TIDMSQZ
RNS Number : 5131V
Serica Energy PLC
15 April 2021
Serica Energy plc
("Serica" or the "Company")
Results for the year ended 31 December 2020
London, 15 April 2021 - Serica Energy plc (AIM: SQZ), a British
independent upstream oil and gas company with operations in the UK
North Sea today announces its audited financial results for the
year ended 31 December 2020. The results are included below and
copies are available at www.serica-energy.com and www.sedar.com
.
Commenting on the results, Mitch Flegg, Serica's CEO stated:
" We are reporting solid results after a challenging year and a
severe industry downturn. Despite the many obstacles 2020
presented, Serica has continued to strengthen its financial and
operational foundations and also to deliver returns to its
shareholders. COVID-19 caused disruption to global markets and
threatened operations during 2020 but Serica responded rapidly to
protect its personnel and ensure continuing supplies of oil and gas
into the British market. The impact of a substantial fall in
commodity prices during the year plus a 45-day shut-in of BKR
production in 1H to repair a damaged caisson on the Bruce platform
was mitigated by the flexible structure of the BKR net cash flow
sharing arrangements and the Group's gas price hedging programme.
This financial and operational resilience enables the
recommendation of an increased dividend of 3.5 pence per share.
The R3 workover is now nearing completion despite a series of
technical challenges and periodic severe weather throughout the
campaign and the Columbus development well was spudded in mid-March
2021. These projects are expected to boost production during 2H and
Q4 respectively and we continue to actively pursue M&A
opportunities that can broaden our asset base and add further value
for our stakeholders. I look forward to updating shareholders on
our progress during the rest of the year."
2020 Summary
-- Group profit before tax of GBP12.5 million (2019: GBP108.8
million) impacted by low commodity prices and Bruce caisson
shut-in.
-- Average net production of 23,800 boe per day (2019: 30,000
boe per day) - reduction reflects 1H caisson repairs and other
field maintenance work.
-- Cash flow from operations of GBP44.1 million (2019: GBP137.1 million).
-- Capital expenditure of GBP26.6 million (2019: GBP5.3 million) .
-- Maiden 3 pence per share dividend paid in July totalling GBP8.0 million (2019: nil) .
-- Closing cash and cash equivalents of GBP89.3 million (2019:
GBP101.8 million) after capital expenditure and dividend payment
with no debt.
-- Resource base reinforced as Group production of approx. 8.1
million boe for the year largely offset by a 12% increase oil and
gas reserves, leaving year end reserves of 61.0 million boe (2019:
62.3 million boe).
Financial
-- Average 2020 sales price of approx. US$20 per boe (2019:
US$30 per boe) and average operating cost of US$14.12 per boe
(2019: US$12.60 per boe).
-- Gross loss of GBP2.9 million (2019: profit of GBP85.8
million) and operating loss of GBP18.7 million (2019: profit of
GBP87.7 million) included GBP38.5 million (2019: GBP52.6 million)
of non-cash depletion charges.
-- Realised gains of GBP12.3 million (2019: GBP3.9 million) on
2020 gas price hedging offset by unrealised losses of GBP16.6
million (2019: unrealised gains of GBP6.7 million) on 2021/2022
hedging:
o based on market futures curve at balance sheet date and
reflects rapidly strengthening forward gas prices at the year
end.
-- Cash flow from operations of GBP44.1 million (2019: GBP137.1 million) after payment of:
o GBP21.8 million of BKR cash flow sharing and other liabilities
(2019: GBP57.3 million)
o GBP26.6 million of capital expenditure (2019: GBP5.3 million)
and
o GBP8.0 million of dividends (2019: nil).
-- Profit after tax was GBP7.8 million (2019: GBP64.0 million)
after a non-cash deferred tax provision of GBP4.8 million (2019:
GBP44.8 million).
Operational
-- Updated independent audit of field reserves reported Serica's
share of estimated remaining 2P reserves as 61.0 million boe as at
1 January 2021:
o approximate 12% increase over the 62.3 million boe reported as
at 1 January 2020, after adjustment for 2020 production
o largely the result of improved production efficiencies and
lower operating costs achieved on the BKR assets since acquisition
by Serica
o projected BKR field life now extended by a further two
years.
-- Bruce, Keith and Rhum fields produced 21,500 boe per day net
to Serica for 2020 compared to 27,300 boe per day for 2019 -
reduction largely due to the 45-day shutdown in 1H to effect
caisson repairs on the Bruce platform and to planned
maintenance.
-- Erskine field continued its strong performance averaging over
2,300 boe per day net to Serica during 2020 (2019: 2,700 boe per
day) after five-week planned maintenance shut-in.
-- Serica continued its cost reduction programme on BKR,
lowering underlying operating costs by a further 10% in 2020.
However, overall Group costs per barrel increased to US$14.12 per
boe from US$12.30 in 2019 as fixed cost elements were spread over
lower production volumes.
-- Successful completion of the Rhum R3 workover is expected to
accelerate field production, with the potential to bring additional
reserves into the commercial lifespan of the field and to provide
operational back-up to the existing two wells. Total costs now
projected at GBP21 million, after adjustment for net cash flow
sharing, of which GBP11.5 million to be spent in 2021 - represents
total cost overrun of GBP9.7 million net to Serica.
-- The Maersk Resilient heavy-duty jack-up rig spudded the
Columbus development well on 17 March 2021 and drilling is
progressing to plan. The Arran-Shearwater export pipeline has been
laid and first gas from Columbus is expected for Q4 2021.
ESG
-- Active management on flaring resulted in a 45% reduction in flare volumes compared to 2019.
-- CO(2) emissions on Bruce of approx. 214,500 tonnes were over
10% lower compared to 2019 (241,500 tonnes).
-- ESG performance metrics added to annual incentive scheme for
all Group employees covering flaring, carbon intensity, diversity
and waste.
-- As a demonstration of its commitment to reporting
transparency, Serica intends to publish its second Environmental,
Social and Governance ("ESG") Report in conjunction with the
publication of the full Annual Report and this will be available on
Serica's website www.serica-energy.com .
Outlook
-- The resurgence in commodity prices which commenced in Q4 2020
has continued into 2021 with average market prices for Q1 of
approximately 50 pence per therm for NBP gas and US$61 per barrel
for Brent oil, significantly higher than the respective average
prices of 25 pence per therm and US$42 per barrel seen in 2020.
-- Gas in particular, currently some 80% of Serica's production
mix, has seen prices since the year end reach sustained levels not
seen since 2018. Apart from the significant benefit this brings to
realised revenues, Serica also continues to build its price hedge
position to cushion against commodity price falls such as seen in
2020 whilst maintaining high exposure to higher prices such as seen
in the period following the year end.
-- Significant increases in Serica's retained share of
production volumes in prospect with R3 expected to be contributing
in Q3, Columbus from Q4 and Serica's retained share of net cash
flow from the BKR assets increasing from 60% to 100% effective 1
January 2022.
-- As a core part of pursuing our objectives we will continue to
increase our focus on ESG issues, in particular in efforts to
reduce the carbon intensity of our production.
-- Having initiated a dividend policy last April it is the
Board's intention to maintain dividend payments for future years
and to grow the level when financial performance supports this.
-- Subject to shareholder approval at the AGM, a dividend of 3.5
pence per share will be payable on 23 July 2021 to shareholders
registered on 25 June 2021 with an ex-dividend date of 24 June
2021.
-- With strong operating, ESG and financial credentials Serica
is well-placed to grow through developing the potential of its
existing assets as well as building on new opportunities to
diversify risk, provide new growth prospects and achieve economies
of scale.
A conference call for sell-side analysts will be held later
today at 10.00 a.m. (UK time), today. If you would like to
participate, please email serica@vigocomms.com . A copy of the
accompanying presentation can be found on our website:
www.serica-energy.com .
Regulatory
This announcement is inside information for the purposes of
Article 7 of Regulation 596/2014.
The technical information contained in the announcement has been
reviewed and approved by Fergus Jenkins, VP Technical at Serica
Energy plc. Mr. Jenkins (MEng in Petroleum Engineering from
Heriot-Watt University, Edinburgh) is a Chartered Engineer with
over 25 years of experience in oil & gas exploration,
development and production and is a member of the Institute of
Materials, Minerals and Mining (IOM3) and the Society of Petroleum
Engineers (SPE).
Enquiries:
Serica Energy plc +44 (0)20 7390 0230
Tony Craven Walker, Executive Chairman
Mitch Flegg, CEO
Peel Hunt (Nomad & Joint Broker) +44 (0)20 7418 8900
Richard Crichton / David McKeown / Alexander
Allen
Jefferies (Joint Broker) +44 (0)20 7029 8000
Tony White / Will Soutar
VIGO Communications +44 (0)20 7390 0230
Patrick d'Ancona / Chris McMahon / Simon serica@vigocomms.com
Woods
CHAIRMAN'S STATEMENT
Dear Shareholder
The past twelve months have seen a perfect storm of events
caused by the worldwide pandemic which erupted at the start of
2020. The resultant lockdown, requiring companies to restrict
travel, abandon office working, implement social distancing and
introduce new digital technologies to facilitate communication, has
put considerable strain on established business models and work
practices.
In the oil and gas world, we also had to contend with one of the
biggest commodity price collapses in recent years, with US oil
prices moving into negative territory for a short time early in
2020 and European gas prices dropping to levels which have not been
seen for decades. In short, 2020 has been an extraordinarily
difficult year to navigate for all industries but particularly for
the oil and gas industry.
I am pleased to report that Serica has not only been able to
weather these storms, but we have also been able to move forward
with all of the projects we set for the year, in particular the
Columbus gas field development and the R3 intervention projects. A
successful conclusion of these projects should see a significant
increase in production levels in the second half of this year to
add to the benefits we are already seeing from strengthening
commodity prices. We are also entering the last year of the net
cash flow sharing arrangements with BP, Total and BHP which formed
the basis of our acquisition of the BKR assets in 2018. As a
result, we will be retaining 100% of cash flows from these assets
from the beginning of next year, up from 60% this year and further
strengthening our cash generation.
We have been able to achieve our 2020 operational targets to
build for the future with minimal impact on our financial
resources. Cash balances remained strong at year end, standing at
just under GBP90 million compared with GBP101 million at the start
of the year despite the low oil and gas prices and after making
significant capital investments in the Columbus and R3 projects. In
addition, we are reporting a profit for the year of just under GBP8
million after providing for deferred tax. Albeit significantly less
than the GBP64 million reported for the prior year this
demonstrates remarkable resilience during a severe industry
downturn.
Prices for both oil and gas have strengthened since the start of
this year, particularly gas prices which affect some 80% of our
production and which have risen some four-fold from their 2020 low,
supporting ongoing spend on our Columbus and Rhum R3 projects. This
strong financial position, with no debt and considerable unutilised
debt capacity allows us to prepare for drilling the North Eigg gas
prospect next year as well as completing our existing projects this
year, continuing investment in the BKR assets and pursuing further
growth opportunities.
Last year we paid our maiden dividend, amounting to 3p per
share, and did so at a time of considerable upheaval in the oil and
gas sector. This year, in view of the Company's continuing strong
cash position, we are recommending an increased dividend of 3.5p
per share reflecting the Board's confidence in the future prospects
for the Company. Subject to approval at the Annual General Meeting
in June, this will be paid as a single final dividend to all
shareholders on the register at 25 June 2021.
The Company puts considerable emphasis on setting the highest
standards that it can to meet environmental, social and good
governance expectations of our shareholders, other stakeholders and
of society at large. These include diversity where this can be
achieved and equal opportunity. As a young company we are able to
implement good modern practices and involve all of our employees in
seeking to achieve and improve on our targets and we endeavour to
bring new thinking and business innovation to these efforts as a
focal part of our leadership team. Mitch Flegg, in his CEO's
report, will be highlighting some of the steps we are taking and
significant improvements we have been able to make to the carbon
intensity of our offshore operations since taking over operations
two years ago. Further information is provided in our Annual Report
and we will also be publishing a full ESG performance report on our
web-site as part of our annual reporting cycle.
Many commentators have questioned the role of oil and gas as the
world enters a new phase and new technologies are developed to
replace the traditional sources of energy. Targets have been set to
achieve Net Zero carbon by 2050 with various stage targets in the
intervening period. There is no question that the oil and gas
industry is fully committed to meeting those targets and has the
technological expertise and knowledge to achieve it but it is a
process which will take time to implement. Oil and gas,
particularly gas as a relatively clean fuel, will still be required
to underpin this transition and to provide economies with the fuel
and materials they need as part of the energy mix to maintain
supply and living standards whilst the shift to new sources of
energy is implemented and new technologies and the necessary
infrastructure are developed.
Serica has a role to play in this transition. As an established
North Sea production operator we have the skills and finances to
work in partnership with major companies as they seek to optimise
their reserves, reduce operating costs, improve profitability and
move to lower carbon technologies. With our performance as Bruce
operator we have strong ESG credentials and we will be looking to
build on this as a fundamental part of any new investment as well
as continuing to focus on our main tenets: adding shareholder
value, protecting shareholder value and returning shareholder
value. Serica has been able to do all three in 2020 and is
well-placed to grow on the back of its existing assets as well as
building on new opportunities. We are looking forward to 2021.
In summary, I am very pleased to report that we have been able
to manage the challenges of 2020 and are entering 2021 financially
and operationally stronger than ever. This is due in no small part
to the huge commitment of Serica's teams in London, Aberdeen and on
the Bruce offshore complex. I would like to thank all of them on
behalf of the Board and our shareholders for their outstanding
performance in such challenging times.
Tony Craven Walker
Chairman
14 April 2021
STRATEGIC REPORT
The following Strategic Report of the operations and financial
results of Serica Energy plc ("Serica") and its subsidiaries (the
"Group") should be read in conjunction with Serica's consolidated
financial statements for the year ended 31 December 2020.
References to the "Company" include Serica and its subsidiaries
where relevant. All figures are reported in GB Sterling ("GBP")
unless otherwise stated. With effect from 1 January 2019, the
Group's results have been reported in GBP.
The Company is subject to the regulatory requirements of AIM, a
market of the London Stock Exchange in the United Kingdom. Although
the Company delisted from the Toronto Stock Exchange ("TSX") in
March 2015, the Company is a "designated foreign issuer" as that
term is defined under Canadian National Instrument 71-102 -
Continuous Disclosure and Other Exemptions Relating to Foreign
Issuers.
Serica is an independent oil and gas company with production,
development and exploration interests in the UK Continental
Shelf.
CEO's REVIEW
It is impossible to review any aspect of 2020 without first
considering the impact of the COVID-19 pandemic. Serica was quick
to implement measures to reduce the likelihood of the virus
impacting our operations. We adopted new travel procedures which
included reducing the number of personnel on helicopters to and
from our offshore installations. We also significantly limited
manning levels on the Bruce platform in order to reduce the risk of
an outbreak, allow social distancing offshore and provide isolation
areas for suspected cases. These reduced manning levels meant that
the working conditions were more difficult for those staff
remaining on the platform and also meant that we have had to
prioritize essential (especially safety and environmentally
critical) activities throughout the year. I am delighted to report
that due to the incredible skill, hard work and professionalism of
our team we have managed to avoid any cases of the virus on our
installations and so we have incurred no COVID-19 related
interruptions to production. Our safety performance was outstanding
with zero recordable injuries sustained during the year. Serica has
not furloughed any staff or taken advantage of any of the
government assistance programmes.
Serica has demonstrated that it has all of the skills to thrive
as a modern, dynamic energy company operating as part of the Net
Zero transition. Over 80% of our production is natural gas which is
a key component in this transition. Our second annual
Environmental, Social and Governance ("ESG") Report will be
published along with the annual report. In the past year we have
reduced Bruce carbon emissions by over 11% and we have achieved a
62% reduction in flaring in only two years as operator of the Bruce
platform.
Despite the severe social impact of COVID-19 and the economic
impact on commodity pricing which has affected all companies in
2020, I am pleased to report that Serica Energy's strong balance
sheet and robust hedging position combined with the structure of
the transactions under which we acquired our interests in the
Bruce, Keith and Rhum ("BKR") fields has resulted in the Company
reporting a full-year profit of GBP7.8 million (2019: GBP64.0
million) after provision for deferred tax.
Production levels in 2020 were impacted by a 45-day suspension
of BKR production to resolve an issue with an unused caisson on the
Bruce platform. As a result, Serica's net production for the year
averaged 23,800 boe/d (compared to 30,000 boe/d in 2019). It should
be noted that the 45-day shut-down occurred in the early part of
the year when gas prices were significantly lower than late in the
year. The production from the 45-day period is not lost but
deferred and the shut-down is not expected to have any impact on
ultimate recovery from BKR.
Gas prices for the year averaged less than 25 pence per therm
before hedging gains but Serica's gas price hedging programme
effectively fixed prices for approximately one-third of our
retained 2020 gas sales at approximately 39 pence per therm. This
hedging programme delivered cash income of GBP12.3 million during
2020. We continue to extend our hedging position and for 2021 and
2022 Serica has swaps in place covering up to 25% of retained gas
sales after adjustment for 2021 net cash flow sharing. These swaps
provide some protection against severe downside gas prices whilst
retaining the potential upside benefit from the majority of
production.
We continue to focus on minimising our cost base and in 2020 we
have realised further reductions in our absolute operating costs.
However, when expressed as costs per barrel there is an increase to
US$14.12/boe (2019: US$12.60/boe). The increase in operating costs
per barrel reflected lower production volumes caused by the 45-day
BKR production suspension in the first half and does not indicate
an increase in the underlying trend.
Serica has commissioned a new Competent Person's Report ("CPR")
effective 1 January 2021 and this has identified an upgrade to net
2P Reserves estimates particularly due to the successful efforts to
extend the prognosed Cessation of Production ("COP") on Bruce
through which all Bruce, Keith and Rhum production is processed. I
am delighted to report that the latest CPR estimates that the Bruce
COP (2P case) has been extended by a further two years and is now
predicted to occur in 2030. In the last two years we have extended
COP by a total of four years; this is a clear indication that our
BKR life extension strategy is being successful. Our net 2P
reserves stood at 62.3 million boe at 1 January 2020 and our 2020
net production was more than 8 million boe but due to these
upgrades, after 2020 production, our net 2P reserves at 1 January
2021 stand at 61.0 million boe.
During 2020, Serica decided to withdraw from Namibia where we
had originally been awarded a licence in 2011. Following a full
review, we elected not to seek a further renewal period or to
continue with a new licence application. The pace of exploration
activity in Namibia had been slower than we hoped, and the
development of any discovery would likely have been high cost, time
consuming and inconsistent with our sustainability objectives.
Therefore, we have decided to concentrate on the numerous lower
risk, nearer term opportunities in our North Sea portfolio. In
particular we have a programme of three investment projects that
each have the ability to generate significant value for the
Company:
1. The Rhum field currently produces from two wells (R1 and R2)
which are subsea tie-backs to the Bruce platform. A third well (R3)
was drilled when the field was originally developed but was not put
into production due to mechanical issues with equipment in the
well. In late 2020, operations commenced to remedy these problems.
The completion equipment installed in the well by the previous
operator in 2005 has been fully recovered. We are now in the
process of regaining access to the reservoir prior to running a new
completion, reperforating and flowing the well. R3 is expected to
accelerate field production, with the potential to bring additional
reserves into the commercial lifespan of the field, and to provide
operational back-up to the existing two wells.
2. T he Columbus development well in the UK Central North Sea
was spudded in March 2021. The well is being drilled with the
Maersk Resilient jack up rig to a total depth of 17,600ft and will
include a 5,600ft horizontal section. The Columbus development area
is 35km north east of the Shearwater production facilities and will
be drained by a single producing well tied into the existing
Arran-Shearwater pipeline. The recent Competent Person's Report
estimates the Columbus gross undeveloped 2P reserves to be in
excess of 14 million barrels of oil equivalent ("boe"). Serica is
operator and has a 50% interest in the project. Production is
expected to commence in early Q4 2021, with average production
forecast to be around 3,500 boe/d net to Serica, of which over 70%
is gas.
3. Planning is ongoing for the drilling of the HPHT North Eigg
exploration well which we expect to spud in 2022. This prospect is
located in the area adjacent to the Serica operated Rhum field and
in the event of a discovery, Serica will investigate options for
subsea tie-backs to the Bruce facilities and topsides modifications
to ensure a low cost, low emission design to enable early
development, maximise recovery and optimise production. Serica has
carried out an in-house evaluation of the prospect and estimates
the unrisked prospective (recoverable) resources, based on seismic
mapping and Rhum analogue data, to be around 70 million boe.
2020 was a year of solid performance and improvement which
demonstrated the resilience and profitability of the Company in the
face of unprecedented business challenges. 2021 will be a year of
continued investment in the growth opportunities which exist in our
portfolio. The end of 2021 will represent another huge milestone
for the Company with the expiry of the cash flow sharing
arrangement under which Serica has been sharing the net cash flow
from BKR variously with BPEOC, Total E&P and BHP who originally
sold us their interests. In 2021 Serica retains 60% of the net cash
flow but this will increase to 100% on 1 January 2022 and stay at
that level thereafter providing a significant cash boost for the
Company.
Serica's strategy is to build on the strong financial and
operating capabilities which the Company has established in the UK
Sector of the North Sea and focus on our strong ESG credentials.
Whilst we see significant benefits and potential in our existing
portfolio we continue to look at new opportunities to expand our
operations to diversify risk, provide new growth prospects and
achieve economies of scale. We are confident that we have the
resources to deliver this strategy and the platform to create
additional value for shareholders.
Mitch Flegg
Chief Executive Officer
14 April 2021
REVIEW OF OPERATIONS
Production
Northern North Sea: Bruce Field - Blocks 9/8a, 9/9b and 9/9c,
Serica 98%
Serica operates the Bruce field and facilities consisting of
three bridge-linked platforms, wells, pipelines and subsea
infrastructure. The platforms contain living quarters for up to 168
people, reception, compression, power generation, processing and
export facilities and a drilling derrick that is currently
mothballed.
The Bruce field is produced through a combination of platform
wells and subsea wells tied back to the platform, with over 20
wells producing from multiple reservoirs and compartments. Bruce
production is predominantly gas which is rich in NGL's. Gas is
exported through the Frigg pipeline to the St Fergus terminal,
where it is separated into sales gas and NGL's. Oil is exported
through the Forties Pipeline System to Grangemouth.
The offshore team is supported onshore by the Serica technical
headquarters in Aberdeen which has a live video link to the
platform, streaming data and offering seamless communication with
the offshore crew. The onshore support team was already using video
links to provide support to the platform, so whilst working from
home during the COVID-19 pandemic, that technology has allowed
Serica to provide uninterrupted support to the offshore
operation.
In January 2020, during a Bruce platform inspection, the
condition of an unused seawater return caisson on the platform was
observed to have deteriorated. This caisson had been taken out of
service in 2009. Production through the Bruce facility was halted
while the problem was fully investigated.
A subsequent underwater inspection determined that the caisson
had parted below the water line. Both the upper and lower sections
of the caisson were intact and engineering work to ensure that the
caisson was properly secured commenced.
Work was successfully undertaken during the following weeks and
the caisson sections secured allowing production to restart on 5
March. During August, further work was undertaken to remove damaged
parts of the caisson back to shore.
To maintain operations during COVID-19 restrictions, increased
social distancing offshore, pre-mobilisation testing, social
distancing on transportation (including helicopters) and other
practical control measures were introduced. This reduced the number
of personnel working offshore by 30%. This had an initial impact on
the quantity of work that was able to be executed offshore, but
during the year Serica found ways to remove inefficiencies whilst
maintaining reduced numbers offshore. No pandemic production
interruptions occurred in 2020.
As part of the drive to be more efficient, during 2020 Serica
created a digital twin of the Bruce facility to enable more onshore
support (maintenance campaigns, visual inspection, modification
design and pipework fabrication) to be undertaken without personnel
having to visit the platform. As an example, one specific
inspection scope that had previously been forecast to cost
GBP150,000, was carried out with reductions of 75% in offshore days
and 40% in the total cost. This reduces cost, shortens response
time and minimises travel risk. Further enhancements to this
technology will be incorporated in future years.
Bruce field production in 2020 averaged in excess of 9,600 boe/d
of exported oil and gas net to Serica (2019: 13,100 boe/d) with the
reduction primarily as a result of the 45-day caisson shut-down.
Full year production reliability was 84.7% (96% excluding the
caisson interruption).
The latest independent report of reserves, compiled by RISC
Advisory, estimated 2P reserves of 15.7 million boe net to Serica
as of 1 January 2021 (2020: 22.2 million boe). The restricted
programme of well work during 2020 has led to declassification of
some 2P reserves pending reinstatement of this work in future
periods.
Northern North Sea: Keith Field - Block 9/8a, Serica 100%
Keith is an oil field produced by one subsea well tied back to
the Bruce facilities. Keith produces at a relatively low rate but
provides a low-cost contribution to oil export from Bruce. Keith
production was interrupted in January 2020 initially due to the
Bruce caisson issue and thereafter when required topsides
reinstatement work was unable to progress due to the reduced number
of people offshore in response to COVID-19. An intervention to
restore flow from Keith was successfully carried out in late March
2021 and further enhancement work is planned in Q2. Keith
production during 2020 was minimal but average production in 2019
was around 450 boe/d. No 2P reserves were included in the most
recent reserves report pending successful reinstatement of
production.
Northern North Sea: Rhum Field - Block 3/29a, Serica 50%
The Rhum field is a gas condensate field producing from two
subsea wells tied into the Bruce facilities through a 44km
pipeline. Rhum production is separated into gas and oil and
exported to St Fergus and Grangemouth along with Bruce and Keith
production. Rhum gas has a higher CO(2) content than Bruce gas and
so is blended with Bruce gas before leaving the offshore
facilities. The field continues to outperform our expectations at
the time of acquisition.
An intervention campaign is under way to workover the R3 well
and allow it to be brought onto production. The well was drilled at
the same time as the other two Rhum production wells, however
problems were encountered in 2005 by the previous operator during
well completion. The well was left with an ice-like hydrate plug
which prevented it flowing; attempts at that time to rectify this
additionally resulted in wireline debris being left in the
well.
Serica has successfully remedied both issues, recovering the
wireline 'fish' and dissociating the hydrate plug with heated
fluid. The well is now being prepared for production. The operation
has taken longer than anticipated due largely to the unexpectedly
poor condition of the equipment being recovered from the well and
also to periodically severe weather conditions. Production from the
well is now expected to commence in Q3. Total R3 capital costs are
now projected at GBP21.0 million net to Serica, after adjustment
for net cash flow sharing, of which GBP11.5 million will be spent
in 2021. This represents a total cost overrun of GBP9.7 million net
to Serica.
Average Rhum production in 2020 was over 11,900 boe/d net to
Serica (2019: 13,775 boe/d) the reduction being primarily as a
result of the Bruce caisson shut down. The latest independent
report of reserves, compiled by RISC Advisory, estimated 2P
reserves of 35.1 million boe net to Serica as at 1 January 2021
(2020: 28.7 million boe). The significant increase after adjustment
for 2020 production demonstrates Serica's progress in extending
projected field life and adding to recoverable reserves.
Central North Sea: Erskine Field - Blocks 23/26a (Area B) and
23/26b (Area B), Serica 18%
Serica holds a non-operated interest in Erskine, a gas and
condensate field located in the UK Central North Sea. Serica's
co-venturers are Ithaca Energy 50% (operator) and Harbour Energy
32%. Erskine fluids are processed and exported via the Lomond
platform, which is 100% owned and operated by Harbour Energy.
The Erskine field is produced through five production wells over
the Erskine normally unattended installation, transported to Lomond
via a multiphase pipeline and processed on the Lomond platform.
Then condensate is exported down the Forties Pipeline System via
the CATS riser platform at Everest and gas is exported via the CATS
pipeline to the CATS terminal at Teesside.
The flash and export coolers that are part of the Erskine
production module located on the Lomond platform were replaced in
April 2020. The 2020 Forties Pipeline System maintenance shut-in,
planned for June 2020, was deferred due to COVID-19 until May 2021.
However, the Lomond offtake facilities and the Erskine field were
shut in for 35 days during Q3 to carry out an extensive maintenance
programme.
The high frequency pigging program on the condensate export line
has continued and no indications of wax build-up have been seen.
Serica is supporting Ithaca and Harbour Energy with their
reliability improvement plans for the Erskine system and provides a
secondee to Lomond as part of the offshore management team.
Erskine production levels in 2020 averaged over 2,300 boe/d net
to Serica (2019: 2,700 boe/d) after the planned 35 day maintenance
shut-down in Q3. Full year production reliability in 2020 was
slightly above 82%, after exclusion of the maintenance shut-down,
which was comparable to 2019. The latest independent report of
reserves, compiled by RISC Advisory, estimated 2P reserves of 3.1
million boe net to Serica as of 1 January 2021 (2020: 4.1 million
boe).
Development
Central North Sea: Columbus Development - Blocks 23/16f and
23/21a (part), Serica 50% and Operator
Serica is development operator with partners Tailwind Energy
Limited (25%) and Waldorf Production Limited (25%). Columbus is
located in the Eastern Central Graben, UK Central North Sea and the
reservoir is located within the Forties Sandstone. Columbus has
been designated as a development within the Lomond Field Area; it
is however independent of Lomond, having separate development
consent, export route and licence terms.
The development comprises a single horizontal well with a subsea
completion connected to the Arran-Shearwater pipeline, through
which Columbus production will be exported along with Arran field
production. The Arran export pipeline was approved at a similar
time to Columbus and has now been constructed and laid on the
seabed, though it has not yet been tied into the Shearwater
platform. When production from Arran and Columbus reaches the
Shearwater facilities, it will be separated into gas which is
exported via the SEGAL line to St Fergus and liquids which are
exported via the Forties Pipeline System to Cruden Bay.
Columbus development timing is dependent on the export pipeline
being tied into the Shearwater platform and Arran exports
beginning. Columbus start-up is therefore expected during the
fourth quarter of 2021, once stabilised production conditions have
been achieved following the Arran field coming on-line.
The Maersk Resilient heavy-duty jack-up rig was contracted to
drill the 23/16f- C 1 development well; it arrived on site on 6
March and the well was spudded on 17 March 2021. The well is
planned to be drilled to a total depth of 17,600ft and will include
a 5,600ft horizontal section through the reservoir. Well operations
are expected to take around 70 days.
After drilling the well, an open-hole sand-screen completion
will be installed and a short clean-up flow and well test will be
performed to provide production data and prepare for flowing into
the export system. The well will then be suspended, before being
connected to the Arran-Shearwater pipeline later in the year. When
production commences, average gross production is forecast to be
around 7,000 boe/d, of which over 70% will be gas.
The latest independent report of reserves, compiled by RISC
Advisory, estimated 2P reserves of 7.1 mmboe net to Serica as at 1
January 2021 (2020: 6.7 million boe).
Exploration
UK
North Eigg and South Eigg - Blocks 3/24c and 3/29c, Serica 100%
and operator
In December 2019, Serica was awarded the P2501 Licence as part
of an out of Round application; this comprises Blocks 3/24c and
3/29c and contains the North Eigg and South Eigg prospects. The
official start date for the licence was 1 January 2020. The work
programme involves reprocessing seismic data and drilling an
exploration well within three years of the start of the licence.
The North Eigg prospect has been high-graded for drilling, being
clearly visible on 3D seismic data and sharing many similarities
with the nearby Rhum field, operated by Serica.
Work has started on planning to drill the exploration well,
which is expected to be high temperature and high pressure, during
the summer of 2022. In the event of a commercial discovery, Serica
would seek a fast-track route to develop the field, whilst
implementing options that would reduce emissions. This could
potentially be via a subsea tie-back to the Serica operated and 98%
owned Bruce facilities, which are to the south of the prospect.
This would bring the benefits of reducing the overall carbon
intensity of the Bruce facilities and extending the life of the
infrastructure.
Columbus West - Block 23/21b, Serica 50%, operator Summit
Exploration and Production
An extensive work programme was undertaken to mature the
prospectivity on the licence. Despite this work, stratigraphic
trapping and sealing mechanisms for the prospects remained elusive
and could not be satisfactorily confirmed.
The seismic data response was also suggestive of oil rather than
gas accumulations and the economics were determined not to be
favourable for an oil development, as there was no nearby tieback
host.
Taking current market outlook into consideration, and the
approaching commitment required to move to the next phase of the
licence which would have meant relinquishing 50% of the initial
licensed area and committing to drill a well, the risk-reward ratio
related to proceeding with West Columbus was not deemed sufficient
to proceed with exploration drilling.
Serica therefore supported the operator's recommendation to
relinquish the licence.
Skerryvore and Ruvaal- Blocks 30/12c (part), 30/13c (split),
30/17h, 30/18c and 30/19c (part), Serica 20%, operator Parkmead
The Skerryvore and Ruvaal prospects lie in the Central North
Sea, 60km south of the Erskine field. Over 500 km(2) of 3D seismic
data has been purchased over the licence areas. The seismic data is
being reprocessed and will then be interpreted to enable a drill or
drop decision to be made on the prospects. For a variety of
reasons, delivery of the reprocessed data was delayed by almost a
year during 2020, so interpretation work is yet to begin; the
operator therefore applied to OGA for an extension to the initial
three-year licence term and it has now been extended by 12 months
to September 2022. Interpretation will start as soon as data is
made available.
Licence Awards in the UK 32(nd) licensing round
In December 2020 Serica was formally awarded four new blocks in
the UK 32(nd) licensing round. Blocks 3/25b, 3/30, 4/26 and 9/5a
are in the vicinity of the Bruce hub and include several leads
which, if successful, could be tied back to Serica's existing
infrastructure. The work programme does not include any commitment
wells but is designed to mature these leads to drill-ready
status.
Namibia
Luderitz Basin: Blocks 2512A, 2513A, 2513B and 2612A (part),
Serica 85% and operator
Serica Energy Namibia B.V. (the Company's subsidiary holding
interests in Namibia) had an 85% interest in a Petroleum Agreement
in the Luderitz Basin, offshore Namibia. Following completion of
the initial licence period which had already been extended until
the end of 2019 whilst partners were sought to drill an exploration
well, Serica worked with the Ministry of Mines and Energy to
discuss the options of a further extension or new licence
application.
However, due to COVID-19 restrictions, exceptionally low oil and
gas prices, and market uncertainties, these discussions were
delayed. After further review Serica then elected not to progress
this and made the decision to withdraw from Namibia to focus on
activities in the UK North Sea which are nearer to existing
infrastructure, such as drilling North Eigg in 2022 and working on
the 32(nd) Round licences.
Group Proved plus Probable Reserves ("2P")
Total oil and
Oil Gas gas*
mmbbl bcf mmboe
2P Reserves at 31 December
2019 14.8 284.7 62.3
------ ------- --------------
2020 production (0.9) (40.8) (8.1)
Revisions (1.1) 45.3 6.8
2P Reserves at 31 December
2020 12.8 289.2 61.0
====== ======= ==============
*Total Group gas reserves at 31 December 2019 and 2020 have been
converted to barrels of oil equivalent using a factor of 6.0 bcf
per mmboe for reporting and comparison purposes. As the actual
calorific values of gas produced from individual fields varies,
reported production rates for each field and the total production
and revisions numbers reported above do not convert precisely.
Group Proved and Probable reserves as at 31 December 2019 were
based on the independent report prepared by Lloyd's Register ("LR")
in accordance with the reserve definitions guidelines defined in
SPE Petroleum Resources Management System 2018 ("PRMS 2018"). LR
closed their consultancy division in 2020 and Serica selected RISC
Advisory ("RISC") to prepare an independent report as at 31
December 2020 using the same guidelines.
Figures quoted relate to export fluids, so Fuel in Operation
(reported in previous reports) is not relevant as it has already
been subtracted.
Impacts of COVID-19 meant that some of the planned production
enhancement work on Bruce was not carried out in 2020; as this
relies on equipment upgrades which were also delayed, the work
cannot be carried out in the short-term and this was reflected in
the re-classification of some volumes from reserves to contingent
resources (hence they do not contribute to the figures in the table
above). Once this work has been reinstated in the firm work
programme, these volumes will again form part of the 2P
reserve.
Additional data from Rhum caused a revision to in-place gas
which resulted in a material increase to the recoverable reserve
estimate for the field. This offset much of the Bruce reserves
reduction and Serica's 2020 production.
Aggregate reserves revisions result from several factors,
including field production performance in the time between audits
and prevailing commodity prices, which are used for the economic
evaluation.
LICENCE HOLDINGS
The following table summarises the Group's licences as at 31
December 2020.
Licence Block(s) Description Role % Location
UK
--------- ------------------- --------------------------- ------------- ----- ---------------
P.090 9/9a Bruce Bruce Field Production Operator 99% Northern North
Sea
------------------- --------------------------- ------------- ----- ---------------
P.090 9/9a Rest of Block Development Operator 98% Northern North
Excluding Bruce Sea
(REST)
------------------- --------------------------- ------------- ----- ---------------
P.198 3/29a (ALL) Rhum Field Production Operator 50% Northern North
Sea
------------------- --------------------------- ------------- ----- ---------------
P.209 9/8a Bruce Bruce Field Production Operator 98% Northern North
Sea
------------------- --------------------------- ------------- ----- ---------------
P.209 9/8a Keith Keith Field Production Operator 100% Northern North
Sea
------------------- --------------------------- ------------- ----- ---------------
P.209 9/8a Rest of Block Development Operator 98% Northern North
Excluding Bruce Sea
and Keith (REST)
------------------- --------------------------- ------------- ----- ---------------
P.276 9/9b BRUCE Bruce Field Production Operator 98% Northern North
Sea
------------------- --------------------------- ------------- ----- ---------------
P.276 9/9c (ALL) Bruce Field Production Operator 98% Northern North
Sea
------------------- --------------------------- ------------- ----- ---------------
P.276 9/9b Rest of Block Development Operator 98% Northern North
Excluding Bruce Sea
Unit (REST)
------------------- --------------------------- ------------- ----- ---------------
P.566 3/29b (ALL) Rhum Field non-unitised Operator 100% Northern North
production Sea
------------------- --------------------------- ------------- ----- ---------------
P.975 3/24b (ALL) Rhum non-unitised Operator 100% Northern North
production Sea
------------------- --------------------------- ------------- ----- ---------------
P.975 3/29d (ALL) Rhum non-unitised Operator 100% Northern North
production Sea
------------------- --------------------------- ------------- ----- ---------------
P101 23/21a Columbus Columbus Development Operator 50% Central North
Area Sea
------------------- --------------------------- ------------- ----- ---------------
Columbus Development Central North
P1314 23/16f Area Operator 50% Sea
------------------- --------------------------- ------------- ----- ---------------
Central North
P57 23/26a Erskine Field - Production Non-operator 18% Sea
------------------- --------------------------- ------------- ----- ---------------
Central North
P264 23/26b Erskine Field - Production Non-operator 18% Sea
------------------- --------------------------- ------------- ----- ---------------
30/12c, 30/13c, Central North
P2400 30/17h, 30/18c Exploration Non-operator 20% Sea
------------------- --------------------------- ------------- ----- ---------------
Central North
P2402 30/19c Exploration Non-operator 20% Sea
------------------- --------------------------- ------------- ----- ---------------
Northern North
P2501 3/24c, 3/29c Exploration Operator 100% Sea
------------------- --------------------------- ------------- ----- ---------------
P2506 3/25b, 3/30, 4/26, Northern North
* 9/5a Exploration Operator 100% Sea
------------------- --------------------------- ------------- ----- ---------------
* Licence dated 19 January 2021
F INANCIAL REVIEW
Field revenues and costs are booked for Serica's full equity
interests and included within gross profits. Under the BKR deals,
amounts are due to the asset vendors for net cash flow sharing (50%
in 2019, 40% in 2020 and 2021) and certain other deferred payments.
Estimates of these amounts were included within the fair value upon
acquisition and subsequent changes are included as ' Change in fair
value of BKR financial liability' within profit before tax for each
reported period. Such variations are driven principally by changes
in commodity sales prices and production volumes.
2020 RESULTS
Serica generated a profit before taxation for 2020 of GBP12.5
million compared to GBP108.8 million for 2019. After non-cash
deferred tax provisions of GBP4.8 million (2019: GBP44.8 million),
profit for the year was GBP7.8 million compared to GBP64.0 million
for 2019.
Results for full year 2020 were impacted by the COVID-19 crisis,
which caused unprecedented falls in both oil and gas prices, and
also by a 45-day shut-down of the BKR fields early in the year to
secure a damaged caisson on the Bruce platform. However, the
combined effects of the BKR net cash flow sharing structure and
Serica's gas price hedging programme mitigated the cash impact of
each substantially. Net cash flow sharing payments under the BKR
deals were significantly reduced in line with lower net cash income
generated during the year. In addition, Serica's gas price hedging
programme effectively fixed prices for approximately one third of
retained gas sales for 2020 at approximately 39 pence per therm
before system fees - well above market levels. This was of
particular importance during H1 when market prices averaged below
20 pence per therm.
A particular and somewhat counterintuitive feature of the strong
recovery in gas prices late in 2020 was that future liabilities,
valued at 31 December on the basis of forward commodity prices,
increased compared to the 30 June 2020 valuation with consequent
impact upon the income statement during 2H 2020. These comprised
estimates of the final year of BKR net cash flow sharing and also
the valuation of our gas price hedging over 2021 and 2022. As
Serica retains 60% of BKR net cash flows in 2021 and 100%
thereafter, it stands to benefit substantially from increased cash
flows arising from strong commodity prices and this will be
reflected in 2021 cash flow and net income. Equally, as no more
than 25% of Serica's projected retained gas production for any
period is hedged, and currently none of its oil or other liquids,
the Company will also benefit during 2021 and thereafter should
actual commodity pricing prove to be as strong as the basis used
for valuing those hedge instrument liabilities. Nonetheless, in
view of recent and ongoing volatility in commodity markets the
Company's strategy remains to protect commodity pricing for a
proportion of its future production.
The overall impact of this volatile year was to deliver two
distinct periods. In H1, production interruption and plummeting oil
and gas prices led to net operating cash flow falling to breakeven
levels though this was then boosted by realised hedging income and
by reduced liability valuations at 30 June 2020. In H2, stronger
production and strengthening commodity prices, particularly in Q4,
led to greatly improved net operating cash though this was then
offset by the increased year end liability provisions described
above. Earnings before interest, tax, depreciation and exploration
("EBITDAX") in H1 were GBP9.6 million and in H2 were GBP30.4
million after adjustment for unrealised hedging losses.
Sales revenues
Total product sales volumes for the year comprised approximately
386.3 million therms of gas (2019: 491.3 million therms), 1,002,000
lifted barrels of oil (2019: 1,567,100 barrels) and 71,800 metric
tonnes of NGLs (2019: 85,500 metric tonnes). Overall, this
represented total 2020 product sales of 22,400 boe/d (2019: 29,300
boe/d) delivering total revenue of GBP125.6 million (2019: GBP250.5
million). This consisted of BKR revenues of GBP108.8 million (2019:
GBP216.6 million) and Erskine revenues of GBP16.8 million ( 2019:
GBP33.9 million). Average sales prices net of system fees were 21
pence per therm (2019: 31 pence per therm), US$42.4 per barrel
(2019: US$61.4 per barrel) and GBP176 per metric tonne (2019:
GBP266 per metric tonne) respectively giving a combined realised
sales price for lifted volumes of approximately US$20 per barrel of
oil equivalent (2019: US$30 per boe). This is before gas price
hedging gains detailed below.
Gross loss
The gross loss for 2020 was GBP2.9 million compared to a gross
profit of GBP85.8 million for 2019. Overall cost of sales of
GBP128.6 million compared to GBP164.7 million for 2019. This
comprised GBP89.7 million of operating costs (2019: GBP105.1
million) and GBP38.5 million of non-cash depletion charges (2019:
GBP52.6 million) plus a GBP0.3 million charge representing a
reduction during the year of the opening liquids underlift position
(2019: GBP7.0 million). Reductions in both operating costs and
depletion charges reflected lower production volumes plus other
operating cost savings, whilst depletion charges were further
reduced by an increase in remaining field reserves. Operating costs
comprise costs of production, processing, transportation and
insurance and averaged approximately US$14.12 per boe (2019:
US$12.6). An overall reduction in operating costs was achieved
despite exceptional expenditures on Bruce caisson repairs and
represented a reduction in underlying costs of some 10%. The
increase in operating costs per barrel for the year reflected lower
production volumes arising from the caisson shut-down whilst the
fixed element of operating costs continued to be incurred and does
not reflect an increase in the underlying trend.
Overall, despite the unprecedented fall in oil and gas sales
prices and the loss of 45 days of BKR production, sales revenues
for the year plus cash hedging gains covered cash operating costs
for the year one and a half times over.
Operating loss before BKR fair value adjustment, net finance
revenue, and tax
The operating loss for 2020 was GBP18.7 million compared to a
profit of GBP87.7 million for 2019. This included GBP4.3 million of
other expense from net commodity price hedging losses (2019: gain
of GBP10.6 million). Realised hedging gains of GBP12.3 million
(2019: GBP3.9 million) were more than offset by unrealised hedging
losses of GBP16.6 million (2019: gains of GBP6.7 million). The
unrealised losses reflected the surge in future gas prices at the
close of 2020 and will only become fully realised should actual
prices for 2021 and 2022 reach those levels. Overall, cash hedging
gains realised during 2020 represented approximately US$3 per boe
based upon retained volumes after adjustment for BKR cash flow
sharing.
E&E asset write-offs of GBP3.7 million (2019: GBP0.1
million) principally represented the write-off of exploration costs
following expiry of Serica's Namibian licence. Administrative
expenses of GBP5.6 million compared to GBP6.0 million for 2019
whilst share-based payments were GBP1.9 million (2019: GBP1.1
million) and currency losses were GBP0.3 million (2019: GBP1.0
million) largely arising on US$ holdings.
Profit before taxation and profit for the year after
taxation
Profit before taxation was GBP12.5 million (2019: GBP108.8
million) after a gain in the fair value of the BKR financial
liability of GBP31.3 million (2019: GBP21.8 million) and negligible
net finance costs (2019: GBP0.7 million). Net finance costs
represent the discount unwind on decommissioning provisions less
interest earned on cash deposits.
The fair value gain of GBP31.3 million arose following a
downwards revision of the fair value of the balance sheet financial
liability relating to consideration projected to be paid under the
BKR agreements. The fair value of this liability is re-assessed at
each financial period end. The most significant factors behind the
downward revision in fair value in the year are the impact of lower
production volumes and realised gas pricing on net cash flow
payments in respect of 2020.
The 2020 taxation charge of GBP4.8 million (2019: GBP44.8
million) solely comprised a non-cash deferred tax element. As the
Company continues to benefit from accumulated losses carried
forward from previous years it is not currently paying cash taxes.
It is nonetheless required to make provision for deferred taxes in
recognition of future periods when all losses have been utilised
and cash payments will commence.
Overall, this generated a profit after taxation for 2020 of
GBP7.8 million compared to a profit after taxation of GBP64.0
million for 2019.
GROUP BALANCE SHEET
The balance sheet at 31 December 2020 demonstrates Serica's
resilience during this turbulent year. This has allowed the Company
to fund its significant capital expenditures on Columbus
development and Rhum R3 well work from its cash resources without
recourse to borrowing and also to pay its maiden cash dividend of
GBP8.0 million.
A reduction in exploration and evaluation assets from GBP3.7
million in 2019 to GBP1.0 million at 31 December 2020 reflected a
GBP3.7 million write-off of past expenditures (including GBP3.5
million from Namibia) following licence relinquishment partially
offset by GBP1.0 million of new expenditure on UK licences during
2020.
Total property, plant and equipment decreased from GBP325.4
million at year end 2019 to GBP311.1 million at 31 December 2020
after depletion charges for 2020 of GBP38.5 million (2019: GBP52.6
million), asset revisions of GBP1.1 million (2019: GBP0.6 million)
and other charges of GBP0.2 million (2019: GBP0.2 million) partly
offset by capital expenditure on Columbus and Rhum during 2020 of
GBP25.5 million (2019: Columbus GBP4.5 million, other GBP0.2
million). Depletion charges represent the allocation of field
capital costs over the estimated producing life of each field and
principally comprise costs of asset acquisitions.
An inventories balance of GBP4.6 million at 31 December 2020
showed little change from GBP4.7 million at the end of 2019. An
increase in trade and other receivables from GBP35.9 million at the
end of 2019 to GBP41.3 million at 31 December 2020 largely
reflected higher prices for December gas sales plus increased
capital expenditure amounts recoverable from field partners. The
derivative financial asset of GBP6.9 million at year end 2019 had
become a derivative financial liability of GBP9.7 million at 31
December 2020. This represents the valuation of gas price hedges in
place at the respective year ends and the consequent amounts
projected to be either due or payable based upon futures pricing
prevailing at those points. Year end 2020 reflected particularly
strong futures pricing which, should it be realised, would deliver
greatly increased gas sales revenues during 2021 and 2022.
The reduction in cash balances from GBP101.8 million at 31
December 2019 to GBP89.3 million at 31 December 2020 reflected cash
flow from operations offset by both the significant capital
expenditures of GBP25.5 million and also the payment of a GBP8.0
million dividend during the year.
The increase in current trade and other payables to GBP31.1
million at 31 December 2020 from GBP24.6 million at the end of 2019
arose largely due to a high level of accruals related to the Rhum
R3 well work.
A final cash dividend for 2019 of 3 pence per share (2018: nil)
was proposed in April 2020 and approved at the annual general
meeting on 25 June 2020. The dividend was paid in July 2020.
Current financial liabilities of GBP53.6 million (31 December
2019: GBP45.4 million) and non-current financial liabilities of
GBP48.8 million (31 December 2019: GBP110.1 million) comprise total
remaining amounts projected to be paid under the BKR acquisition
agreements.
The current liability comprises amounts estimated to fall due
over the final twelve months of the net cash flow sharing
arrangements, a fixed payment of GBP16 million contingent upon the
outcome of the Rhum R3 well work and contingent consideration in
respect of Rhum field performance during 2021. Amounts due under
the net cash flow sharing arrangements are based on forward
projections of production volumes and sales prices. Subsequent
payments will be calculated on volumes and prices actually achieved
in 2021. The non-current liability comprises deferred consideration
in respect of BKR decommissioning and oil linefill. Under
arrangements for those BKR field interests acquired from BP, Total
E&P and BHP, decommissioning liabilities were retained by the
vendors with Serica liable to pay deferred consideration equivalent
to 30% of the actual costs of decommissioning net of tax recovered
by them.
The overall reduction in financial liabilities of GBP53.1
million during 2020 comprised cash amounts of GBP21.8 million paid
in the period and GBP31.3 million released through the income
statement. This release arose due to lower than previously forecast
net cash flow sharing payments in respect of 2020 partially offset
by a re-assessment of the estimated fair value of projected
remaining payments as at 31 December 2020.
Non-current provisions of GBP22.8 million have been made in
respect of decommissioning liabilities for the Bruce and Keith
interests acquired from Marubeni (31 December 2019: GBP22.6
million). These were not subject to the same deferred consideration
arrangements as applied for those field interests acquired from BP,
Total E&P and BHP described above. No provision is included for
decommissioning liabilities related to the Erskine facilities as
these liabilities are retained by BP up to a cap which is not
projected to be exceeded.
The deferred tax liability of GBP80.6 million at 31 December
2020 has increased from GBP75.8 million at year end 2019 and
reflects accounting provisions expected to be released against
future tax charges once the Group's tax losses have been fully
utilised.
Overall, net assets have increased from GBP198.0 million at year
end 2019 to GBP199.8 million at 31 December 2020 after payment of
GBP8.0 million in dividends.
The increase in share capital from GBP181.4 million to GBP181.6
million arose from shares issued following the exercise of share
options and shares issued under an employee share scheme, whilst
the increase in other reserves from GBP17.8 million to GBP19.7
million arose from share-based payments related to share option
awards.
CASH BALANCES AND FUTURE COMMITMENTS
Current cash position and price hedging
At 31 December 2020 the Group held cash and cash equivalents of
GBP89.3 million (2019: GBP101.8 million). This is after capital
investments during the year of GBP26.6 million and dividend
payments of GBP8.0 million plus monthly net cash flow sharing
payments and other BKR consideration totalling GBP11.4 million and
GBP10.4 million respectively. Amounts due under the net cash flow
sharing arrangements have fallen from 50% of BKR net operating cash
flows for 2019 to 40% for 2020. This leaves one more year of
payments at 40% and then zero thereafter. The GBP12.1 million of
total cash and cash equivalents held in a restricted account
against letters of credit issued in respect of certain
decommissioning liabilities as at 31 December 2020 (2019: GBP12.1
million) was reduced to GBP6.4 million effective 1 January 2021 due
to an upgrade in reserves and further extension of BKR field
life.
At 31 December 2020 Serica held gas price swaps covering 167,000
therms per day for H1 2021 and 192,000 therms per day for H2 2021
at average prices of 37 pence per therm and 36 pence per therm
respectively. It further held gas price swaps covering 200,000
therms per day for H1 2022 and 50,000 therms per day for H2 2022 at
average prices of 40 pence per therm and 37 pence per therm
respectively. At 31 December 2020 a cash margin call of GBP1.8
million had been paid to a hedge counterparty as security against
settlement of future hedge instruments (2019: nil).
In 2021 to date, Serica has obtained additional gas price swaps
covering 50,000 therms per day for H1 2022, 100,000 therms per day
for H2 2022 and 50,000 therms per day for Q1 2023 at average prices
of 46, 41 and 50 pence per therm respectively.
Following onset of the COVID-19 crisis in March last year, cash
projections were run to examine the potential impact of extended
low oil and gas prices as well as possible production interruptions
and the situation was kept under review thereafter. Some 80% of
Serica's production is gas with exposure to price falls partially
mitigated by price hedging now extending up to Q1 2023. The BKR net
cash flow sharing arrangements and structuring of elements of Rhum
deferred consideration further mitigate the impact of low sales
prices and any production interruptions upon net income to end
2021. This allied to the fact that Serica currently has substantial
cash resources, no borrowings and relatively low operating costs
per boe means that the Company is well placed to withstand such
risks and its capital commitments can be funded from existing cash
resources.
Field and other capital commitments
There are no existing capital commitments on the Erskine
producing field and net production revenues are expected to cover
all ongoing field expenditures. Serica's share of decommissioning
costs relating to its 18% Erskine field interest will be met by BP
up to a level of GBP31.3 million, adjusted for inflation, and
Serica's current estimate of such costs is below this level.
There are no significant existing capital commitments on the BKR
producing fields other than an estimated GBP11 million net to
Serica outstanding at 31 December 2020 on the Rhum R3 well work,
expected to be completed during Q2 2021. Potential further
programmes to enhance current production profiles and extend field
life are under consideration. Net revenues from Serica's share of
income from the BKR fields, after net cash flow sharing payments,
is expected to cover Serica's retained share of ongoing field
expenditures as well as other contingent or deferred consideration
due under the respective BKR acquisition agreements set out
below.
The Columbus development is underway with first gas expected in
Q4 2021. Total development expenditure net to Serica's share
outstanding at 31 December 2020 is estimated at approximately GBP15
million.
The Group has no significant exploration commitments apart from
a well on the North Eigg prospect to be drilled within three years
of the 1 January 2020 licence award.
BKR asset acquisitions
On 30 November 2018 Serica completed the four BKR acquisitions.
The following elements of consideration were outstanding at 31
December 2020:
-- A contingent payment of GBP16.0 million is due to BP
Exploration Operating Company ("BPEOC") upon bringing the Rhum R3
well onto production and achieving a minimum cumulative 90 days of
gas production at a defined level.
-- A contingent payment of up to GBP7.7 million is due to BPEOC
based upon Rhum 2021 average field production and commodity sales
prices in the year. The payment made in respect of 2019 was GBP2.6
million whilst the payment calculated in respect of 2020 and made
in Q1 2021 was GBP1.0 million. There will be a final calculation of
the combined average performance covering years 2019 to 2021 and
applied to the total potential consideration for the three years of
up to GBP23.1 million. Any difference between this calculation and
cumulative payments to-date will then be settled.
-- In addition, Serica will pay contingent cash consideration to
BPEOC, Total E&P and BHP calculated as 40% of 2021 net cash
flows resulting from the respective field interests acquired from
those companies. Such amounts will be paid by Serica pre-tax on a
monthly basis and then offset by Serica against its own tax
liabilities.
-- BP, Total E&P and BHP will retain liability, in respect
of the field interests Serica acquired from each of them, for all
the costs of decommissioning those facilities that existed at the
date of completion. Serica will pay deferred consideration equal to
30% of actual future decommissioning costs, reduced by the tax
relief that each of BP, Total E&P and BHP receives on such
costs. Staged prepayments against such projected amounts will
commence in 2022 and be spread over the remaining years before
cessation of field production.
-- Serica will pay to each of BP, Total E&P and BHP,
deferred consideration equal to 90% of their respective shares of
the realised value of oil in the Bruce pipeline at the end of field
life.
OTHER
Asset values and impairment
At 31 December 2020, Serica's market capitalisation stood at
GBP308.0 million based upon a share price of 115 pence which
exceeded the net asset value of GBP199.8 million. By 13 April the
Company's market capitalisation has risen to GBP320.5 million.
BUSINESS RISK AND UNCERTAINTIES
Serica, like all companies in the oil and gas industry, operates
in an environment subject to inherent risks and uncertainties. The
Board regularly considers the principal risks to which the Group is
exposed and monitors any agreed mitigating actions. The overall
strategy for the protection of shareholder value against these
risks is to retain a broad portfolio of assets with varied
risk/reward profiles, to apply prudent industry practice, to carry
insurance, where both available and cost effective, and to retain
adequate working capital.
Following completion of the four BKR acquisitions in 2018,
Serica has built a strong working capital reserve. This is
available to respond to a range of risks including production
interruptions, severe commodity price falls and unexpected costs.
To supplement this the Company carries business interruption
insurance to mitigate the impact of deferred or lost revenues over
sustained periods of production shut-in beyond an initial 60 days,
where caused by events covered under such policies. The Company
also uses price hedging instruments to help manage field revenues
and will continue to seek cost effective opportunities to add to
its existing hedge position. These currently cover up to 25% of the
Company's retained share of projected 2021 and 2022 gas
production.
The principal risks currently recognised and the mitigating
actions taken by the management are as follows:
Investment Returns: Management seeks to invest in a portfolio
of exploration, development and producing acreage capable
of delivering returns to shareholders through acquisitions
of producing assets to which it can add further value and
through the discovery and exploitation of commercial reserves.
Delivery of this business model carries a number of key risks.
Risk Mitigation
-----------------------------------------------------------------
Stock market support may be
eroded lowering investor appetite * Management regularly communicates its strategy to
and obstructing fundraising shareholders
* Focus is placed on building a diverse and resilient
asset portfolio capable of offering prospectivity
throughout the business cycle
-----------------------------------------------------------------
Each investment carries its
own risk profile and no outcome * Management aims to avoid over-exposure to individual
can be certain assets, to identify the associated risks objectively
and mitigate where practical
-----------------------------------------------------------------
Operations: Operations may not go according to plan leading
to damage, pollution, cost overruns or poor outcomes.
Risk Mitigation
------------------------------------------------------------------
Production may be interrupted
generating significant revenue * The Company seeks to diversify its revenue streams
loss whilst costs continue to
be incurred
* Management determines and retains an appropriate
level of working capital
* Business interruption cover is carried when cost
effective
------------------------------------------------------------------
Third party offtake routes may
experience restrictions or interruptions * The Group aims to diversify its exposure to offtake
and full availability may depend routes where possible though all of its oil
upon sustained production from production currently uses the FPS system
other fields in the system
* The Group carries business interruption cover
------------------------------------------------------------------
The Company is reliant upon
its IT systems to maintain operations * The Group employs specialist support
and communications
* Protection against external intrusion is incorporated
within the system and tested regularly
------------------------------------------------------------------
Personnel: The Group relies upon a pool of experienced and
motivated personnel to conduct its operations and execute
successful investment strategies
Risks Mitigation
----------------------------------------------------------------
Key personnel may be lost to
other companies * The Remuneration Committee regularly evaluates
incentivisation schemes to ensure they remain
competitive
* The Group seeks to build depth of experience in all
key functions to ensure continuity
----------------------------------------------------------------
Personal safety may be at risk
in demanding operating environments, * A culture of safety is encouraged throughout the
typically offshore organisation
* Responsible personnel are designated at all
appropriate levels
* The Group maintains up-to-date emergency response
resources and procedures
----------------------------------------------------------------
Political and commercial environment: World share and commodity
markets and political environments continue to be volatile
Risk Mitigation
------------------------------------------------------------------
Sanctions imposed by the U.S.
government may threaten continuing * An OFAC Licence has been obtained which has enabled
production from the Rhum field continuing production from Rhum
and licences are required to
be renewed periodically
* Serica initiates the renewal process well in advance
of the specified date
------------------------------------------------------------------
The UKCS licensing regime under
which Serica's operational rights * Management maintains regular communication with
and obligations are defined regulatory authorities
may be subject to future change
* The Company aligns its standards and objectives with
government policies as closely as possible
------------------------------------------------------------------
Volatile commodity prices mean
that the Group cannot be certain * Planning and forecasting considers downside price
of the future sales value of scenarios
its products
* Oil and gas floor price hedging may be utilised where
deemed cost effective
* Price mitigation strategies may be employed at the
point of major capital commitment
------------------------------------------------------------------
COVID-19: The impact of the virus has significantly affected
the majority of global activities and markets. The full extent
and duration of the crisis remains uncertain.
Risk Mitigation
------------------------------------------------------------------------
The Company's personnel may
be at risk from catching the * The Company has instituted recommended safe practices
virus and will maintain these as necessary
* Serica has instituted a programme of working from
home where feasible and temporarily closed its London
and Aberdeen offices
------------------------------------------------------------------------
The spread of infection and
associated counter measures * The Company has reduced the number of staff working
may interrupt offshore operations offshore to a safe minimum
* Management encourages safe practices travelling to
and from the platform and mandates additional
precautions whilst offshore
------------------------------------------------------------------------
The continued operation of Serica's
fields may be adversely affected * Serica carries a working capital reserve to cover
by interruptions to operations such eventualities
of fields and infrastructure
downstream
* Serica works with the regulatory bodies and
infrastructure owners to identify and mitigate any
such risks
------------------------------------------------------------------------
ESG strategy and risk management
Details of ESG strategies directed towards reducing carbon
emissions and contributing to government net zero targets are
described on pages 48 and 49 and also in a separate ESG Report
which will be issued in conjunction with publication of the 2020
Annual Report.
Serica has reviewed guidance issued by the Task Force on
Climate-related Financial Disclosures ("TCFD") with regard to the
identification, management and reporting of climate-related
financial risks. The Company is in the process of developing its
capabilities to report under TCFD guidance.
Management considers climate-related strategic and financial
risks in both its existing asset portfolio and future business
growth including potential acquisitions. This includes
consideration of the potential impact of both transition and
physical risks.
Key Performance Indicators ("KPIs")
The Company's main business is the acquisition, development and
production of commercially attractive oil and gas reserves in a
safe and environmentally sensitive manner. This is achieved both
through pursuing the full cycle of exploration, discovery,
development and production and also through acquiring existing
reserves where management believe that further value can be
added.
Operational and financial performance is tracked through the
following KPI's whose progress is covered within the Review of
Operations and Finance Review within this strategic report:
-- Daily production volumes
-- Production costs per barrel of oil equivalent
-- Realised sales income per barrel of oil equivalent
HSE performance is tracked through the following KPI's whose
progress is covered within the ESG Report to be issued along with
the 2020 Annual Report:
-- Recordable incidents and injuries
-- Workforce engagement in HSE
-- Quality of discharges to water and air
ESG performance is tracked through the following KPI's whose
progress is covered within the ESG Report to be issued along with
the 2020 Annual Report:
-- Carbon intensity
-- Flare volumes
-- Workforce engagement in ESG
-- Waste volumes generated
-- Diversity of personnel
Elements falling within each of the above categories are
included within annual incentive schemes for all Group
employees.
The Company tracks its new business development objectives
through the building of a risk-balanced portfolio of full cycle
assets. Specific KPI's are not applied due to the range of
different potential acquisition targets. However, successful
delivery will add to future production volumes and net realised
income.
Further information upon the Company's HSE and ESG policies and
delivery can be found in an updated ESG Report which will be issued
along with the 2020 Annual Report.
Section 172 statement
The Directors' statement under Section 172 of the Companies Act
2006 is included on pages 45 to 47.
Additional Information
Additional information relating to Serica, can be found on the
Company's website at www.serica-energy.com and on SEDAR at
www.sedar.com
The Strategic Report has been approved by the Board of
Directors.
On behalf of the Board
Mitch Flegg
Chief Executive Officer
14 April 2021
Forward Looking Statements
This disclosure contains certain forward looking statements that
involve substantial known and unknown risks and uncertainties, some
of which are beyond Serica Energy plc's control, including: the
impact of general economic conditions where Serica Energy plc
operates, industry conditions, changes in laws and regulations
including the adoption of new environmental laws and regulations
and changes in how they are interpreted and enforced, increased
competition, the lack of availability of qualified personnel or
management, fluctuations in foreign exchange or interest rates,
stock market volatility and market valuations of companies with
respect to announced transactions and the final valuations thereof,
and obtaining required approvals of regulatory authorities. Serica
Energy plc's actual results, performance or achievement could
differ materially from those expressed in, or implied by, these
forward looking statements and, accordingly, no assurances can be
given that any of the events anticipated by the forward looking
statements will transpire or occur, or if any of them do so, what
benefits, including the amount of proceeds, that Serica Energy plc
will derive therefrom.
Serica Energy plc
Group Income Statement
For the year ended 31 December
Registered Number: 5450950
Balance Sheet
As at 31 December
2020 2019
Note GBP000 GBP000
Continuing operations
Sales revenue 4 125,641 250,533
Cost of sales 5 (128,560) (164,748)
Gross (loss)/profit (2,919) 85,785
Other (expense)/income 6 (4,276) 10,618
Pre-licence costs - (566)
E&E asset write-offs 14 (3,725) (80)
Administrative expenses (5,579) (5,963)
Foreign exchange loss (344) (1,020)
Share-based payments 27 (1,862) (1,094)
Operating (loss)/profit before net finance revenue (18,705) 87,680
and tax
Change in fair value of BKR financial liabilities 22 31,296 21,771
Finance revenue 9 465 571
Finance costs 10 (508) (1,252)
Profit before taxation 12,548 108,770
Taxation charge for the year 11a) (4,769) (44,750)
Profit for the year 7,779 64,020
========== ==========
Earnings per ordinary share - EPS
Basic EPS on profit for the year (GBP) 12 0.03 0.24
Diluted EPS on profit for the year (GBP) 12 0.03 0.23
Group Statement of Comprehensive Income
There are no other comprehensive income items other than those
passing through the income statement.
Serica Energy plc
Registered Number: 5450950
Balance Sheet
As at 31 December
Group Company
2020 2019 2020 2019
Note GBP000 GBP000 GBP000 GBP000
Non-current assets
Exploration & evaluation assets 14 1,043 3,652 - -
Property, plant and equipment 15 311,125 325,404 215 387
Investments in subsidiaries 16 - - 105,256 105,256
312,168 329,056 105,471 105,643
---------- ---------- -------- ---------
Current assets
Inventories 17 4,633 4,671 - -
Trade and other receivables 18 41,329 35,906 162,291 93,330
Derivative financial asset 19 - 6,880 - -
Cash and cash equivalents 20 89,333 101,825 7,078 11,348
---------- ---------- -------- ---------
135,295 149,282 169,369 104,678
---------- ---------- -------- ---------
TOTAL ASSETS 447,463 478,338 274,840 210,321
---------- ---------- -------- ---------
Current liabilities
Trade and other payables 21 (31,121) (24,600) (995) (1,738)
Derivative financial liability 19 (9,691) - - -
Financial liabilities 22 (53,634) (45,351) - -
Provisions 23 (1,002) (1,848) - -
Non-current liabilities
Financial liabilities 22 (48,770) (110,108) - -
Provisions 23 (22,799) (22,590) - -
Deferred tax liability 11d) (80,600) (75,831) - -
---------- ---------- -------- ---------
TOTAL LIABILITIES (247,617) (280,328) (995) (1,738)
---------- ---------- -------- ---------
NET ASSETS 199,846 198,010 273,845 208,583
========== ========== ======== =========
Share capital 25 181,606 181,385 153,907 153,686
Merger reserve 16 - - 88,088 88,088
Other reserve 19,680 17,818 19,680 17,818
Accumulated (deficit)/funds (1,440) (1,193) 12,170 (51,009)
TOTAL EQUITY 199,846 198,010 273,845 208,583
========== ========== ======== =========
The profit for the Company was GBP71.2 million for the year
ended 31 December 2020 (2019: loss of GBP2.6 million). In
accordance with the exemption granted under section 408 of the
Companies Act 2006 a separate income statement for the Company has
not been presented.
Approved by the Board on 14 April 2021
Antony Craven Walker Mitch Flegg
Executive Chairman Chief Executive Officer
Serica Energy plc
Statement of Changes in Equity
For the year ended 31 December
Group Other Accum'd
Note Share capital reserve deficit Total
GBP000 GBP000 GBP000 GBP000
At 1 January 2019 180,294 16,724 (65,213) 131,805
Profit for the year - - 64,020 64,020
-------------- --------- --------- --------
Total comprehensive income - - 64,020 64,020
Share-based payments 27 - 1,094 - 1,094
Issue of share capital 25 1,091 - - 1,091
At 31 December 2019 181,385 17,818 (1,193) 198,010
Profit for the year - - 7,779 7,779
--------
Total comprehensive income - - 7,779 7,779
Share-based payments 27 - 1,862 - 1,862
Issue of share capital 25 221 - - 221
Dividend paid 13 - - (8,026) (8,026)
At 31 December 2020 181,606 19,680 (1,440) 199,846
============== ========= ========= ========
Share Merger Other Accum'd
Company capital reserve reserve funds/ Total
(deficit)
GBP000 GBP000 GBP000 GBP000 GBP000
At 1 January 2019 152,595 88,088 16,724 (48,426) 208,981
Loss for the year - - - (2,583) (2,583)
--------- --------- --------- ---------- --------
Total comprehensive income - - - (2,583) (2,583)
Share-based payments (note
27) - - 1,094 - 1,094
Issue of share capital
(note 25) 1,091 - - - 1,091
At 31 December 2019 153,686 88,088 17,818 (51,009) 208,583
Profit for the year - - - 71,205 71,205
--------- --------- --------- ---------- --------
Total comprehensive income - - - 71,205 71,205
Share-based payments (note
27) - - 1,862 - 1,862
Issue of share capital
(note 25) 221 - - - 221
Dividend paid (note 13) - - - (8,026) (8,026)
At 31 December 2020 153,907 88,088 19,680 12,170 273,845
========= ========= ========= ========== ========
Serica Energy plc
Cash Flow Statement
For the year ended 31 December
Group Company
2020 2019 2020 2019
Note GBP000 GBP000 GBP000 GBP000
Operating activities:
Profit/(loss) for the year 7,779 64,020 71,205 (2,583)
Adjustments to reconcile profit
for the year
to net cash flow from operating
activities:
Taxation charge 4,769 44,750 - -
Change in BKR fair value liability (31,296) (21,771) - -
Net finance costs/(income) 43 681 (20) (176)
Depreciation and depletion 38,495 52,631 - -
Oil and NGL over/underlift 342 6,969 - -
E&E asset write-offs 3,725 80 - -
Unrealised hedging losses/(gains) 16,571 (6,742) - -
Write-back of loans and investments - - - -
Share-based payments 1,862 1,094 1,862 1,094
Other non-cash movements 629 638 182 (149)
(Increase)/decrease in trade and
other (5,423) 6,147 (74,906) 1,100
receivables
Decrease/(increase) in inventories 38 (386) - -
Increase/(decrease) in trade and
other 6,537 (11,056) (438) (1,690)
payables
--------- --------- --------- --------
Net cash in/(out)flow from operations 44,071 137,055 (2,115) (2,404)
--------- --------- --------- --------
Investing activities:
Interest received 465 571 57 225
Purchase of E&E assets (1,116) (549) - -
Purchase of property, plant and
equipment (25,530) (4,736) - -
Cash outflow from business combination 22 (21,759) (57,259) - -
Cash outflow arising on asset acquisitions - - - -
Changes in term deposits - 1,000 - 1,000
Receipts/(payments) from Group
subsidiaries - - 5,945 (8,196)
Net cash flow from investing activities (47,940) (60,973) 6,002 (6,971)
--------- --------- --------- --------
Financing activities:
Repayments of borrowings 22 - (15,673) - -
Payments of lease liabilities 28 (133) (178) (133) (178)
Proceeds from issue of shares 25 221 1,091 221 1,091
Dividends paid 13 (8,026) - (8,026) -
Finance costs paid (56) (962) (37) (49)
Net cash flow from financing activities (7,994) (15,722) (7,975) 864
----------- --------- ---------- --------
Net (decrease)/increase in cash
and cash equivalents 26 (11,863) 60,360 (4,088) (8,511)
Effect of exchange rates on cash
and cash
equivalents 26 (629) (638) (182) 149
Cash and cash equivalents at 1
January 26 101,825 42,103 11,348 19,710
Cash and cash equivalents at 31
December 26 89,333 101,825 7,078 11,348
=========== ========= ========== ========
Serica Energy plc
Notes to the Financial Statements
1. Authorisation of the Financial Statements and Statement of
Compliance with International Accounting Standards in conformity
with the requirements of the Companies Act 2006
These are not the statutory accounts of the Company prepared in
accordance with the Companies Act. The Group's and Company's
financial statements for the year ended 31 December 2020 were
authorised for issue by the Board of Directors on 14 April 2021 and
the balance sheets were signed on the Board's behalf by Antony
Craven Walker and Mitch Flegg. Serica Energy plc is a public
limited company incorporated and domiciled in England & Wales
with its registered office at 48 George Street, London, W1U 7DY.
The principal activity of the Company and the Group is to identify,
acquire and subsequently exploit oil and gas reserves. Its current
activities are located in the United Kingdom. The Company's
ordinary shares are traded on AIM.
The Group's financial statements have been prepared in
accordance with International Accounting Standards in conformity
with the requirements of the Companies Act 2006 as they apply to
the financial statements of the Group for the year ended 31
December 2020. The Company's financial statements have been
prepared in accordance with International Accounting Standards in
conformity with the requirements of the Companies Act 2006 as they
apply to the financial statements of the Company for the year ended
31 December 2020 and as applied in accordance with the provisions
of the Companies Act 2006. The principal accounting policies
adopted by the Group and by the Company are set out in note 2.
The Company has taken advantage of the exemption provided under
section 408 of the Companies Act 2006 not to publish its individual
income statement and related notes. The profit dealt with in the
financial statements of the parent Company was GBP71,205,000 (2019:
loss GBP2,583,000).
2. Accounting Policies
Basis of Preparation
The accounting policies which follow set out those policies
which apply in preparing the financial statements for the year
ended 31 December 2020.
The Group and Company financial statements have been prepared on
a historical cost basis and following the change in functional and
presentational currency from US$ to GBP sterling with effect from 1
January 2019 are presented in GBP sterling. All values are rounded
to the nearest thousand pounds (GBP000) except when otherwise
indicated.
Going Concern
The Directors are required to consider the availability of
resources to meet the Group's liabilities for the foreseeable
future. The financial position of the Group, its cash flows and
capital commitments are described in the Financial Review
above.
At 31 December 2020 the Group held cash and term deposits of
GBP89.3 million which had increased to approximately GBP93.6
million by 31 March 2021 after payment of GBP4.6 million of margin
calls related to outstanding gas price hedging. The balance at 31
March 2021 included GBP6.4 million of restricted funds. The bulk of
contingent and deferred consideration due under the BKR acquisition
agreements is related to future successful field performance and
consequently will be either reduced or deferred in the event of
lower net cash generation from either production interruptions or
lower oil and gas prices.
The Group regularly monitors its cash, funding and liquidity
position. Near term cash projections are revised and underlying
assumptions reviewed, generally monthly, and longer-term
projections are also updated regularly. Downside price and other
risking scenarios are considered. In addition to commodity sales
prices the Group is exposed to potential production interruptions
and these are also considered under such scenarios. Serica's
acquisitions to-date have been structured to reduce post-completion
risk and, following completion of the BKR transactions, management
has given priority to building a strong cash reserve which can
respond to different types of risk. For the purposes of the Group's
going concern assessment we have reviewed cash projections for the
period ending 30 June 2022, the 'going concern period'.
Following onset of the COVID-19 crisis, we stress tested future
cash flow forecasts for the Group to evaluate the impact of
plausible downside scenarios. The environment has since improved
but Serica continues to model the downside impact of production
interruption and lower than forecast commodity prices. These
include scenarios that reflect extended low oil and gas prices over
2021 and 2022, which are lower than current forecasts and forward
prices, and a three-month production shut-in to reflect potential
operational or COVID-19 related issues that could impact the Group.
Under such scenarios we retain sufficient liquidity in our
business. We have also performed a reverse stress test to assist
our judgement which is designed to model the extreme price
conditions that would have to exist such that the Group required
additional cash resources or had to rely upon additional cash
resources within the going concern period.
The impact of low gas prices is partially mitigated by price
hedging up to 31 March 2023 for a proportion of projected gas sales
volumes, which deliver monthly cash inflows to Serica where market
prices are lower than 31 up to 50 pence per therm with the price
variations reflecting the periods covered. The BKR net cash flow
sharing arrangements, which run to end 2021, vary in line with
actual net cash generated and therefore the impact of lower sales
prices and production volumes will be shared by Serica and the
previous BKR owners.
Serica currently has no borrowings, relatively low operating
costs per boe and its limited capital commitments can be funded
from existing cash resources. Additionally, we have implemented
operating cost reductions which provide further resilience against
softer commodity prices. In particular, Serica has reduced the
level of offshore personnel through the COVID-19 period by
deferring non-essential work and has facilitated remote working
wherever possible.
After making enquiries and having taken into consideration the
above factors, the Directors have reasonable expectation that the
Group has adequate resources to continue in operational existence
for the going concern period. Accordingly, they continue to adopt
the going concern basis in preparing the financial statements
Use of judgement and estimates and key sources of estimation
uncertainty
The preparation of financial statements in conformity with
International Accounting Standards in conformity with the
requirements of the Companies Act 2006 requires management to make
estimates and assumptions that affect the reported amounts of
assets and liabilities as well as the disclosure of contingent
assets and liabilities at the balance sheet date and the reported
amounts of revenues and expenses during the reporting period.
Estimates and judgements are continuously evaluated and are based
on management's experience and other factors, including
expectations of future events that are believed to be reasonable
under the circumstances. Actual outcomes could differ from these
estimates.
The key sources of estimation uncertainty that have a
significant risk of causing material adjustment to the amounts
recognised in the financial statements are: determining the fair
value of contingent consideration, determining the fair value of
property, plant and equipment on a business combination,
decommissioning provisions, the assessment of commercial reserves,
the impairment of the Group and Company's assets (including oil and
gas development assets and Exploration and Evaluation "E&E"
assets), and the recoverability of deferred tax assets.
Determining the fair value of contingent consideration on BKR
acquisitions
The Group determined the fair value of initial contingent
consideration payable based on discounted cash flows at the time of
the acquisition in 2018, calculated for each separate component of
the contingent consideration. The same models and assumptions were
used in the calculation of the fair value of property, plant and
equipment arising on the business combination. Any cash flows
specific to the contingent consideration also reflect applicable
commercial terms and risks. In calculating the fair value of
contingent consideration on the BKR acquisitions payable as at 31
December 2020, assumptions underlying the calculation were updated
from 2019. These included updated commodity prices, production
profiles, future opex, capex and decommissioning cost estimates,
discount rates, proved and probable reserves estimates and risk
assessments. For further details including sensitivities of the
calculation to changes in input variables, see note 22.
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
(see note 23).
Assessment of commercial oil and gas reserves
Management is required to assess the level of the Group's
commercial reserves together with the future expenditures to access
those reserves, which are utilised in determining the amortisation
and depletion charge for the period and assessing whether any
impairment charge is required. The Group employs independent
reserves specialists who periodically assess the Group's level of
commercial reserves by reference to data sets including geological,
geophysical and engineering data together with reports,
presentation and financial information pertaining to the
contractual and fiscal terms applicable to the Group's assets. In
addition, the Group undertakes its own assessment of commercial
reserves and related future capital expenditure by reference to the
same data sets using its own internal expertise.
Assessment of the recoverable amount of intangible and tangible
assets
The Group monitors internal and external indicators of
impairment relating to its intangible and tangible assets, which
may indicate that the carrying value of the assets may not be
recoverable. The assessment of the existence of indicators of
impairment in E&E assets involves judgement, which includes
whether licence performance obligations can be met within the
required regulatory timeframe, whether management expects to fund
significant further expenditure in respect of a licence, and
whether the recoverable amount may not cover the carrying value of
the assets. For development and production assets judgement is
involved when determining whether there have been any significant
changes in the Group's oil and gas reserves.
The Group determines whether E&E assets are impaired at an
asset level and in regional cash generating units ('CGUs') when
facts and circumstances suggest that the carrying amount of a
regional CGU may exceed its recoverable amount. As recoverable
amounts are determined based upon risked potential, or where
relevant, discovered oil and gas reserves, this involves
estimations and the selection of a suitable pre-tax discount rate
relevant to the asset in question. The calculation of the
recoverable amount of oil and gas development and production
properties involves estimating the net present value of cash flows
expected to be generated from the asset in question. Future cash
flows are based on assumptions on matters such as estimated proven
and probable oil and gas reserve quantities and commodity prices.
The discount rate applied is a pre-tax rate which reflects the
specific risks of the country in which the asset is located.
Management is required to assess the carrying value of
investments in subsidiaries in the parent company balance sheet for
impairment by reference to the recoverable amount. This requires an
estimate of amounts recoverable from oil and gas assets within the
underlying subsidiaries (see note 16).
A review was performed for any indication that the value of the
Group's oil and gas assets may be impaired at the balance sheet
date of 31 December 2020 in accordance with the stated policy and
no impairment triggers were noted.
Deferred taxation
Deferred tax assets, including those arising from unutilised tax
losses, require management to assess the likelihood that the Group
will generate sufficient taxable profits in future periods, in
order to utilise recognised deferred tax assets. Assumptions about
the generation of future taxable profits depend on management's
estimates of future cash flows. These estimates are based on
forecast cash flows from operations (which are impacted by
production and sales volumes, oil and natural gas prices, reserves,
operating costs, decommissioning costs, capital expenditure,
dividends and other capital management transactions) and judgement
about the application of existing tax laws. To the extent that
actual events differ significantly from estimates, the ability of
the Group to realise deferred tax assets could be impacted.
Basis of Consolidation
The consolidated financial statements include the accounts of
Serica Energy plc (the "Company") and its wholly owned subsidiaries
Serica Holdings UK Limited, Serica Energy Holdings B.V., Serica
Energy (UK) Limited, Serica Glagah Kambuna B.V., Serica Sidi Moussa
B.V., Serica Energy Slyne B.V., Serica Energy Rockall B.V., Serica
Energy Namibia B.V., Serica Energy Corporation, Asia Petroleum
Development Limited, Petroleum Development Associates (Asia)
Limited and Petroleum Development Associates (Lematang) Limited.
Together these comprise the "Group".
All inter-company balances and transactions have been eliminated
upon consolidation.
Foreign Currency Translation
The functional and presentational currency of Serica Energy plc
and its subsidiaries is GBP sterling following the change in
functional and presentational currency from US$ to GBP sterling
with effect from 1 January 2019.
Transactions in foreign currencies are initially recorded at the
functional currency rate ruling at the date of the transaction.
Monetary assets and liabilities denominated in foreign currencies
are retranslated at the foreign currency rate of exchange ruling at
the balance sheet date and differences are taken to the income
statement. Non-monetary items that are measured in terms of
historical cost in a foreign currency are translated using the
exchange rate as at the date of initial transaction. Non-monetary
items measured at fair value in a foreign currency are translated
using the exchange rate at the date when the fair value was
determined. Exchange gains and losses arising from translation are
charged to the income statement as an operating item.
Business Combinations and Goodwill
Business combinations from 1 January 2010
Business combinations are accounted for using the acquisition
method. The cost of an acquisition is measured as the aggregate of
consideration transferred, measured at acquisition date fair value
and the amount of any non-controlling interest in the acquiree.
Acquisition costs incurred are expensed.
When the Group acquires a business, it assesses the financial
assets and liabilities assumed for appropriate classification and
designation in accordance with the contractual terms, economic
circumstances and pertinent conditions as at the acquisition date.
Any contingent consideration to be transferred to the acquirer will
be recognised at fair value at the acquisition date. Contingent
consideration classified as an asset or liability that is a
financial instrument and within the scope of IFRS 9 Financial
Instruments, is measured at fair value with the changes in fair
value recognised in the statement of profit or loss in accordance
with IFRS 9. Other contingent consideration that is not within the
scope of IFRS 9 is measured at fair value at each reporting date
with changes in fair value recognised in profit or loss.
Goodwill on acquisition is initially measured at cost being the
excess of purchase price over the fair market value of identifiable
assets, liabilities and contingent liabilities acquired. Following
initial acquisition, it is measured at cost less any accumulated
impairment losses. Goodwill is not amortised but is subject to an
impairment test at least annually and more frequently if events or
changes in circumstances indicate that the carrying value may be
impaired. 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 fair value of net
assets acquired over the aggregate consideration transferred, then
the gain is recognised in profit or loss.
At the acquisition date, any goodwill acquired is allocated to
each of the cash-generating units, or groups of cash generating
units expected to benefit from the combination's synergies.
Impairment is determined by assessing the recoverable amount of the
cash-generating unit, or groups of cash generating units to which
the goodwill relates. Where the recoverable amount of the
cash-generating unit is less than the carrying amount, an
impairment loss is recognised.
Joint Arrangements
A joint operation is a type of joint arrangement 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 conducts petroleum and natural gas exploration and
production activities jointly with other venturers who each have
direct ownership in and jointly control the operations of the
ventures. These are classified as jointly controlled operations and
the financial statements reflect the Group's share of assets and
liabilities in such activities. Income from the sale or use of the
Group's share of the output of jointly controlled operations, and
its share of joint venture expenses, are recognised when it is
probable that the economic benefits associated with the transaction
will flow to/from the Group and their amount can be measured
reliably.
Full details of Serica's working interests in those petroleum
and natural gas exploration and production activities classified as
joint operations are included in the Review of Operations.
Exploration and Evaluation Assets
As allowed under IFRS 6 and in accordance with clarification
issued by the International Financial Reporting Interpretations
Committee, the Group has continued to apply its existing accounting
policy to exploration and evaluation activity, subject to the
specific requirements of IFRS 6. The Group will continue to monitor
the application of these policies in light of expected future
guidance on accounting for oil and gas activities.
Pre-licence Award Costs
Costs incurred prior to the award of oil and gas licences,
concessions and other exploration rights are expensed in the income
statement.
Exploration and Evaluation (E&E)
The costs of exploring for and evaluating oil and gas
properties, including the costs of acquiring rights to explore,
geological and geophysical studies, exploratory drilling and
directly related overheads, are capitalised and classified as
intangible E&E assets. These costs are directly attributed to
regional CGUs for the purposes of impairment testing; UK &
Ireland and Africa.
E&E assets are not amortised prior to the conclusion of
appraisal activities but are assessed for impairment at an asset
level and in regional CGUs when facts and circumstances suggest
that the carrying amount of a regional cost centre may exceed its
recoverable amount. Recoverable amounts are determined based upon
risked potential, and where relevant, discovered oil and gas
reserves. When an impairment test indicates an excess of carrying
value compared to the recoverable amount, the carrying value of the
regional CGU is written down to the recoverable amount in
accordance with IAS 36. Such excess is expensed in the income
statement. Where conditions giving rise to impairment subsequently
reverse, the effect of the impairment charge is reversed as a
credit to the income statement.
Costs of licences and associated E&E expenditure are
expensed in the income statement if licences are relinquished, or
if management do not expect to fund significant future expenditure
in relation to the licence.
The E&E phase is completed when either the technical
feasibility and commercial viability of extracting a mineral
resource are demonstrable or no further prospectivity is recognised
. At that point, if commercial reserves have been discovered, the
carrying value of the relevant assets, net of any impairment
write-down, is classified as an oil and gas property within
property, plant and equipment, and tested for impairment. If
commercial reserves have not been discovered then the costs of such
assets will be written off.
Asset Purchases and Disposals
When a commercial transaction involves the exchange of E&E
assets of similar size and characteristics, no fair value
calculation is performed. The capitalised costs of the asset being
sold are transferred to the asset being acquired. Proceeds from a
part disposal of an E&E asset, including back-cost
contributions are credited against the capitalised cost of the
asset, with any excess being taken to the income statement as a
gain on disposal.
Farm-ins
In accordance with industry practice, the Group does not record
its share of costs that are 'carried' by third parties in relation
to its farm-in agreements in the E&E phase. Similarly, while
the Group has agreed to carry the costs of another party to a Joint
Operating Agreement ("JOA") in order to earn additional equity, it
records its paying interest that incorporates the additional
contribution over its equity share.
Property, Plant and Equipment - Oil and gas properties
Capitalisation
Oil and gas properties are stated at cost, less any accumulated
depreciation and accumulated impairment losses. Oil and gas
properties are accumulated into single field cost centres and
represent the cost of developing the commercial reserves and
bringing them into production together with the E&E
expenditures incurred in finding commercial reserves previously
transferred from E&E assets as outlined in the policy above.
The cost will include, for qualifying assets, any applicable
borrowing costs.
Depletion
Oil and gas properties are not depleted until production
commences. Costs relating to each single field cost centre are
depleted on a unit of production method based on the commercial
proved and probable reserves for that cost centre. The depletion
calculation takes account of the estimated future costs of
development of management's assessment of proved and probable
reserves, reflecting risks applicable to the specific assets.
Changes in reserve quantities and cost estimates are recognised
prospectively from the last reporting date. Proved and probable
reserves estimates obtained from an independent reserves specialist
have been used as the basis for 2019 and 2020 calculations.
Impairment
A review is performed for any indication that the value of the
Group's development and production assets may be impaired.
For oil and gas properties when there are such indications, an
impairment test is carried out on the cash generating unit. Each
cash generating unit is identified in accordance with IAS 36.
Serica's cash generating units are those assets which generate
largely independent cash flows and are normally, but not always,
single development or production areas. If necessary, impairment is
charged through the income statement if the capitalised costs of
the cash generating unit exceed the recoverable amount of the
related commercial oil and gas reserves.
Acquisitions, Asset Purchases and Disposals
Acquisitions of oil and gas properties are accounted for under
the acquisition method when the assets acquired and liabilities
assumed constitute a business.
Transactions involving the purchase of an individual field
interest, or a group of field interests, that do not constitute a
business, are treated as asset purchases. Accordingly, no goodwill
and no deferred tax gross up arises, and the consideration is
allocated to the assets and liabilities purchased on an appropriate
basis. Proceeds from the entire disposal of a development and
production asset, or any part thereof, are taken to the income
statement together with the requisite proportional net book value
of the asset, or part thereof, being sold.
Decommissioning
Liabilities for decommissioning costs are recognised when the
Group has an obligation to dismantle and remove a production,
transportation or processing facility and to restore the site on
which it is located. Liabilities may arise upon construction of
such facilities, upon acquisition or through a subsequent change in
legislation or regulations. The amount recognised is the estimated
present value of future expenditure determined in accordance with
local conditions and requirements. A corresponding tangible item of
property, plant and equipment equivalent to the provision is also
created.
Any changes in the present value of the estimated expenditure is
added to or deducted from the cost of the assets to which it
relates. The adjusted depreciable amount of the asset is then
depreciated prospectively over its remaining useful life. The
unwinding of the discount on the decommissioning provision is
included as a finance cost.
Underlift/Overlift
Lifting arrangements for oil and gas produced in certain fields
are such that each participant may not receive its share of the
overall production in each period. The difference between
cumulative entitlement and cumulative production less stock is
'underlift' or 'overlift'. Underlift and overlift are valued at
market value and included within debtors ('underlift') or creditors
('overlift').
Property, Plant and Equipment - Other
Computer equipment and fixtures, fittings and equipment are
recorded at cost as tangible assets. The straight-line method of
depreciation is used to depreciate the cost of these assets over
their estimated useful lives. Computer equipment is depreciated
over three years and fixtures, fittings and equipment over four
years, and right-of-use assets over the period of lease.
Inventories
Inventories are valued at the lower of cost and net realisable
value. Cost is determined by the first-in first-out method and
comprises direct purchase costs and transportation expenses.
Investments
In its separate financial statements the Company recognises its
investments in subsidiaries at cost less any provision for
impairment.
Financial Instruments
Financial instruments comprise financial assets, cash and cash
equivalents, financial liabilities and equity instruments.
Financial assets and financial liabilities are recognised when the
Group becomes a party to the contractual provisions of the
financial instrument.
Financial assets
Financial assets are classified, at initial recognition, as
subsequently measured at amortised cost, fair value through profit
or loss, and fair value through other comprehensive income
(OCI).
The classification of financial assets at initial recognition
depends on the financial asset's contractual cash flow
characteristics and the Group's business model for managing
them.
With the exception of trade receivables that do not contain a
significant financing component or for which the Group has applied
the practical expedient, the Group initially measures a financial
asset at its fair value plus transaction costs (in the case of a
financial asset not at fair value through profit or loss). Trade
receivables that do not contain a significant financing component
or for which the Group has applied the practical expedient are
measured at the transaction price determined under IFRS 15.
The Group determines the classification of its financial assets
at initial recognition and, where allowed and appropriate,
re-evaluates this designation at each financial year end.
Financial assets at fair value through profit or loss include
financial assets held for trading and derivatives. Financial assets
are classified as held for trading if they are acquired for the
purpose of selling in the near term.
In order for a financial asset to be classified and measured at
amortised cost it needs to give rise to cash flows that are 'solely
payments of principal and interest (SPPI)' on the principal amount
outstanding. This assessment is referred to as the SPPI test and is
performed at an instrument level. Financial assets with cash flows
that are not SPPI are classified and measured at fair value through
profit or loss, irrespective of the business model.
Cash and cash equivalents
Cash and cash equivalents include balances with banks and
short-term investments with original maturities of three months or
less at the date acquired.
Financial liabilities
Financial liabilities are classified, at initial recognition, as
financial liabilities at fair value through profit or loss, loans
and borrowings, payables, or as derivatives designated as hedging
instruments in an effective hedge, as appropriate. The Group's
financial liabilities currently include trade and other payables.
All financial liabilities are recognised initially at fair value.
Obligations for loans and borrowings are recognised when the Group
becomes party to the related contracts and are measured initially
at the fair value of consideration received less directly
attributable transaction costs.
After initial recognition, interest-bearing loans and borrowings
are subsequently measured at amortised cost using the effective
interest method.
Gains and losses are recognised in the income statement when the
liabilities are derecognised as well as through the amortisation
process.
Derivative financial instruments
The Group uses derivative financial instruments, such as forward
commodity contracts, to hedge its commodity price risks. The Group
has elected not to apply hedge accounting to these derivatives.
Such derivative financial instruments are initially recognised at
fair value on the date on which a derivative contract is entered
into and are subsequently remeasured at fair value. Derivatives are
carried as financial assets when the fair value is positive and as
financial liabilities when the fair value is negative. Any gains or
losses arising from changes in the fair value of derivatives are
taken directly to the statement of profit or loss and other
comprehensive income and presented within operating profit.
Further details of the fair values of derivative financial
instruments and how they are measured are provided in Note 19.
Equity
Equity instruments issued by the Company are recorded in equity
at the proceeds received, net of direct issue costs.
Trade and other receivables and contract assets
Trade receivables and contract assets
A receivable represents the Group ' s right to an amount of
consideration that is unconditional (i.e., only the passage of time
is required before payment of the consideration is due). A contract
asset is the right to consideration in exchange for goods or
services transferred to the customer.
Provision for expected credit losses of trade receivables and
contract assets
For trade receivables and contract assets, the Group applies a
simplified approach in calculating expected credit losses 'ECLs'.
Therefore, the Group does not track changes in credit risk, but
instead, recognises a loss allowance based on lifetime ECLs at each
reporting date. The Group has established a provision matrix that
is based on its historical credit loss experience, adjusted for
forward-looking factors specific to the debtors and the economic
environment. A financial asset is written off when there is no
reasonable expectation of recovering the contractual cash flows.
The Group's receivables have a good credit rating and there has
been no noted change in the credit risk of receivables in the
year.
Provisions
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.
The Group's estimate in respect of contingent consideration that
may be payable following the acquisition of its interest in the
Erskine field, is capitalised as an asset acquisition cost. The
value of the provision is determined by the amounts and nature of
operating costs incurred over a contractual period.
Revenue from contracts with customers
Revenue from contracts with customers is recognised when control
of the goods or services are transferred to the customer at an
amount that reflects the consideration to which the Group expects
to be entitled to in exchange for those goods or services. Revenue
is measured at the fair value of the consideration received or
receivable and represents amounts receivable for goods provided in
the normal course of business, net of discounts, customs duties and
sales taxes. The Group has concluded that it is the principal in
its revenue arrangements because it typically controls the goods or
services before transferring them to the customer.
The sale of crude oil, gas or condensate represents a single
performance obligation, being the sale of barrels equivalent on
collection of a cargo or on delivery of commodity into an
infrastructure. Revenue is accordingly recognised for this
performance obligation when control over the corresponding
commodity is transferred to the customer. The normal credit term is
15 to 45 days upon collection or delivery.
Finance Revenue
Finance revenue chiefly comprises interest income from cash
deposits on the basis of the effective interest rate method and is
disclosed separately on the face of the income statement.
Finance Costs
Finance costs of debt are allocated to periods over the term of
the related debt using the effective interest method. Arrangement
fees and issue costs are amortised and charged to the income
statement as finance costs over the term of the debt.
Share-Based Payment Transactions
Employees (including Executive 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').
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. 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 Serica Energy plc
('market conditions'), if applicable.
The cost of equity-settled transactions is recognised, together
with a corresponding increase in equity, 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 income statement 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. For
equity awards cancelled by forfeiture when vesting conditions are
not met, any expense previously recognised is reversed and
recognised as a credit in the income statement. Equity awards
cancelled are treated as vesting immediately on the date of
cancellation, and any expense not recognised for the award at that
date is recognised in the income statement. Estimated associated
national insurance charges are expensed in the income statement on
an accruals basis.
Where the terms of an equity-settled award are modified or a new
award is designated as replacing a cancelled or settled award, the
cost based on the original award terms continues to be recognised
over the original vesting period. In addition, an expense is
recognised over the remainder of the new vesting period for the
incremental fair value of any modification, based on the difference
between the fair value of the original award and the fair value of
the modified award, both as measured on the date of the
modification. No reduction is recognised if this difference is
negative.
Income Taxes
Current tax, including UK corporation tax and overseas
corporation tax, is provided at amounts expected to be paid using
the tax rates and laws that have been enacted or substantively
enacted by the balance sheet date.
Deferred tax is provided using the liability method and tax
rates and laws that have been enacted or substantively enacted at
the balance sheet date. Provision is made for temporary differences
at the balance sheet date between the tax bases of the assets and
liabilities and their carrying amounts for financial reporting
purposes. Deferred tax is provided on all temporary differences
except for:
-- temporary differences associated with investments in
subsidiaries, where the timing of the reversal of the temporary
differences can be controlled by the Group and it is probable that
the temporary differences will not reverse in the foreseeable
future; and
-- temporary differences arising from the initial recognition of
an asset or liability in a transaction that is not a business
combination and, at the time of the transaction, affects neither
the income statement nor taxable profit or loss.
Deferred tax assets are recognised for all deductible temporary
differences, to the extent that it is probable that taxable profits
will be available against which the deductible temporary
differences can be utilised. Deferred tax assets and liabilities
are presented net only if there is a legally enforceable right to
set off current tax assets against current tax liabilities and if
the deferred tax assets and liabilities relate to income taxes
levied by the same taxation authority.
Earnings Per Share
Earnings per share is calculated using the weighted average
number of ordinary shares outstanding during the period. Diluted
earnings per share is calculated based on the weighted average
number of ordinary shares outstanding during the period plus the
weighted average number of shares that would be issued on the
conversion of all relevant potentially dilutive shares to ordinary
shares. It is assumed that any proceeds obtained on the exercise of
any options and warrants would be used to purchase ordinary shares
at the average price during the period. Where the impact of
converted shares would be anti-dilutive, these are excluded from
the calculation of diluted earnings.
Leases
In applying IFRS 16 for the first time the Group applied the
short-term lease practical expedient by not recognising lease
liabilities in respect to lease arrangements with a remaining lease
term of less than 12 months as at 1 January 2019. The Group adopted
the modified retrospective approach to adoption on 1 January 2019,
measuring right-of use assets at an amount based on their
respective lease liability on adoption, with the cumulative effect
of adopting the standard recognised at the date of initial
application without restatement of comparative information.
As a lessee, the Group recognises a right-of-use asset and a
lease liability at the lease commencement date. The lease liability
is initially measured at the present value of the lease payments
that are not paid at the commencement date, discounted by using the
rate implicit in the lease, or, if that rate cannot be readily
determined, the Group uses its incremental borrowing rate.
The lease liability is subsequently recorded at amortised cost,
using the effective interest rate method. The liability is
remeasured when there is a change in future lease payments arising
from a change in an index or rate or if the Group changes its
assessment of whether it will exercise a purchase, extension or
termination option. When the lease liability is remeasured in this
way, a corresponding adjustment is made to the carrying amount of
the right-of-use asset or is recorded in profit or loss if the
carrying amount of the right-of-use asset has been reduced to
zero.
The right-of-use asset is measured at cost, which comprises the
initial amount of the lease liability adjusted for any lease
payments made at or before the commencement date, plus any initial
direct costs incurred and an estimate of costs to dismantle and
remove the underlying asset or to restore the underlying asset or
the site on which it is located, less any lease incentives
received. Right-of-use assets are depreciated over the shorter
period of lease term and useful life of the underlying asset.
The Group does not currently act as a lessor.
New and amended standards and interpretations
The Group has adopted and applied for the first time, certain
standards and amendments, which are effective for annual periods
beginning on or after 1 January 2020. The Group has not early
adopted any other standard, interpretation or amendment that has
been issued but is not yet effective. The nature and effect of the
changes that result from the adoption of these new standards are
described below. Other than the changes described below, the
accounting policies adopted are consistent with those of the
previous financial year.
Several other amendments and interpretations apply for the first
time in 2020, but do not have an impact on the consolidated
financial statements of the Group. The Group has not early adopted
any standards, interpretations or amendments that have been issued
but are not yet effective.
Amendments to IFRS 3: Definition of a Business
The amendment to IFRS 3 Business Combinations clarifies that to
be considered a business, an integrated set of activities and
assets must include, at a minimum, an input and a substantive
process that, together, significantly contribute to the ability to
create output. Furthermore, it clarifies that a business can exist
without including all of the inputs and processes needed to create
outputs. These amendments had no impact on the consolidated
financial statements of the Group, but may impact future periods
should the Group enter into any additional business
combinations.
Amendments to IFRS 7, IFRS 9 and IAS 39 Interest Rate Benchmark
Reform
The amendments to IFRS 9 and IAS 39 Financial Instruments:
Recognition and Measurement provide a number of reliefs, which
apply to all hedging relationships that are directly affected by
interest rate benchmark reform. A hedging relationship is affected
if the reform gives rise to uncertainty about the timing and/or
amount of benchmark-based cash flows of the hedged item or the
hedging instrument. These amendments have no impact on the
consolidated financial statements of the Group.
Amendments to IAS 1 and IAS 8 Definition of Material
The amendments provide a new definition of material that states,
"information is material if omitting, misstating or obscuring it
could reasonably be expected to influence decisions that the
primary users of general purpose financial statements make on the
basis of those financial statements, which provide financial
information about a specific reporting entity." The amendments
clarify that materiality will depend on the nature or magnitude of
information, either individually or in combination with other
information, in the context of the financial statements. A
misstatement of information is material if it could reasonably be
expected to influence decisions made by the primary users. These
amendments had no impact on the consolidated financial statements
of, nor is there expected to be any future impact to the Group.
Conceptual Framework for Financial Reporting issued on 29 March
2018
The Conceptual Framework is not a standard, and none of the
concepts contained therein override the concepts or requirements in
any standard. The purpose of the Conceptual Framework is to assist
the IASB in developing standards, to help preparers develop
consistent accounting policies where there is no applicable
standard in place and to assist all parties to understand and
interpret the standards. This will affect those entities which
developed their accounting policies based on the Conceptual
Framework. The revised Conceptual Framework includes some new
concepts, updated definitions and recognition criteria for assets
and liabilities and clarifies some important concepts. These
amendments had no impact on the consolidated financial statements
of the Group.
Standards issued but not yet effective
Certain standards or interpretations issued but not yet
effective up to the date of issuance of the Group's financial
statements are listed below. This listing of standards and
interpretations issued are those that the Group reasonably expects
to have an impact on disclosures, financial position or performance
when applied at a future date. The Group is currently assessing the
impact of these standards and intends to adopt them when they
become effective. In reviewing the below standards, the Group does
not believe that there will be a material impact on the financial
statements.
Amendments to IAS 1: Classification of Liabilities as Current or
Non-current
The amendments are effective for annual reporting periods
beginning on or after 1 January 2023 and must be applied
retrospectively. The Group is currently assessing the impact the
amendments will have on current practice.
Reference to the Conceptual Framework - Amendments to IFRS 3
The amendments are effective for annual reporting periods
beginning on or after 1 January 2022 and apply prospectively.
Property, Plant and Equipment: Proceeds before Intended Use -
Amendments to IAS 16
The amendment is effective for annual reporting periods
beginning on or after 1 January 2022 and must be applied
retrospectively to items of property, plant and equipment made
available for use on or after the beginning of the earliest period
presented when the entity first applies the amendment.
GLOSSARY
bbl barrel of 42 US gallons
bcf billion standard cubic feet
boe barrels of oil equivalent (barrels of oil, condensate and LPG plus the heating equivalent
of gas converted into barrels at the appropriate rate)
BKR Bruce, Keith and Rhum fields
BPEOC BP Exploration Operating Company
CGU Cash generating unit
CPR Competent Persons Report
ESG Environmental, Social and Governance
FDP Field Development Plan
FPS Forties Pipeline System
GRI Global Reporting Index (framework for sustainability reporting)
HPHT High pressure high temperature
mscf thousand standard cubic feet
mmbbl million barrels
mmboe million barrels of oil equivalent
mmscf million standard cubic feet
mmscfd million standard cubic feet per day
NGLs Natural gas liquids extracted from gas streams
NTS National Transmission System
OGA Oil and Gas Authority
Overlift Volumes of oil or NGLs sold in excess of volumes produced
Underlift Volumes of oil or NGLs produced but not yet sold
P10 A high estimate that there should be at least a 10% probability that the quantities recovered
will actually equal or exceed the estimate
P50 A best estimate that there should be at least a 50% probability that the quantities recovered
will actually equal or exceed the estimate
P90 A low estimate that there should be at least a 90% probability that the quantities recovered
will actually equal or exceed the estimate
Pigging A process of pipeline cleaning and maintenance which involves the use of devices called pigs
Proved Reserves Proved reserves are those Reserves that can be estimated with a high degree of certainty to
be recoverable. It is likely that the actual remaining quantities recovered will exceed the
estimated proved reserves
Probable Reserves Probable reserves are those additional Reserves that are less certain to be recovered than
proved reserves. It is equally likely that the actual remaining quantities recovered will
be greater or less than the sum of the estimated proved + probable reserves
Possible Reserves Possible reserves are those additional Reserves that are less certain to be recovered than
probable reserves. It is unlikely that the actual remaining quantities recovered will exceed
the sum of the estimated proved + probable + possible reserves
Reserves Estimates of discovered recoverable commercial hydrocarbon reserves calculated in accordance
with the revised June 2018 Petroleum Resources Management System (PRMS) version 1.01
SASB Sustainability accounting standards board
Tcf trillion standard cubic feet
TCFD Taskforce on Climate-related Financial Disclosures
UKCS United Kingdom Continental Shelf
UNSDG United Nations Sustainable Development Goals
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FR IIMRTMTABBTB
(END) Dow Jones Newswires
April 15, 2021 02:00 ET (06:00 GMT)
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