deferred tax
asset has been recognised at the balance sheet date due to
uncertainty of recovery of these losses.
The Group has unused overseas tax losses in Canada of
approximately CAD$13.5 million (2016: CAD$13.4 million) for which
no deferred tax asset has been recognised at the balance sheet
date. The tax losses in Canada have expiry periods of 20 years,
none of which expire in 2018, and which arose following the change
in control of the Stratic group in 2010.
The Group has unused Malaysian income tax losses of $5.2 million
(2016: $3.1 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.
7. Income tax (continued)
(e) Change in legislation
Finance Act 2016 enacted a change in the mainstream corporation
tax rate, reducing it from 18% to 17% with effect from 1 April
2020. The impact of the change in tax rate in 2016 was a tax charge
of $0.7 million.
Finance Act 2016 also enacted a change in the supplementary
charge tax rate, reducing it from 20% to 10% with effect from 1
January 2016 and a change to the petroleum revenue tax rate,
reducing it from 35% to 0% with effect from
1 January 2016. The impact of the change in tax rate in 2016 was
a tax charge of $28.9 million.
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 activities directly, 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
impact of these changes in the current year was a tax charge of
$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.
Basic and diluted earnings per share are calculated as
follows:
Weighted average number of
Profit /(loss) after tax Ordinary shares Earnings per share
Year ended 31 December Year ended 31 December Year ended 31 December
2017 2016 2017 2016 2017 2016
$'000 $'000 million million $ $
Basic (60,830) 185,212 1,128.1 815.3 (0.054) 0.227
Dilutive potential of
Ordinary shares
granted under
share-based incentive
schemes - - 53.0 24.6 - (0.006)
Diluted (60,830) 185,212 1,181.1 839.9 (0.054) 0.221
=============== ============ ================ ================ ============ ===========
Basic (excluding
exceptional items) (33,554) 121,510 1,128.1 815.3 (0.030) 0.149
=============== ============ ================ ================ ============ ===========
Diluted (excluding
exceptional items) (33,554) 121,510 1,181.1 839.9 (0.030) 0.145
=============== ============ ================ ================ ============ ===========
9. Dividends paid and proposed
The Company paid no dividends during the year ended 31 December
2017 (2016: none). At 31 December 2017, there are no proposed
dividends (2016: none).
10. Property, plant and equipment
Oil and gas assets Office furniture, fixtures and fittings Total
$'000 $'000 $'000
Cost:
At 1 January 2016 6,165,488 51,865 6,217,353
Additions 629,654 2,857 632,511
Acquired (see note 29) 40,695 - 40,695
Change in cost carry liabilities 26,042 - 26,042
Change in decommissioning provision (34,423) - (34,423)
Change in cost recovery provision (40,389) - (40,389)
Reclassification from intangible assets
(see note 12) 276 - 276
At 31 December 2016 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 (see
note 22) 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
------------------- ---------------------------------------- -----------
Accumulated depletion and impairment:
At 1 January 2016 3,752,020 28,661 3,780,681
Charge for the year 241,879 3,930 245,809
Net impairment reversal for the year (147,871) - (147,871)
At 31 December 2016 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
------------------- ---------------------------------------- -----------
Net carrying amount:
At 31 December 2017 3,827,997 20,625 3,848,622
=================== ======================================== ===========
At 31 December 2016 2,941,315 22,131 2,963,446
=================== ======================================== ===========
At 1 January 2016 2,413,468 23,204 2,436,672
=================== ======================================== ===========
10. Property, plant and equipment (continued)
During 2017 the Group acquired a 25% interest in Magnus oil
field and other interests (see note 29), resulting in an
acquisition of assets at a value of $124.5 million allocated to
property, plant and equipment.
During the year ended 31 December 2017, the Group's lease from
Armada Kraken PTE Limited ('BUMI') of the 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).
During the year ended 31 December 2016, the Group acquired an
additional 10.5% interest in the Kraken asset and an additional
15.15% interest in the West Don field, resulting in aggregate
purchase consideration of $40.7 million allocated to property,
plant and equipment (see note 29).
During the year ended 31 December 2016, a liability of $26.6
million was recognised for the carry payable for the Kraken field
following the finalisation of a reserve determination (see note
22). The amount payable was dependent upon the dated Brent forward
curve at the date of the reserve determination. Change in carry
liabilities also includes a $0.2 million decrease in the liability
(see note 20(f)) for Malaysian assets (2016: decrease of $0.5
million).
Impairments to the Group's producing oil and gas assets and
reversals of impairments are is set out in the table below:
Impairment (charge)/reversal Recoverable amount(iv)
------------------------------- --------------------------
Year ended Year ended
31 December 31 December 31 December 31 December
2017 2016 2017 2016
$'000 $'000 $'000 $'000
Central North Sea(i) (93,288) (184,437) 16,873 296,989
Northern North Sea(ii) (94,428) 352,275 284,858 848,628
Malaysia(iii) 15,745 (19,967) 48,301 39,748
Net impairment reversal/(charge) (171,971) 147,871
--------------- --------------
(i) Amounts disclosed for Central North Sea include Alma/Galia
and Alba. The impairment of Alma/Galia is primarily driven by
performance issues relating to Electric Submersible Pumps and
underlying natural declines in fields.
(ii) Northern North Sea includes Heather Broom, Thistle/Deveron
and the Dons fields. The impairments are attributable primarily to
underlying natural declines in the fields.
(iii) The amounts disclosed for Malaysia relate to the Tanjong Baram field.
(iv) 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 2017 includes $71.1 million
(2016: $1,536.6 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 2017 was $42.3 million
(2016: $55.3 million) and relate to the Kraken development
project (2016: Kraken and Scolty/Crathes development projects). The
weighted average rate used to determine the amount of borrowing
costs eligible for capitalisation is 7.0% (2016: 6.2%).
The net book value of property, plant and equipment held under
finance leases and hire purchase contracts at
31 December 2017 was $756.3 million (2016: $nil) of oil and gas
assets.
11. Goodwill
A summary of goodwill is presented below:
2017 2016
$'000 $'000
Cost and net carrying amount
At 1 January and 31 December 189,317 189,317
--------- ---------
The 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 discounted at the Group's post-tax
weighted average cost of capital ('WACC') of 10.0% (2016: 10.0%).
Risks specific to assets within the CGU are reflected within the
cash flow forecasts.
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 Dated Brent forward price curve for the
first three years and thereafter at $70/bbl from 2021.
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 reserve assessment experts.
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
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% (2016: 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 7% (2016: 9%) from the
prices outlined above. Goodwill would need to be fully impaired if
the oil price or production volumes (on a CGU weighted average
basis) were to fall by 16% from the prices outlined above (2016:
13%). 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
Cost Accumulated impairment Net carrying amount
$'000 $'000 $'000
At 1 January 2016 226,715 (180,185) 46,530
Additions 18,849 - 18,849
Disposal of interests in licences (17,644) - (17,644)
Write off of relinquished licences previously impaired (1,311) 1,311 -
Unsuccessful exploration expenditure written off (458) - (458)
Change in decommissioning provision 3,649 - 3,649
Reclassified to tangible fixed assets (see note 10) (276) - (276)
Impairment charge for the year - (318) (318)
----------
At 31 December 2016 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 previously 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
========== ======================= ====================
During the year ended 31 December 2017, the Group continued to
develop the Kraken field resulting in the additions to intangibles.
The Group also concluded on the unsuccessful exploration costs
resulting in a write off of $3.1 million.
During the year ended 31 December 2016, the Group disposed of
its interest in the Avalon prospect for $1.5 million, realising a
loss on disposal of $16.2 million (see note 4). The additions in
2016 and the related change in decommissioning provision primarily
related to the Eagle well which was drilled during 2016.
13. Investments
$'000
Cost:
At 1 January 2016, 31 December 2016 and 31 December 2017 19,231
=========
Provision for impairment:
At 1 January 2016 (19,108)
Impairment reversal/(charge) for the year 48
At 31 December 2016 (19,060)
Impairment (charge)/reversal for the year (19)
At 31 December 2017 (19,079)
=========
Net carrying amount:
At 31 December 2017 152
=========
At 31 December 2016 171
=========
At 1 January 2016 123
=========
The accounting valuation of the Group's shareholding (based on
the quoted share price of Ascent) resulted in a non-cash impairment
charge of $0.02 million in the year to 31 December 2017 (2016:
impairment reversal of $0.05 million).
14. Inventories
2017 2016
$'000 $'000
Crude oil 12,422 13,199
Well supplies 65,623 61,786
78,045 74,985
======== =======
During 2017, inventories of $2.9 million (2016: $2.0 million)
were recognised within cost of sales in the statement of
comprehensive income. Included within this balance is $2.7 million
as a result of the write down of inventories to net realisable
value (2016: $2.0 million). The write downs are included in cost of
sales.
15. Trade and other receivables
2017 2016
$'000 $'000
Current
Trade receivables 80,743 44,363
Joint venture receivables 87,037 91,220
Under-lift position 32,299 11,886
VAT receivable 11,739 9,098
Other receivables 1,844 17,971
--------- --------
213,662 174,538
Prepayments and accrued income 14,092 28,128
--------- --------
227,754 202,666
========= ========
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 2017, no impairment
provision for trade receivables was necessary (2016: 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 2017 and
31 December 2016, no other receivables were determined to be
impaired.
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.
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 2017 is restricted cash of $3.5 million (2016: $6.6
million). $2.8 million of this relates to cash held in escrow in
respect of the unwound acquisition of the Tunisian assets of PA
Resources (2016: $6.0 million) and the remainder relates to cash
collateral held to issue bank guarantees in Malaysia.
Cash and cash equivalents also include an amount of $3.9 million
(2016: $9.4 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 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 each Share capital Share premium Total
Authorised, issued and fully paid Number $'000 $'000 $'000
At 1 January 2017 1,159,398,871 83,342 125,297 208,639
Issuance of equity shares 26,685,433 1,763 - 1,763
At 31 December 2017 1,186,084,304 85,105 125,297 210,402
================================ ============== ============== ========
The share capital comprises only one class of Ordinary share.
Each Ordinary share carries an equal voting right and right to a
dividend.
On 21 November 2016, the Company completed a placing and open
offer, pursuant to which 356,738,114 new Ordinary shares were
issued at a price of GBP0.23 per share, generating gross aggregate
proceeds of $101.6 million. 233,858,061 of the new shares issued
resulted from existing shareholders taking up their entitlement
under the open offer to acquire four new Ordinary shares for every
nine Ordinary shares previously held. On 21 November 2016,
10,739,486 shares were acquired by the Employee Benefit Trust
pursuant to the open offer.
At 31 December 2017, there were 56,023,671 shares held by the
Employee Benefit Trust (2016: 33,563,282).
On 18 October 2017, 26,685,433 shares were issued to the
Employee Benefit Trust with the remainder of the movement in the
year due to shares used to satisfy awards made under the Company's
share-based incentive schemes.
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:
2017 2016
$'000 $'000
Deferred Bonus Share Plan 1,069 1,274
Restricted Share Plan 1,024 920
Performance Share Plan (68) 4,378
Sharesave Plan 230 93
Executive Director bonus awards 594 1,787
------ ------
2,849 8,452
====== ======
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.
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:
2017 2016
----- -----
Weighted average fair value per share 37p 32p
The following shows the movement in the number of share awards
held under the DBSP scheme:
2017 2016
Number Number
Outstanding at 1 January 2,508,026 2,554,269
Granted during the year (i) 1,357,040 1,256,836
Exercised during the year (1,214,427) (1,199,434)
Forfeited during the year (18,842) (103,645)
Outstanding at 31 December 2,631,797 2,508,026
Exercisable at 31 December - -
(i) On 21 November 2016, at its discretion, the Company
increased the number of shares receivable by participants in the
DBSP by a factor of 1.09265387 so that the value of their rights
under outstanding awards was not adversely affected by the open
offer. This resulted in the grant of 263,790 additional share
awards. The fair value of these awards of $0.1 million 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 2017 was 0.9 years
(2016: 1.0 years).
18. Share-based payment plans (continued)
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:
2017 2016
----- -----
Weighted average fair value per share 33p 32p
The following table shows the movement in the number of share
awards held under the RSP scheme:
2017 2016
Number Number
Outstanding at 1 January 12,564,319 5,815,692
Granted during the year (i) 587,216 8,526,792
Exercised during the year (893,465) (530,109)
Forfeited during the year (77,299) (1,248,056)
Outstanding at 31 December 12,180,771 12,564,319
Exercisable at 31 December 3,451,209 3,369,261
(i) On 21 November 2016, at its discretion, the Company
increased the number of shares receivable by participants in the
RSP by a factor of 1.09265387 so that the value of their rights
under outstanding awards was not adversely affected by the open
offer. This resulted in the grant of 1,164,647 additional share
awards. The fair value of these awards of $0.4 million 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 2017 was 4.8 years
(2016: 5.6 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 per share; and 10%
relates to new 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:
2017 2016
----- -----
Weighted average fair value per share 33p 8p
The following table shows the movement in the number of share
awards held under the PSP scheme:
2017 2016
Number Number
Outstanding at 1 January 61,023,323 20,348,024
Granted during the year (i) 16,302,086 47,934,689
Exercised during the year (2,412,846) (2,139,477)
Forfeited during the year (4,730,839) (5,119,913)
------------ ------------
Outstanding at 31 December 70,181,724 61,023,323
Exercisable at 31 December 2,816,844 2,104,559
(i) On 21 November 2016, at its discretion, the Company
increased the number of shares receivable by participants in the
PSP by a factor of 1.09265387 so that the value of their rights
under outstanding awards was not adversely affected by the open
offer. This resulted in the grant of 5,343,888 additional share
awards. The fair value of these awards of $1.0 million 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 2017 was 4.0 years
(2016: 4.5 years).
18. Share-based payment plans (continued)
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:
2017 2016
Weighted average fair value per share 8p 4p
The following shows the movement in the number of share options
held under the Sharesave plan:
2017 2016
Number Number
Outstanding at 1 January 12,657,432 6,949,242
Granted during the year (i) 1,299,185 10,823,513
Exercised during the year (17,213) (9,562)
Forfeited during the year (1,105,135) (5,105,761)
Outstanding at 31 December 12,834,269 12,657,432
Exercisable at 31 December - -
(i) On 21 November 2016, at its discretion, the Company
increased the number of options receivable by participants in the
Sharesave plan by a factor of 1.09265387 so that the value of their
rights under outstanding awards was not adversely affected by the
open offer. This resulted in the grant of 1,098,593 additional
share options. The exercise price of outstanding options was also
reduced by multiplying by a factor 0.91520291. The incremental fair
value of these adjustments of $0.1 million 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 2017 was 1.7 years
(2016: 3.1 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:
2017 2016
Restated
Weighted average fair value per share 39p 32p
The following table shows the movement in the number of share
awards held under the Executive Director bonus plan:
2017 2016
Restated
Number Number
Outstanding at 1 January 2,869,393 1,203,517
Granted during the year 779,846 1,665,876
Cash settled in the year (726,505) -
Exercised during the year (477,012) -
Forfeited during the year - -
Outstanding at 31 December 2,445,722 2,869,393
Exercisable at 31 December - -
The weighted average contractual life for the share awards
outstanding as at 31 December 2017 was 0.6 years
(2016: 0.6 years).
19. Loans and borrowings
The Group's loans are carried at amortised cost as follows:
2017 2016
Principal Fees Total Principal Fees Total
$'000 $'000 $'000 $'000 $'000 $'000
Credit facility 1,099,966 - 1,099,966 1,037,516 - 1,037,516
Crude oil prepayment 75,556 (378) 75,178 - - -
SVT Working Capital Facility 25,622 - 25,622 - - -
Tanjong Baram project finance loan 8,531 (292) 8,239 24,850 (690) 24,160
Trade creditor loan 10,000 - 10,000 40,000 - 40,000
Total loans 1,219,675 (670) 1,219,005 1,102,366 (690) 1,101,676
Due within one year 330,012 49,601
Due after more than one year 888,993 1,052,075
Total loans 1,219,005 1,101,676
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 revolving credit facility was
payable at LIBOR plus a margin of 2.50% to 4.25%, dependent on
specified covenant ratios.
On 21 November 2016, pursuant to the 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 (see
2016 debt restructuring costs, note 4). The $12 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 (see note 4).
At 31 December 2017, the carrying amount of the Credit Facility
on the balance sheet was $1,100.0 million, comprising the loan
principal drawn down of $1,095.2 million, plus $4.8 million of
interest capitalised to the PIK amount
(2016: $1,037.5 million, being loan principal drawn down of
$1,037.3 million plus $0.2 million of interest capitalised to the
PIK amount).
At 31 December 2017, after allowing for letter of credit
utilisation of $7.0 million, $97.8 million remained available for
drawdown under the Credit Facility (2016: $6.4 million and $156.3
million respectively).
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. A single
amortisation of the RCF is due of $270 million in October 2018.
19. Loans and borrowings (continued)
Crude oil prepayment transaction
On 25 October 2017, the Group entered into a $80 million crude
oil prepayment ('Prepay') with Mercuria Energy Trading SA.
Repayment will be 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 Prepay is payable at 1 month USD LIBOR
plus a margin of 7.0%. The prepayment transaction is being
undertaken on an unsecured basis.
At 31 December 2017, the carrying amount of the Prepay on the
balance sheet was $75.6 million, compromising of the initial draw
down of $80.0 million, less the repayment of $4.4 million of the
principal. $0.3 million of interest is accrued on the balance
sheet.
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
installments 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 finance loan
During the year ended 31 December 2015, the Group entered into a
five year $35 million loan facility in Malaysia. Interest is
payable at USD LIBOR plus a margin of 2.25%.
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, together with accrued
interest at a rate of 7.0% per annum, is repayable in instalments
from 2018. A bonus of up to $1.7 million was payable at 31 December
2017 if the oil price was above $75/bbl in any period of 180
consecutive days between 1 October 2016 and 31 December 2017. At 31
December 2017, no bonus payment had been made or was due to be
paid.
The bonus amount was accounted as an embedded derivative, which
had a valuation of $nil at 31 December 2017 and 2016.
19. Loans and borrowings (continued)
Bonds
The Group's bonds are carried at amortised cost as follows:
2017 2016
Principal Fees Total Principal Fees Total
$'000 $'000 $'000 $'000 $'000 $'000
High yield bond 720,827 (8,467) 712,360 677,482 (10,460) 667,022
Retail bond 224,048 (2,057) 221,991 191,258 (2,541) 188,717
Total bonds due after more than one year 944,875 (10,524) 934,351 868,740 (13,001) 855,739
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.
The amendments to the high yield bond were not deemed to be a
substantial modification and therefore $5.0 million of advisors'
fees directly attributable to the modification of the high yield
bond were adjusted against the carrying value of the bond and are
being amortised over bond's remaining term.
The fair value of the high yield bond was estimated to be $519.9
million (2016: $488.0 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.
The amendments to the retail bond were not deemed to be a
substantial modification and therefore $0.8 million of advisors'
fees directly attributable to the modification of the retail yield
bond were adjusted against the carrying value of the bond and are
being amortised over bond's remaining term.
The bond had a fair value of $161.6 million (2016: $138.7
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
2017 2016
Assets Liabilities Assets Liabilities
$'000 $'000 $'000 $'000
Commodity contracts (at fair value through profit or loss) - 41,996 2,973 34,548
Foreign exchange contracts (at fair value through profit or loss) - - - 9,726
Interest rate swap designated as cash flow hedge (at fair value through
OCI) 36 - 41 -
Other receivables (loans and receivables) 61,701 - 36,328 -
Other liabilities (at amortised cost) - 19,211 - -
Total current 61,737 61,207 39,342 44,274
Other receivables (loans and receivables) 8,191 - 23,429 -
Other liabilities (at amortised cost) - 7,121 - 19,767
Total non-current 8,191 7,121 23,429 19,767
(b) Commodity contracts
The Group uses put and call options and swap contracts to manage
its exposure to the oil price.
Oil price hedging
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. During 2017,
losses totalling $5.2 million were recognised within unrealised
revenue in the income statement.
The Group has not entered into any other put options within
2017. All put options entered into in 2016 matured within the year
ended 31 December 2016. In 2016, gains of $193.2 million were
included in realised revenue in the income statement in respect of
these matured options and $2.5 million of gains deferred in the
prior year on the early close-out of effective hedges were
recognised in realised revenue. Mark to market losses on the time
value element of the put options in 2016 totalling $5.4 million was
recognised in finance costs. Of this amount, $36.5 million was
recognised within the Group's Business performance results as it
relates to the amortisation of the option premium paid, over the
life of the option. The balance of the mark to market losses were
recognised as an exceptional credit/charge in line with the Group's
accounting policy.
Gains totalling $43.9 million were realised during 2016 in
respect to fixed price oil swap contracts. These contracts were for
2 million barrels of 2016 production with a fixed price of
$66.64/bbl and were designated as effective hedges at 31 December
2015. An unrealised gain of $5.8 million was recognised as an
exceptional item in the income statement.
Commodity derivative contracts at fair value through profit or
loss ('FVTPL')
Commodity derivative are designated as at FVTPL, 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 2017, losses totalling $28.3
million (2016: losses of $35.3 million) were recognised in respect
of commodity contracts designated as FVTPL. This included losses
totalling $20.6 million (2016: gains of
$16.2 million) realised on contracts that matured during the
year, and mark to market losses totalling $7.7 million (2016:
losses of $51.5 million). Of the realised amounts recognised during
the year, $10.4 million (2016: $31.2 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.
The mark to market of the Group's open contracts as at 31
December 2017 was a 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
(2016: $40.5 million in respect of fixed price swap contracts
for 5,998,000 barrels of 2017 production at a weighted average
price of $51.3/bbl). The mark to market position on the Group's
other commodity derivative contracts (including contracts to
purchase crude oil for trading purposes which are accounted for as
a derivative), was $nil
(2016: asset of $8.9 million).
20. Other financial assets and financial liabilities (continued)
(c) Foreign currency contracts
The Group enters into a variety of foreign currency contracts,
including Sterling, Euros and Norwegian Kroner. During the year
ended 31 December 2017, these contracts resulted a realised gain of
$0.4 million recognised in the income statement (2016: similar
contracts resulted in a realised loss of $57.6 million and an
unrealised gain of $7.7 million).
During 2017, the Group has continued to use an exchange
structure to manage risk. The first exchange structure was entered
into in 2016 and allowed the counterparty to elect to sell GBP47.5
million to EnQuest at an exchange rate of $1.4:GBP1 or purchase 1.3
million barrels of oil at $58/bbl. This structure expired on 30
June 2017. The second exchange structure allowed the counterparty
to elect to sell GBP66 million to EnQuest at an exchange rate of
$1.2:GBP1 or purchase 1.5 million barrels of oil at $60/bbl. This
structure expired on 31 December 2017. From the exchange structures
in the year, $4.8 million was recognised within other foreign
currency contracts within cost of sales and no costs within other
operating income (2016: $9.3 million and $nil respectively).
(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 Groups Malaysian loan into a fixed rate
of 1.035% until 2018. The swap, which is effective from a hedge
accounting perspective, has a net asset fair value of $0.04 million
(2016: $0.04 million). The impact recognised within finance
expenses on the income statement was $0.02 million (2016: $0.06
million).
(e) 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 Realised Unrealised Realised Unrealised Realised Unrealised
31 December 2017 $'000 $'000 $'000 $'000 $'000 $'000
---------
Call options 880 (18,670) - - - -
Put options - - - - - -
Commodity swaps (23,754) 14,144 - - - -
Commodity futures (437) (363) - - - -
Purchase and sale of crude oil 2,736 (2,827) - - - -
Foreign exchange swaps - - - 433 - -
Other forward currency contracts - - (4,848) 9,293 - -
Interest rate swap - - - - 15 (38)
(20,575) (7,716) (4,848) 9,726 15 (38)
Revenue and other operating income
Cost of sales Finance costs
Year ended Realised Unrealised Realised Unrealised Realised Unrealised
31 December 2016 $'000 $'000 $'000 $'000 $'000 $'000
---------
Call options 27,916 (16,654) - - - -
Put options 195,701 - - - (36,458) 31,072
Commodity swaps 31,084 (37,823) - - - -
Commodity futures 426 146 - - - -
Purchase and sale of crude oil 676 2,827 - - - -
Foreign exchange swap contracts - - (1,034) - - -
Other forward currency contracts - - (65,865) (1,584) - -
Interest rate swap - - - - (58) -
255,803 (51,504) (66,899) (1,584) (36,516) 31,072
20. Other financial assets and financial liabilities (continued)
(f) Other receivables and liabilities
Other receivables Other liabilities
$'000 $'000
At 1 January 2016 22,897 7,684
Additions during the year 42,878 12,379
Change in fair value 2,151 (575)
Utilised during the year (9,058) -
Unwinding of discount 1,017 279
Foreign exchange (128) -
At 31 December 2016 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
Comprised of:
Financial carry - 7,211
Accrued waiver fee - 12,000
KUFPEC receivable 7,065 -
BUMI receivable 24,407 -
Decommissioning of Magnus and other interests option - 4,214
Thistle decommissioning option 16,120 -
Purchase option 22,300
Other - 2,907
Total 69,892 26,332
Classified as:
Current 61,701 19,211
Non-current 8,191 7,121
69,892 26,332
20. Other financial assets and financial liabilities (continued)
(f) Other receivables and liabilities (continued)
Other receivables
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. $7.1 million was received during the year ended 31
December 2017
and the remaining receivable, discounted to present value, had a
carrying value of $7.1 million at 31 December 2017 (2016: $14.0
million). Unwinding of discount of $0.2 million is included within
finance income for the year ended
31 December 2017 (2016: $0.4 million).
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 during
2018 and onwards. Included within other receivables at 31 December
2017 is an amount of $24.4 million representing the discounted
value of EnQuest's share of these repayments
(2016: $43.5 million). A total of $20.1 million was collected
during the period. Unwinding of discount of $1.6 million is
included within finance costs in the twelve months ended 31
December 2017.
As part of the Magnus and other interests acquisition (see note
29), EnQuest entered into an option to undertake the
decommissioning of Thistle. The financial asset of $16.1 million
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 estimate cash outflow to settle the liability
assumed.
In addition, the Group has an option to acquire the remaining
75% of the Magnus oil field and BP's interest in the associated
infrastructure for a value of $300 million. This option lapses in
January 2019. In line with IAS 39, a discounted value of $22.3
million has been attributed to this option (see note 29).
Other receivables at 31 December 2016 also included $2.3 million
representing the fair value of a convertible loan note from Ascent.
This loan note was sold during the first half of 2017, realising a
gain of $1.3 million.
Other liabilities
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. The discounted value of $7.2 million has been
disclosed as a financial liability (2016: $7.4 million). Unwinding
of the discount of $0.2 million is included within finance expense
for the year ended 31 December 2017 (2016: $0.3 million).
In addition, included in other liabilities is an accrued 'waiver
fee' of $12.0 million payable to the Credit Facility lenders in
relation to the restructuring of the facility in November 2016 (see
note 19). The amount is payable by March 2018.
As part of the Magnus and other interests acquisition (see note
29), EnQuest agreed to pay additional consideration in relation to
the management of the physical decommissioning costs of Thistle and
Deveron. The financial liability of $4.2 million relates to the
amount due to BP by reference to 7.5% of BP's actual
decommissioning costs on an after tax basis.
21. Fair value measurement
The following table provides the fair value measurement
hierarchy of the Group's assets and liabilities:
31 December 2017 Quoted prices in active Significant observable Significant unobservable
Total markets inputs inputs
(Level 1) (Level 2) (Level 3)
$'000 $'000 $'000 $'000
Assets measured at fair
value:
Derivative financial
assets
Interest rate swap(ii) 36 - 36 -
Other financial assets
Available-for-sale
financial investments:
Quoted equity shares 152 152 - -
Thistle decommissioning
option 16,120 - - 16,120
Purchase option 22,300 - - 22,300
Liabilities measured at
fair value:
Derivative financial
liabilities
Commodity derivative
contracts(i) 41,996 - 41,996 -
Other financial liability
Decommissioning of Magnus
and other interests
option 4,214 - - 4,214
Liabilities for which fair
values are disclosed (see
notes 19 and 24)
Interest bearing loans and
borrowings 1,219,675 - - 1,219,675
Obligations under finance
leases 797,933 - - 797,933
Sterling 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.
31 December 2016 Quoted prices in active Significant observable Significant unobservable
Total markets inputs inputs
(Level 1) (Level 2) (Level 3)
$'000 $'000 $'000 $'000
Assets measured at fair
value:
Derivative financial
assets
Commodity derivative
contracts(i) 2,973 - 2,973 -
Interest rate swap(ii) 41 - 41 -
Other financial assets
Available-for-sale
financial investments:
Quoted equity shares 171 171 - -
Loans and receivables
Other receivables(i) 2,270 - 2,270 -
Liabilities measured at
fair value:
Derivative financial
liabilities
Commodity derivative
contracts(i) 34,548 - 34,548 -
Foreign currency
derivative contracts(ii) 9,726 - 9,726 -
Liabilities for which
fair values are disclosed
(see notes 19 and 24)
Interest bearing loans
and borrowings 1,102,366 - - 1,102,366
Obligations under finance - - - -
leases
Sterling retail bond 138,727 138,727 - -
High yield bond 491,405 - 491,405 -
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 re-assessing
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 (2016: 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 contingent
consideration (see note 24), which are valued in accordance with
the Group's accounting policies.
22. Provisions
Decommissioning Cost recovery Contingent Surplus lease
provision Carry provision provision Consideration provision Total
$'000 $'000 $'000 $'000 $'000 $'000
At 1 January 2016 506,770 - 127,121 26,269 26,417 686,577
Additions during
the year 44,454 - - - - 44,454
Acquisitions 15,153 - - - - 15,153
Changes in
estimates (76,855) 26,591 (40,389) (4,056) (22,604) (117,313)
Unwinding of
discount 10,724 - 2,797 367 9 13,897
Utilisation (6,355) (21,100) - - (421) (27,876)
Foreign exchange - - - - (585) (585)
At 31 December
2016 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) - 194 3,290
Change in fair
value - - - (423) - (423)
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
Classified as
Current 11,138 - 5,178 26,512 387 43,215
Non-current 628,113 - 18,733 56,654 2,499 705,999
639,251 - 23,911 83,166 2,886 749,214
Decommissioning provision
The Group makes full provision for the future costs of
decommissioning its production facilities and pipelines on a
discounted basis. With respect to the Heather field, the
decommissioning provision is based on the Group's contractual
obligation of 37.5% of the decommissioning liability rather than
the Group's equity interest in the field.
The Group's total provision represents the present value of
decommissioning costs which are expected to be incurred up to 2033
assuming no further development of the Group's assets. The
liability is discounted at a rate of 2.0%
(2016: 2.3%). The unwinding of the discount is classified as a
finance cost (see note 6).
Acquisitions during the year ended 31 December 2016 reflect
amounts associated with the additional interests in the Kraken and
West Don fields acquired during the year which were $7.5 million
and $7.6 million, respectively (see note 29).
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 2017 were renewed for
12 months, subject to on-going compliance with
the terms of the Group's borrowings. At 31 December 2017, the
Group held surety bonds totalling $129.6 million (2016: $118.5
million).
Carry provision
Consideration for the acquisition of 40% of the Kraken field
from Cairn (previously Nautical) and First Oil PLC ('First Oil') 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 2017 (2016: $21.1 million paid and $5.5 million
remaining).
22. Provisions (continued)
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 2017 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% (2016: 2.3%).
During 2017, the Group entered into discussions with Petronas in
relation to the prior period PM8 cost recovery at the PM8
concession. A provision has been made for the expected payments
that the Group will make as part of the settlement agreement. The
provision is expected to be paid in two parts during 2018 and 2019,
as disclosed within current and non-current provisions. At 31
December 2017, the provision was $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. $8.0 million
is due on the later of one year after first oil or 30 January 2018.
In addition, further payments will become due if the oil price
rises above $75/bbl on a linear basis up to $100/bbl, with a cap on
total payments of $20.0 million. The cash flows have been
discounted using a 2.0% discount rate (2016: 3.0%). An option model
has been used to value the element of the consideration that is
contingent on the oil price and has resulted in a credit to the
income statement of $0.4 million for the year ended
31 December 2017 (2016: $0.7 million). The carrying value of the
Scolty/Crathes contingent consideration at
31 December 2017 is $8.1 million (31 December 2016: $17.3
million).
In addition, there is consideration due subject to future
exploration success which, having been reassessed for the year
ended 31 December 2017, continues to be held at $5.3 million.
On 1 December 2017 the acquisition of the Magnus oil field and
other interests (see note 29) was funded through a vendor loan from
BP, recognised as contingent consideration at a fair value of $66.6
million. 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 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 of around 3 years.
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%
(2016: 2.3%) discount rate.
At 31 December 2017, the provision was $2.9 million (2016: $2.8
million).
23. Trade and other payables
2017 2016
$'000 $'000
Current
Trade payables 144,584 232,277
Accrued expenses 271,686 183,753
Over-lift position 23,173 35,058
Joint venture creditors 1,632 456
Other payables 5,014 1,304
--------- ---------
446,089 452,848
========= =========
Classified as:
Current 367,312 410,261
Non-current 78,777 42,587
--------- ---------
446,089 452,848
========= =========
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 2018 and
the balance is expected to be fully settled in 2019.
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:
2017 2016
$'000 $'000
Due in less than one year 7,177 4,296
Due in more than one year but not more than five years 27,286 17,412
Due in more than five years 75,536 62,990
109,999 84,698
Lease payments recognised as an operating lease expense during
the year amounted to $5.3 million
(2016: $4.8 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 $7.1 million
(2016: $9.4 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:
2017 2016
$'000 $'000
Due in less than one year 1,638 202
Due in more than one year but not more than five years 7,141 5,877
Due in more than five years 4,686 5,869
13,465 11,948
Sub-lease rent recognised during the year amounted to $1.3
million (2016: $1.6 million).
24. Commitments and contingencies (continued)
(iii) Finance lease commitments
The Group had the following obligations under finance leases as
at the balance sheet date:
2017 2017 2016 2016
Minimum payments Present value of payments Minimum payments Present value of payments
$'000 $'000 $'000 $'000
Due in less than one year 173,846 118,009 - -
Due in more than one year
but not more than five
years 460,960 289,949 - -
Due in more than five years 456,374 389,975 - -
1,091,180 797,933 - -
Less future financing
charges 293,247 - - -
797,933 797,933 - -
Finance leases with an effective borrowing rate of 8.12% were
entered into during the year (see note 10).
On 20 December 2013, the Group entered into a bareboat charter
with BUMI for the lease of an FPSO vessel for the Kraken field.
BUMI constructed the vessel and the Group made an initial
prepayment of $100.0 million during 2014.
In August 2016, it was agreed that $65.0 million of this
prepayment would be refunded (see note 20(f)).
In June 2017, the Group's lease of the FPSO 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. The lease liability is
carried at $797.9 million as at 31 December 2017, of which $118.0
million is classified as a current liability. Finance lease
interest of
$31.3 million has been recognised within finance costs.
(iv) Capital commitments
At 31 December 2017, the Group had capital commitments excluding
the above lease commitments amounting to $33.8 million (2016:
$267.3 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 on-going 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.
There are a number of contractual matters not agreed between the
Group and BUMI relating to the charter of the FPSO on the Kraken
field. The Group considers that these matters will not adversely
impact its payment obligations in relation to the charter.
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 28 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 2017 (2016: none).
Share subscription
In 2016, subscription for new ordinary shares pursuant to the
placing and open offer (see note 17) at the issue price of GBP0.23
per share:
-- Double A Limited ('Double A'), a company beneficially owned
by the extended family of Amjad Bseisu, took up its entitlement in
the open offer, subscribing for 31,735,702 shares;
-- Directors and key management personnel took up their
entitlement in the open offer, subscribing for 423,540 new ordinary
shares;
-- Key management personnel participated in the placing,
subscribing for 412,608 new ordinary shares; and
-- Close family members of Amjad Bseisu and their associated
undertakings participated in the placing, subscribing for 2,940,304
shares.
Commission related to the placing
Double A made a commitment to subscribe for up to 91,224,079 new
Ordinary shares under the placing (subject to clawback to satisfy
valid applications under the open offer). In consideration of
Double A's commitment, the Company agreed to pay Double A
commission equal to 1% of the product of (i) the number of new
ordinary shares which are subsequently clawed back following
completion of the open offer and (ii) the issue price (the
'Commission'). The Commission is consistent with those paid in
respect of other participants in the placing. The Commission of
$0.2 million due to Double A was outstanding as at 31 December 2016
and settled subsequently during 2017.
Office sublease
During the year ended 31 December 2017, the Group recognised
$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 (2016: $0.1
million rental income from AA Capital Analysts Limited, a company
whose majority controlling shareholder is Double A Limited).
Contracted services
During the year ended 31 December 2017, the Group obtained
contracting services from Influit UK Production Solutions for a
value of US$0.04m. 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 2017.
2017 2016
$'000 $'000
Short-term employee benefits 5,057 5,002
Share-based payments 1,305 3,770
Post-employment pension benefits 55 33
6,417 8,805
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 2017 and 2016, 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 2017 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 (primarily fixed price swaps over a total of 5.5
million barrels as at 31 December 2017), with all other variables
held constant. As the derivatives on hand at 31 December 2017 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 2017 (68,350) 48,320 - -
31 December 2016 (58,000) 60,000 - -
26. Risk management and financial instruments (continued)
Foreign currency risk
The Group is exposed to foreign current 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 2% (2016: 1%) of the Group's sales and 83% (2016:
81%) of costs (including capital expenditure) are denominated in
currencies other than the functional currency.
At 31 December 2016, the Group had a forward foreign currency
contract in place for NOK37.1 with a strike price of NOK8.61/GBP1
which matured in Q1 2017 as a result of the exchange structure
entered into in June 2016 (see note 20). As at 31 December 2017,
all exchange structures have matured (see note 20).
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
Year ended Year ended
31 December 2017 31 December 2016
Change in US Dollar rate $'000 $'000
+10% (43,100) (48,250)
-10% 43,100 48,250
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
operators and at 31 December 2017 there were $23.6 million of trade
receivables past due (2016: $5.6 million), $1.7 million of joint
venture receivables past due (2016: $8.6 million) and $nil (2016:
$nil) of other receivables past due but not impaired. Subsequent to
year end, $1.5 million of these outstanding balances have been
collected (2016: $10.9 million). Receivable balances are monitored
on an ongoing basis with appropriate follow-up action taken where
necessary.
2017 2016
Ageing of past due but not impaired receivables $'000 $'000
Less than 30 days 1,726 6,101
30-60 days - -
60-90 days 253 -
90-120 days - 656
120+ days 23,301 7,473
25,280 14,230
At 31 December 2017, the Group had four customers accounting for
84% of outstanding trade receivables
(2016: three customers, 90%) and three joint venture partners
accounting for 97% of joint venture receivables
(2016: five joint venture partners, 90%).
26. Risk management and financial instruments (continued)
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.
On 21 November 2016, the Company concluded a comprehensive
financial restructuring comprising: amendments to the credit
facility, high yield bond and retail bond; renewal of surety bond
facilities; and a placing and open offer (the 'Restructuring'). The
terms of the Restructuring are set out further in notes 17 and 19.
The Restructuring was designed to provide the Group with a stable
and sustainable capital structure, reduced cash debt service
obligations and greater liquidity. In particular, the Restructuring
is expected to enable the Group to complete the Kraken and
Scolty/Crathes developments. At 31 December 2017, $97.8 million
(2016: $156.3 million) was available for draw down 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.
Year ended 31 December 2017 On demand Up to 1 year 1 to 2 years 2 to 5 years Over 5 years Total
$'000 $'000 $'000 $'000 $'000 $'000
Loans and borrowings - 424,886 347,603 667,975 - 1,440,464
Bonds(1) - 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
Year ended 31 December 2016 On demand Up to 1 year 1 to 2 years 2 to 5 years Over 5 years Total
$'000 $'000 $'000 $'000 $'000 $'000
Loans and borrowings - 122,590 260,017 960,880 - 1,343,487
Bonds(1) - 56,069 60,812 182,435 901,377 1,200,693
Trade and other payables 258,828 136,564 45,378 - - 440,770
Other financial liabilities - - 7,641 - - 7,641
258,828 315,223 373,848 1,143,315 901,377 2,992,591
(1) 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 the coupon payment date (see
note 19).
26. Risk management and financial instruments (continued)
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.
Year ended 31 December 2017 On demand Less than 3 months 3 to 12 months 1 to 2 years Over
2 years Total
$'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)
Year ended 31 December 2016 On demand Less than 3 months 3 to 12 months 1 to 2 years Over
2 years Total
$'000 $'000 $'000 $'000 $'000 $'000
Commodity derivative contracts 146 (10,626) (27,419) - - (37,899)
Foreign exchange forward contracts - (4,741) - - - (4,741)
Foreign exchange forward contracts - 4,308 - - - 4,308
Chooser contract - (3,711) (3,711) - - (7,422)
Interest rate swaps - 1 3 2 - 6
146 (14,769) (31,127) 2 - (45,748)
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, 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,
there is approval from the Board to hedge up to 75% of annual
production in year 1, 60% in year 2 and 50% in year 3. This is
designed to reduce the risk of adverse movements in exchange rates
and 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.
26. Risk management and financial instruments (continued)
The Group monitors capital using the gearing ratio and return on
shareholders' equity as follows:
2017 2016
$'000 $'000
Loans, borrowings and bond (i) (A) 2,164,550 1,971,106
Cash and short-term deposits (173,128) (174,634)
Net debt/(cash) (B) 1,991,422 1,796,472
Equity attributable to EnQuest PLC shareholders (C) 760,866 818,852
Profit/(loss) for the year attributable to EnQuest PLC shareholders (D) (60,830) 185,212
Profit/(loss) for the year attributable to EnQuest PLC shareholders excluding exceptionals
(E) (33,554) 121,510
Gross gearing ratio (A/C) 2.8 2.4
Net gearing ratio (B/C) 2.6 2.2
Shareholders' return on investment (D/C) (8%) 23%
Shareholders' return on investment excluding exceptionals (E/C) (4%) 15%
(i) Principal amounts drawn, excludes netting off of fees (see
note 19)
27. Post balance sheet events
On 31 January 2018, following the acquisition of the initial 25%
interest in the Magnus oil field (see note 29), EnQuest agreed with
BP to undertake the management of the physical decommissioning
activities for Thistle and Deveron. EnQuest will receive $30
million in cash in exchange for undertaking the management of the
physical decommissioning and making payments by reference to 3.7%
of the gross decommissioning costs of the Thistle and Deveron
fields when spend commences, subject to a cap of GBP57 million.
EnQuest will also have an option, exercisable over a 12 month
period, to receive a further $20 million in cash in exchange for
making additional payments by reference to 2.4% of the gross
decommissioning costs of these fields, subject to a cap of GBP42
million.
28. Subsidiaries
At 31 December 2017, EnQuest PLC had investments in the
following subsidiaries:
Name of company Principal activity Country of incorporation Proportion of nominal value
of issued shares controlled
by the Group
Intermediate holding company
and provision of Group
manpower and
contracting/procurement
EnQuest Britain Limited services England 100%
Exploration, extraction and
EnQuest Heather Limited(i) production of hydrocarbons England 100%
Extraction and production of
EnQuest Thistle Limited(i) hydrocarbons England 100%
Stratic UK (Holdings)
Limited(i) Intermediate holding company England 100%
Grove Energy Limited(1) Intermediate holding company Canada 100%
Exploration, extraction and
EnQuest ENS Limited(i) production of hydrocarbons England 100%
Exploration, extraction and
EnQuest UKCS Limited(i) production of hydrocarbons England 100%
Exploration, extraction and
EnQuest Norge AS(i)2 production of hydrocarbons Norway 100%
EnQuest Heather Leasing
Limited(i) Leasing England 100%
Exploration, extraction and
EQ Petroleum Sabah Limited(i) production of hydrocarbons England 100%
EnQuest Dons Leasing
Limited(i) Dormant England 100%
Exploration, extraction and
EnQuest Energy Limited(i) production of hydrocarbons England 100%
Exploration, extraction and
EnQuest Production Limited(i) production of hydrocarbons England 100%
EnQuest Global Limited Intermediate holding company England 100%
Exploration, extraction and
EnQuest NWO Limited(i) production of hydrocarbons England 100%
EQ Petroleum Production Exploration, extraction and
Malaysia Limited(i) production of hydrocarbons England 100%
Construction, ownership and
NSIP (GKA) Limited(3) operation of an oil pipeline Scotland 100%
Provision of Group manpower
and contracting/procurement
EnQuest Global Services services for the
Limited(i)4 International business Jersey 100%
EnQuest Marketing and Trading Marketing and trading of
Limited crude oil England 100%
NorthWestOctober Limited(i) Dormant England 100%
EnQuest UK Limited(i) Dormant England 100%
EnQuest Petroleum Developments Exploration, extraction and
Malaysia SDN. BHD(i)5 production of hydrocarbons Malaysia 100%
EnQuest NNS Holdings Limited Intermediate holding company England 100%
Exploration, extraction and
EnQuest NNS Limited production 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
29. Business combinations
Acquisition of Magnus and other interests
On 1 December 2017, EnQuest completed the acquisition from BP
plc of an initial 25% interest in the Magnus oil field ('Magnus')
as well as a 3.0% interest in the Sullom Voe Oil terminal and
supply facility ('SVT'), 9.0% of Northern Leg Gas Pipeline
('NLGP'), and 3.8% of Ninian Pipeline System ('NPS') (collectively
the 'Transaction assets').
The transaction is in keeping with EnQuest's strategy of
maximising value from late life assets with significant remaining
resource potential. The required regulatory, government authority,
counterparty and partner consents have been obtained for the
transaction.
The transaction is an acquisition of an interest in a joint
operation under IFRS 11 and, as the activity constitutes a business
as defined in IFRS 3 Business Combination, the acquisition has been
accounted for as a business combination. 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
Transaction assets for the one month period from the acquisition
date.
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(iii) 22,300
Financial asset(i) 16,120
Inventory 14,884
177,846
Liabilities
Trade and other payables (see note 23) (8,459)
Financial liabilities(ii) (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(iii) (22,300)
Thistle decommissioning option(i) (16,120)
25% acquisition value (10,314)
Total excess of fair value over cost arising on acquisition(iv) (48,734)
Purchase consideration through vendor loan 66,623
(i) The financial asset relates 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 relates 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.
(iii) The financial asset relates 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.
(iv) 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 asset may be
subsequently adjusted, with a corresponding adjustment to goodwill
prior to 1 December 2018 (one year after the transaction).
29. Business combinations (continued)
In addition to the above identifiable assets and liabilities,
under the terms of the agreement, the Group has an option
to acquire the remaining 75% of the Magnus oil field and BP's
interest in the associated infrastructure for a value of $300
million. This option lapses in January 2019. In line with IAS 39, a
discounted value of $22.3 million has been attributed to this
option and recorded within other financial assets (see note
20).
EnQuest also has 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 (see note 20). In January 2018, the
Group exercised part of the option (see note 27).
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.
At the date of acquisition, the fair value of the net assets was
$115.4 million. At 31 December 2017, none of the trade receivables
have been impaired.
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 interim period and working capital adjustments since
the economic date of 1 January 2017, resulting contingent
consideration of $66.6 million. The present value of the contingent
consideration was calculated from the future expected cash flows,
at a discount rate of 10.0% and assumed repayment of around 3
years. This is recognised within contingent consideration within
provisions
(see note 22).
From the date of acquisition, the Transaction assets have
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 the year, 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.
All transaction costs were paid by BP as part of the deal
agreement.
Information on prior year acquisitions
The net assets acquired during the year ended 31 December 2016
were recognised as follows:
15.15% interest 10.5% interest
in West Don in Kraken Total
$'000 $'000 $'000
Property, plant and equipment (see note 10) 7,096 33,599 40,695
Prepayments and accrued income - 10,500 10,500
Under-lift position 3,271 - 3,271
Deferred tax asset (see note 7) 268 - 268
Accrued expenses (538) (31,581) (32,119)
Provision for decommissioning (see note 22) (7,633) (7,520) (15,153)
Net identifiable assets 2,464 4,998 7,462
In February 2016, the Group acquired an additional 10.5%
interest in the Kraken development asset from First Oil for nominal
consideration, resulting in a revised working interest of 70.5% in
this joint arrangement. The amounts recognised in respect of the
identifiable assets acquired and liabilities assumed are set out in
the table above.
In August 2016, the Group acquired an additional 15.15% interest
in the West Don producing field from First Oil, resulting in a
revised working interest of 78.6% in this joint arrangement. The
amounts recognised in respect of the identifiable assets acquired
and liabilities assumed are set out in the table above. The
consideration of $2.5 million, which was satisfied through a
reduction of receivable balances, equalled the fair value of
identifiable assets acquired and liabilities assumed and therefore
no goodwill arose on the acquisition.
30. Cash flow information
Cash generated from operations
Year ended Year ended 31 December
31 December
2017 2016
Notes $'000 $'000
Profit/(loss) before tax (243,773) 217,244
Depreciation 5(c) 4,500 3,930
Depletion 5(b) 224,698 241,879
Exploration costs impaired/(reversed) and written off 5(d) (193) 776
Net impairment (reversal)/charge to oil and gas assets 4 171,971 (147,871)
Write down of inventory 4 (2,682) -
Write down of asset 4 2,808 -
Loss on disposal of intangible oil and gas assets 4 - 16,178
Excess of fair value over consideration 4 (48,734) -
Gain on disposal of loan notes 5(d) (1,263) -
Impairment (reversal)/charge to investments 4 19 (48)
Share-based payment charge 5(f) 2,849 8,452
Shares purchased on behalf of Employee Benefit Trust 17 (1,763) -
Change in deferred consideration 5(d) - (4,056)
Change in surplus lease provision 22 (200) (23,025)
Change in decommissioning provision 5(d) - (1,627)
Change in other provisions 22 10,161 -
Hedge accounting deferral 20 - (2,456)
Amortisation of option premiums 20 (10,445) (31,210)
Unrealised (gain)/loss on financial instruments 5(a)(b) (2,010) 53,088
Unrealised exchange loss/(gain) 5(e) 23,910 (51,867)
Net finance (income)/expense 6 147,079 127,835
Operating profit before working capital changes 276,932 407,222
Decrease/(increase) in trade and other receivables (13,611) 26,579
(Increase)/decrease in inventories 2,039 (7,356)
(Decrease)/increase in trade and other payables 61,674 (18,198)
Cash generated from operations 327,034 408,247
Changes in liabilities arising from financing activities
Year ended 31 December 2017(1) Loans and borrowings Bonds Finance leases Total
(see note 19) (see note 19) (see note 24)
$'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
(1,219,675) (944,875) (797,933) (2,962,483)
(i) First year adoption of IAS 7 amendment, therefore comparative information is not required.
This information is provided by RNS
The company news service from the London Stock Exchange
END
FR GGUWAWUPRGBB
(END) Dow Jones Newswires
March 20, 2018 03:00 ET (07:00 GMT)
Enquest (LSE:ENQ)
Historical Stock Chart
From Apr 2024 to May 2024
Enquest (LSE:ENQ)
Historical Stock Chart
From May 2023 to May 2024