REG - Serica Energy PLC - 2025 full-year results
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RNS Number : 2457Y Serica Energy PLC 26 March 2026
Serica Energy plc
('Serica' or 'the Company')
Results for the year ended 31 December 2025
London, 26 March 2026 - Serica Energy plc (AIM: SQZ), a leading 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
2025. The results are included below and copies are available at
www.serica-energy.com (http://www.serica-energy.com) and www.sedar.com
(http://www.sedar.com) .
Chris Cox, Serica's CEO, stated:
"Serica delivered positive strategic progress in 2025, significantly
strengthening our portfolio and organisation, and positioning the Company for
materially increased production and the delivery of future growth. Successful
acquisitions mean that Serica will have an increasingly resilient and
diversified portfolio, with production set to reach over 65,000 boepd by the
end of 2026 as they all complete. Our production is generating material cash
flows, enhanced further at current commodity prices, boosting our liquidity
position and supporting our ability to allocate capital to both attractive
growth opportunities and shareholder returns. Our disciplined capital
allocation is focused on the short‑cycle, low‑risk opportunities in our
portfolio.
Following our newly completed transaction with TotalEnergies we also operate
strategic West of Shetland gas processing infrastructure serving one of the
UKCS' most prospective hydrocarbon regions at a time when the importance of
domestic gas supply is so starkly in focus. 2026 will be a year of further
delivery on our strategy as we high‑grade and progress our organic growth
opportunities, and deliver stronger, more reliable performance across a
diversified asset base. Serica is better placed than ever to create
sustainable value for shareholders and be an important contributor to the UK's
energy security."
Results summary ($ million unless stated)
2025 2024
Average realised Brent oil price ($/bbl) 67 75
Average realised gas price (pence per therm) 84 76
Production (boepd) 27,600 34,600
Revenue 601 727
Operating costs 366 330
EBITDAX 210 379
Cash Tax paid 9 153
Adjusted CFFO less tax 187 403
Capital expenditure 250 278
Free cash flow (24) (1)
Cash and restricted cash 31 148
Total debt 231 231
Net (debt) / cash (200) (83)
Final dividend declared (pence per share) 10 10
Dividends paid 85 113
Highlights
Production set to rise materially over the course of 2026
· Production of 27,600 boepd in 2025 (2024: 34,600 boepd), impacted by
unscheduled downtime at the Triton FPSO
· Production year to date of 38,600 boepd, following a production
interruption for further maintenance work at the Triton FPSO
- Production has averaged over 50,000 boepd since resumption from
Triton on 9 March
· Production from Serica's portfolio has the potential to exceed rates
of 65,000 boepd by the end of 2026, once all acquisitions announced in 2025
have been completed
Successful M&A delivering increased production, cashflows, and growth
opportunities
· Announced four cash-generative acquisitions through 2025 at an
attractive combined valuation of $3.3/boe per 2P boe of reserves
· Acquisition of 40% of the Greater Laggan Area ('GLA'), West of
Shetland, from TotalEnergies has now completed, with a net completion payment
of $56 million received by Serica
- The acquisition adds production of just over 5,000 boepd from GLA
net to Serica, as well as additional potential growth opportunities with the
Glendronach tie-back and Tormore infills, while the strategic Shetland Gas
Plant offers material value creation potential from owned and third-party
business
· The number of producing fields in the Serica portfolio is set to
more than double once all acquisitions complete, significantly increasing the
diversification, reliability and predictability of future production and
revenues
Material increase in reserves and resources following completion of
acquisitions
· 2P reserves of 116.8 mmboe as at end-2025 (end-2024: 118 mmboe),
broadly evenly split between oil (58.9 mmboe) and gas (57.9 mmboe), following
2025 production of 10.4 mmboe
- Pro forma for the completion of acquisitions announced in 2025, 2P
reserves increase 19% to 138.5 mmboe, of which 54% is gas
· Acquisitions are gas weighted and add longer-life producing
fields to the portfolio
· 2C resources increased 16% to 103.4 mmboe as at end-2025
(end-2024: 89 mmboe), driven by additional infill well opportunities at Bruce
and the farm-in to the Wagtail licence
- Pro forma 2C resources of 112.6 mmboe, boosted by the inclusion of a
40% stake in Glendronach, as the Company grows its organic hopper materially
through M&A
Organic growth options have the potential to sustain and grow production well
into the next decade
· Market screening for a rig is currently underway with a view to
drilling a programme of new wells targeting infills and tie-backs in the
broader Serica portfolio, potentially to commence with infill drilling at the
Bruce field in 2027. Low-risk new wells have the potential to add materially
to production, with very short payback and highly attractive returns
Balance sheet strength and efficient tax position supports investment in
growth and returns
· Cash and restricted cash of $31 million (31 December 2024: $148
million) as at 31 December 2025
- Total liquidity of $290 million, comprising cash, restricted cash
and undrawn committed RBL facility availability as at 31 December 2025 of $259
million
- Borrowings of $231 million (31 December 2024: $231 million),
resulting in a net debt position of $200 million as at 31 December 2025
- Net debt position to more than halve in Q1, following receipt of $56
million from TotalEnergies
· Group tax assets more than doubled in 2025, with a notional value
of over $1 billion
· Loss after taxation for 2025 of $52 million, following previously
announced non-cash deferred tax charge of $65 million taken in Q1 2025 as a
result of the extension of EPL to 2030
· Final dividend declared today of 10 pence per share (2024: 10
pence per share) subject to approval at Serica's 2026 AGM
- The final dividend is payable on 24 July 2026 to shareholders
registered on 26 June 2026, with an ex-dividend date of 25 June 2026
Outlook and guidance - significant uplift in production forecast
· Unchanged guidance for 2026 production of significantly over 40,000
boepd
· Capital expenditure guidance of $175-195 million and opex guidance of
$380-400 million unchanged
· Material free cash flow was forecast to be generated in 2026 even at
an oil price of $63/bbl and gas price of 69p/therm, with cash generation
significantly higher at current commodity prices
- Serica has been proactively and opportunistically building its hedge
book mostly since early March, taking advantage of sharp increases in the
front end of the curve in both oil and gas while bolstering downside
protection
· Completion processes for Catcher, Golden Eagle Area Development and
Spirit Energy assets are on track and due to complete through the course of
2026
· The Company continues to be active, but highly selective, in
screening a broad range of cash-generative and value accretive M&A
opportunities, in both the UK North Sea and overseas
· Serica remains committed to moving from AIM to the Main Market of the
LSE at the earliest viable opportunity in 2026, which is now expected to be
during Q3
Regulatory
This announcement contains inside information for the purposes of Article 7 of
the Market Abuse Regulation (EU) 596/2014 as it forms part of UK domestic law
by virtue of the European Union (Withdrawal) Act 2018 ('MAR'), and is
disclosed in accordance with the company's obligations under Article 17 of
MAR.
The technical information contained in the announcement has been reviewed and
approved by Carla Riddell, Chief Technical Officer at Serica Energy plc. Ms.
Riddell (B.Sc. Geology from University of Durham University, M.Sc. Palynology
from University of Sheffield) has over 25 years of experience in oil & gas
exploration, development and production and is a Fellow of the Geological
Society of London and Energy Institute.
Enquiries:
Serica Energy plc +44 (0)20 7487 7300
Martin Copeland (CFO) / Andrew Benbow (Head of Investor Relations)
Peel Hunt (Nomad & Joint Broker) +44 (0)20 7418 8900
Richard Crichton / David McKeown / Emily Bhasin
Jefferies (Joint Broker) +44 (0)20 7029 8000
Sam Barnett / Cameron Jones
Vigo Consulting (PR Advisor) +44 (0)20 7390 0230
Patrick d'Ancona serica@vigoconsulting.com
Serica will host a live presentation on the Investor Meet Company platform
today at 1000 GMT. The presentation is open to all existing and potential
shareholders. Questions can be submitted at any time during the live
presentation. Investors can sign up to Investor Meet Company for free and add
to meet Serica Energy plc via:
https://www.investormeetcompany.com/serica-energy-plc/register-investor
(https://www.investormeetcompany.com/serica-energy-plc/register-investor) .
Serica will host a Capital Markets Day in Q2, at which further details will be
given on our exciting organic growth projects and on the medium-term capital
allocation framework.
CHAIR'S STATEMENT
I am pleased to introduce my third set of results as the Chair of Serica
Energy, marking a year of positive strategic progress for the Company. These
results are being published in the midst of significant volatility in the
global oil and gas markets caused by the conflict in the Middle East. Serica
has consistently argued for the importance of domestic energy, including
vitally needed oil and gas, for a variety of reasons. The potential risks to
supply reinforce this argument. Serica's role in producing UK oil and gas has
expanded greatly over the last several years and, as described elsewhere in
this report, the Company is pursuing options to do more.
The acquisitions we announced during the year will significantly enhance
Serica going forward, adding materially to reserves, production, and cashflow,
and reducing the reliance on two major producing hubs. The importance of such
diversification was illustrated in 2025, as ongoing issues at the Triton FPSO
again had a detrimental impact on the Company's production and results.
Despite these issues, which represented a deferral of production and cash
generation, I am confident that our strategic actions in 2025 have positioned
Serica well to continue delivering for shareholders. In this light, as well as
in the improved market context in which we find ourselves today, we are
pleased to be able to maintain our proposed 10p final dividend for approval at
our AGM.
Enhanced team, consistent focus
As the Company grows, our strategy and focus remain consistent.
Serica is set to become a significantly larger company as our acquisitions
complete, and oversight is provided by a stable Board and a management team of
real quality. The additions to the Executive Leadership Team and other
positions during 2026 result in a team with the experience and expertise to
take the Company safely and successfully to the next level.
Our strategy for growth through both M&A and targeted investment
continues, with the opportunity to build on the strengthened platform achieved
in 2025.
A more robust company, well positioned to deliver
Serica's strategy is based on applying our expertise to mid-to-late life
assets, optimising production, and unlocking subsurface opportunities to
extend field life and deliver value for shareholders. This is a two-pronged
strategy, with value delivered by M&A through the acquisition of both new
production assets and further organic opportunities, and enhanced by
operational and subsurface expertise.
In 2025 we identified and executed multiple opportunities to carry out value
accretive deals in the UK North Sea. The completed acquisition of Prax
Upstream, and the associated deals which along with the acquisition of assets
from Spirit Energy are set to complete in 2026, boosts our pro forma reserves
by almost 20% and materially increases production. It also adds to our
opportunity set, with an attractive number of investment opportunities now
vying for capital allocation.
An area of our expanded portfolio that has tremendous potential is the
operated West of Shetland hub, which combines sub-surface potential in the
most prospective basin on the UK Continental Shelf, and will add
infrastructure opportunities via the Shetland Gas Plant. This is personally
pleasing, having worked in the basin extensively earlier in my career, going
right back to the development of the Foinaven field.
At a time when it is becoming ever clearer how critical energy security is and
that the UK requires all the homegrown hydrocarbons and especially gas that it
can produce, we look forward to playing our part in maximising throughput in
the Shetland Gas Plant, which - coming up to its 10 Year anniversary this year
- represents a modern, strategically important, onshore landing point for gas
entering the UK supply network.
Actions needed to kick-start the UK North Sea
In my statement last year, I reported that common sense UK Government policies
for the North Sea would prioritise domestic production over imports.
Regrettably, the merits of such an approach are being reinforced by the
interruption to oil and gas supplies from the Middle East. Our thoughts are
with all those affected by the situation.
I also wrote last year that confidence in the UK North Sea sector had been
eroded. Since then, the Government has continued to solicit opinions and
information through formal consultations and dialogue, which has been welcome,
but this has not yet translated into actions which would support a world class
and valuable industry. I take this opportunity, therefore, to repeat our
request for a change in approach, to which end I offer a four-point plan.
Firstly, demonstrate a willingness to approve the development of new oil and
gas fields. There are project approval decisions which could be made now and
others to come over the next several months which would reduce the risks to
the UK of future oil and gas crises and could even help with the current
crisis if it is prolonged.
Secondly, revisit the decision not to award new exploration licences. There is
significant untapped oil and gas potential on the UK Continental Shelf and
companies like Serica are willing and able to take the financial risks of
exploration. We do not ask for subsidies to undertake these activities. We
only ask for the ability to do so at our own financial risk.
Thirdly, as soon as reasonably possible, replace the Energy Profits Levy with
a permanent, properly designed mechanism for raising the level of tax on UK
oil and gas production during periods of true 'windfall' prices. Much
collaborative work by officials and the industry has already gone into the
design of just such a tax in the form of the Oil and Gas Price Mechanism
('OGPM') intended to replace the EPL. Implementing this change would still see
the Exchequer share fairly in windfalls caused by price shocks, but would be a
huge step towards rebuilding confidence in the sector.
Finally, talk about the UK North Sea sector as a national asset; a
longstanding source of economic value, world-class skills and immense pride
amongst the people and communities involved. Too often in reports and
ministerial statements, the sector is referred to in terms which imply
irrelevance despite it being the single largest source of energy in the UK, or
being less desirable than other sectors even though it supports some 200,000
jobs, many of which are highly skilled. The people working in the sector, or
dependent on it across the country, deserve better. Moreover, a sector talked
up rather than down will deliver more, benefiting the country as a whole.
Maximising the benefits available to the UK from domestic oil and gas and
achieving net zero by 2050 are not mutually exclusive objectives. Indeed, they
complement each other, not least when oil and gas imported over thousands of
miles typically comes with significantly higher emissions than the equivalent
domestic production.
These facts are understood and are being acted upon by other oil and gas
producing countries in western Europe. Amongst those countries, the UK holds
the second largest resource of oil and gas. For the benefit of ourselves and
regional security, we should exploit to the full that position of good fortune
and much skill.
Consistent strategy delivering value for shareholders
As stated, our strategy remains unchanged. We are high-grading and maturing
the increasing number of potential organic growth investments in our
portfolio. Following the exceptional subsurface results of the five-well
Triton drilling campaign completed in 2025, we are turning our attention to
the Bruce and newly acquired West of Shetland hubs. More information on these
will be provided at our Capital Markets Day in Q2.
At the same time, we are actively pursuing further opportunities to grow the
Company, from transformational deals to smaller bolt-on acquisitions. We
retain the belief that attractive acquisition opportunities will arise in the
UK North Sea. As ever, however, our aim is the creation of shareholder value
rather than size for the sake of it. Accordingly, while overseas entry has not
been our focus during 2025, we continue to monitor potential openings. As we
go forward, we will balance our capital allocation between acquisitions,
organic growth, and direct shareholder returns - based on creating optimal
value for shareholders. We are confident in our ability to continue delivering
on this strategy.
After some 20 years on the AIM market, we also look forward to taking the
natural next step in the Company's growth in moving to the Main Market of the
London Stock Exchange later this year. This would have been completed in 2025,
but rightfully M&A took priority. We believe that completing the move this
year will add to Serica's visibility, taking our story to the widest audience
possible.
----------------------
CHIEF EXECUTIVE OFFICER'S REVIEW
Serica delivered a year of meaningful operational and strategic progress in
2025, adding assets that will diversify and enhance the Company, and
underpinning our future success by strengthening organisational capability and
renewing our commitment to optimising production. The foundations we laid over
the past year position us well as we move into 2026.
Building capability to deliver on the opportunities ahead
We are confident in our strategy, and confident that we have the right team to
deliver it. When I joined there were certain gaps in the organisation that
needed to be filled, and we have strengthened Serica's organisational
capability to ensure we have people in place to support the Company's next
phase of growth, while retaining our entrepreneurial culture. It was evident
that the business required additional depth in several critical areas. Since
then, we have made a number of targeted senior appointments across all areas
that have materially improved our decision‑making, our talent management,
and our ability to deliver for shareholders.
Serica is already seeing the benefits of an intensive effort on being set up
to capitalise on M&A, and the team did a tremendous job in getting
multiple acquisitions over the line last year. Across the business we are
seeing improvements. The addition of a Chief People Officer has significantly
improved how we manage and develop our people, and will be crucial as we
integrate new personnel into the Company in 2026. Our Chief Technical Officer
brings essential technical challenge and strategic insight into our portfolio
planning, and with a new Head of Developments we have clear ownership and
expertise when it comes to project prioritisation, transforming how we
evaluate opportunities and how we deploy capital.
We have also formed a new group focused on our non-operated joint ventures,
the most important of which is Triton, with Executive Leadership Team
representation, recognising the increasing importance of this part of the
business for us and the different skillsets and focus priorities needed to
optimise value from non-operated assets. The business is growing, and our
capability is growing with it and equipping us for further growth to come.
In operations, we have brought in new Offshore Installation Managers and
additional technical capability to address gaps, strengthening our operational
leadership and enhancing our production optimisation capability.
The result is a leadership team that is strategically aligned and better
equipped to manage the scale and complexity of our enlarged asset base. The
progress made in 2025 would not have been possible without these changes, and
this team provides a strong platform for the delivery of improved performance
in 2026 and beyond.
Increasing reliability
A key area for us to tackle remains improving our operating performance, and I
remain convinced that we can and will do better. We are working with the
operator at Triton while at the Bruce Hub, asset uptime remains impressive,
but more can be done to optimise production performance. We have shifted the
organisation's mindset to focus more on operational excellence and chasing all
avenues for increased production, investing when necessary - as improved
operating practice not only means safer production, but also adding barrels in
this way can easily deliver greater value than from more material capital
allocation spend.
High performance cannot be delivered without appropriate resources, and the
team has done some great work at the Bruce platform on reducing the
maintenance backlog, improving and replacing key equipment and reducing single
point failure risk - all steps necessary to allow us to operate the asset well
into the next decade. That is what we believe the rocks around Bruce can
deliver, as we move towards the next stage of Bruce's evolution - and a
material increase in production. We are confident that our planned drilling
campaign on Bruce (the first since 2012) will illustrate this potential,
growing production and extending the life of field potentially until the end
of the next decade. Work being done during 2026 will set us up for reliable
long‑term performance as well as materially improving our emissions to
ensure we maintain the necessary licence to operate.
A key theme across our operations is the exposure to single point failure in
certain key systems, especially those that involve rotating equipment. It is
impossible to avoid such exposure entirely, but we are making strenuous
efforts - directly on our operated assets and indirectly on our non-operated
assets - to reduce this risk. These efforts include parallel systems where
feasible and financially justified, maintenance and predictive analysis.
Of course, production performance never outweighs safety, which remains and
will always be our number one priority. In 2025 we significantly improved our
process‑safety performance. At the same time, we recognised the need to
re‑emphasise personal safety after an increase in thankfully minor eye and
hand injuries, with three minor lost time injuries in the year our first for
five years, and a reminder of the need for constant vigilance on all forms of
safety. We have responded with targeted personal equipment upgrades and a
renewed behavioural focus. Our safety goal for 2026 is simple and unchanged
from before: no harm to our people.
Positive subsurface performance ongoing
As with 2024, while our production performance was not satisfactory, our
subsurface team continued to deliver tremendous results, demonstrating the
strength of our underlying resource base and our human capital. The five-well
drilling campaign at Triton, delivered ahead of schedule and under budget, was
rounded off with successful wells at Evelyn and Belinda, although neither has
yet to deliver their potential due to the Triton FPSO operational issues. With
the full complement of wells in production, we are confident of maintaining
Triton area production capacity of above 20,000 boepd net to Serica through
2027 at least.
Hitherto, the fact that we have not yet seen the benefits of the subsurface
results is deeply frustrating and something we are working closely with the
operator, Dana Petroleum, to address. The impact to date, however, is deferred
production rather than lost production. The resource remains in place, and our
immediate task is to ensure that the infrastructure is capable of bringing it
to the surface. I said when I joined that it would be a two-year process to
get to good operational performance. Nearly twenty-one months in, progress has
been slower than I hoped. With the work that has been done on the FPSO since
that time, however, I am confident that improved performance and the value
that follows will come.
Improved operations at Triton and continued production optimisation at Bruce
means, factoring in also production from the acquisitions as they complete
during the year, we are well set to surpass production levels of 65,000 boepd
towards the end of the year.
New assets supporting predictability
Our strategy is to build a diversified asset base that reduces dependence on
any single asset. The consequent resilience and greater predictability of cash
flow makes Serica more attractive to investors. New assets are an important
component of that long‑term stability. Value from across our portfolio will
come from increasing reliability, delivery, and taking advantage of
opportunities ahead. Our new assets support all three.
Adding producing assets, with stable operations, provides greater confidence
in production and earnings. In this regard, I look forward to the addition to
our portfolio of fields with historically high-uptime and consistent delivery
- our stake in the Cygnus field, with the acquisition of the asset portfolio
from Spirit Energy set to complete around the start of Q4, being a good
example. Greater diversification is greater strength.
By their nature, E&P companies can never stand still, and Serica certainly
will not. Reserves replacement was delivered in 2025 through adding material
reserves and resources in acquisitions, and through progressing opportunities
in the portfolio, with 2P reserves up 19% year-on-year on a pro forma basis.
The resources from Kyle, now renamed Kyla, have matured to reserves, and that
is one of a multitude of opportunities in our hopper, with the opportunity set
available to us only increasing through new acquisitions in 2025.
Material growth potential in the portfolio
The acquisition of the West of Shetland assets from TotalEnergies is set to
add development opportunities at Glendronach and Tormore to our portfolio, and
the Spirit Energy transaction will bring infill drilling potential at Cygnus,
Clipper South, and GMA, to further bolster our subsurface opportunities. The
more I see the output of our subsurface team, the more excitement I have
regarding the opportunities available to us. The success of our drilling
results around Triton only increases my confidence in what can be achieved
when putting the same proven team of subsurface, wells and other functional
experts to work across our expanded asset base.
Our technical and financial high‑grading process continues to evaluate these
opportunities rigorously. We are focused on short‑cycle, low‑risk,
high‑return projects that enhance returns and strengthen production
stability. We will provide more details about this work at the Capital Markets
Day in Q2. There is material growth potential across the portfolio - and it is
a welcome, but new challenge for Serica to have more opportunities than we
have the financial and organisational capacity to deliver in parallel. With a
combination of near‑term infill wells and optimisation opportunities,
tiebacks, and long‑term development potential, we have a balanced
opportunity set that I am confident can deliver over a number of years.
The long‑term opportunity set in our newly acquired, operated hub in the
West of Shetland, offers great potential. The Shetland Gas Plant, which I was
pleased to visit earlier this month, provides access to a material inventory
of owned and third-party future gas developments.
The Shetland Gas Plant is the youngest onshore landing point for domestically
produced gas, and the key export route capable of handling the next wave of
gas developments in the region, positioning us at the heart of the UK's most
prospective basin for future gas production. We are actively progressing
commercial engagement with our partners in the area to ensure that the value
of this strategic position is realised. This benefits us, Shetland and -
through the supply of much needed gas - the UK as a whole.
M&A remains a central part of our two-pronged strategy. While we will
maintain our position as a North Sea‑focused business, we continue to assess
both domestic and selected international opportunities where the value case is
strong and aligned to our operational strengths and core business model.
Across all of these opportunities, our discipline remains the same: invest
where the returns justify the capital, prioritise short‑cycle value
creation, and ensure every project competes for funds. It is this discipline
that has strengthened our portfolio and will drive shareholder value in the
years ahead.
Delivering cash
2026 will be a pivotal year for Serica. The Company is set to generate
material free cash flow and build our liquidity position, and we will complete
the ranking of our organic opportunities and set out a clear, actionable plan
for the allocation of available capital, in order to deliver on our exciting
growth potential in coming years. Across our operations, the priority remains
on improving production reliability, and embedding the operating discipline
needed to sustain long‑term performance. Serica today is a more resilient
company than it was a year ago, and we are taking the right steps to ensure we
continue to grow and create value for our shareholders.
----------------------
REVIEW OF OPERATIONS
Reserves and resources
Serica's assets contained 116.8 mmboe of 2P oil and gas reserves net to the
Company as of 31 December 2025 (31 December 2024: 117.5 mmboe), with
production of 10.1 mmboe in 2025. The portfolio currently has a broadly even
split between oil (58.9 mmboe) and gas (57.9 mmboe).
As at 31 December 2025 (mmboe) 2P 2025 1 (#_ftn1) 2P 2025 2P 2024 2C 2025 2C 2025 pro forma 2C 2024
pro forma 2 (#_ftn2)
Bruce Hub 61.2 61.2 69.8 55.8 55.8 33.3
Triton Hub 49.9 49.9 41.8 18.5 18.5 16.4
West of Shetland 0.8 4.8 - - 5.4 -
Other Production Assets 4.9 8.1 5.9 0.1 0.4 9.0
Southern North Sea - 14.4 - - 3.4 -
Greater Buchan Area - - - 29.0 29.0 30.0
Total 116.8 138.4 117.5 103.4 112.6 88.7
( )
Reserves replacement was robust in 2025, supported by 10.2 mmboe being moved
into 2P reserves due to the maturation of the Kyla redevelopment. This
effectively offset the 10.1 mmboe of production in the year. Minor revisions
at the Bruce and Rhum fields also largely offset, and a small benefit is also
booked from the addition of Lancaster via the acquisition of Prax Upstream.
Our attractive opportunity set is reflected in our material 2C resource
position of 103.4 mmboe, up 16% from 88.7 mmboe as at the end of 2024. This
increase was driven by preliminary work on the Bruce drilling programme, as
additional infill well opportunities delivered an 18.2 mmboe increase in 2C
resources. This outweighed the relinquishment of the Mansell licence (8.3
mmboe), and transfer of Kyla (8.5 mmboe) from resources to reserves. The
addition of Wagtail through the farm-in to the UK North Sea P2530 Licence also
provided an uplift of 8.0 mmboe of 2C resources.
As the TotalEnergies, ONE-Dyas, and Spirit Energy acquisitions complete, our
reserves will see a significant uplift, with the acquired assets resulting in
a 19% uplift to 138.4 mmboe. The acquisitions will also result in the
portfolio being weighted slightly more towards gas, with 2P oil reserves of
63.2 mmboe and gas reserves of 75.3 mmboe meaning that 54% of portfolio
reserves are gas.
The acquisition of 40% in the Glendronach licence, West of Shetland, is the
key contributor to the increase in pro forma 2C resources.
Production net to Serica (boepd)
2025 2024
Bruce Hub 16,100 19,800
Triton Hub 5,900 9,000
Other Assets 5,300 5,800
West of Shetland 300 -
Total 27,600 34,600
Bruce Hub
Bruce - Blocks 9/8a, 9/9b and 9/9c, Serica 98% and operator
Rhum - Blocks 3/29a, Serica 50% and operator
Keith - Block 9/8a, Serica 100%
Production at the Bruce Hub averaged 16,100 boepd in 2025 (2024: 19,800 boepd)
net to Serica, below asset potential. Asset uptime over the year was robust,
although production was limited through work on the productive R3 well in
January, followed by maintenance work on the export pipeline, and the main oil
line ('MOL') booster pump being offline and reducing the ability to enhance
oil recovery through bull-heading operations (in which gas is pumped into a
well to reduce back pressure and enhance production).
Activity on Bruce in 2026 is focused on enhancing reliability and the ability
to deliver optimal well stock performance, leading to production increasing
from 2025 levels. Work will also take place to support the extension of asset
life that will allow the potentially material uplift in production volumes
from new drilling on the Bruce field to be delivered in the years to come. The
planned shutdown in Q3 is expected to last approximately 24 days.
There have been no wells drilled on the Bruce field since 2012. Following the
development of a full field model, numerous infill drilling locations were
identified. These have now been high-graded, with three opportunities
prioritised on the western side of the field, providing the best opportunity
for rapid tieback to the Bruce subsea and platform facilities. Market
screening for a rig is currently underway, to enable drilling to begin in
2027. Given the continued availability of attractive capital allowances
designed to support such investments, this investment would be highly
tax-efficient and has the potential to deliver a material uplift in production
from the Bruce field as well as to extend the life of the hub.
Triton Hub
Bittern 64.63%, Evelyn 100%, Gannet E 100%, Guillemot West & North West
10%, Belinda 100%
Production from the Triton Hub, operated by Dana Petroleum, averaged 5,900
boepd in 2025 (2024: 9,000 boepd) net to Serica, significantly below potential
due to necessary maintenance work that took place on the Triton FPSO
throughout the year.
From the end of January 2025 until July, extensive remediation work and
modifications were carried out, with subsequent issues relating to the
compression train and flare system resulting in significantly reduced
production in Q3. Following the completion of this work, production rebounded
strongly in November, averaging 25,300 boepd net to Serica prior to the
planned subsea work starting on the Bittern export pipeline, which was
completed as scheduled in mid-December.
After a solid start to 2026, production was shut in for a period of 24 days
for emergent essential maintenance. Production resumed on 9 March.
The focus in 2026 continues to be working with the operator to increase
reliability, optimising production through one compressor before potentially
moving to twin compressor operations following a period of stability.
The operator of the Triton FPSO forecasts that the planned shutdown in Q3 will
last for approximately 65 days.
Other Producing Assets
Erskine - Blocks 23/26a (Area B) and 23/26b (Area B), Serica 18%
The Erskine field produced consistently across 2025, delivering a rate of over
1,900 boepd net to Serica in 2025 (2024: 1,200 boepd). A late life
compression project to extend the life of the has been deferred until 2027.
Columbus - Blocks 23/16f and 23/21a (part), Serica 75% (operator)
Production at Columbus was steady in 2025, averaging 1,300 boepd (2024: 1,400
boepd) net to Serica.
Orlando - Block 3/3b, Serica 100%
Average Orlando field production in 2025 was 2,000 boepd (2024: 3,300 boepd)
net to Serica. Storm damage to the host Ninian Central Platform in mid-January
2026 led to an outage until early March.
West of Shetland
Lancaster, Serica 100% (operator)
The acquisition of Prax Upstream was completed on 11 December 2025, from which
time production from Lancaster was added to the Serica portfolio. The field
has since produced at levels of around 6,000 boepd with high-uptime and is
expected to remain around this level until production ceases. Bluewater, the
FPSO operator, has now served notice on the Aoka Mizu FPSO, and production is
expected to cease in May 2026, in line with expectations.
Organic growth assets
Kyla (P2616), Serica (operator) 100%
The Kyla Redevelopment, located in Block 29/2c, is a previously producing
oilfield, 20 km southeast of Triton, shut-in in 2020 solely due to the
decommissioning of the Banff FPSO host facility. A field development plan was
submitted in February 2026, and the asset name accordingly changed from Kyle
to Kyla in line with regulatory requirements. As plans for development have
progressed, 10.2 mmboe of 2C resources have been matured to 2P reserves. Kyla
can be produced via a single horizontal well tied-back to Triton via Bittern,
similar to other Triton tie-backs.
P2530, Serica 40% (operator)
P2530 contains the Wagtail oil discovery and the low-risk Marsh and Bancroft
exploration prospects. Wagtail is situated north-west of the Triton FPSO,
and development engineering feasibility studies are ongoing. The P2530 joint
venture will then be in a position to decide whether to move onto the next
licence phase and commit to drill an appraisal well, or relinquish the licence
with no further commitments by 31 August 2026.
Greater Buchan Area - Blocks 20/5a, 205d, 21/1d & 21/1a, Serica 30%
Buchan Horst is one of the largest remaining undeveloped fields on the UKCS,
with an estimated 22.7 mmboe of 2C resources net to Serica, and the potential
for 10,000 boepd peak net production. The development project would support an
estimated 1,000 jobs in the UK. Serica continues to work closely with the
joint venture partners to assess the project, retaining optionality over
future development scenarios.
Skerryvore - Blocks 30/12c (part), 30/13c (split), 30/17h, 30/18c and 30/19c
(part), Serica 70% working interest
The P2400 Licence is located in the Central North Sea, 60 km south of the
Erskine field. The commitment work programme includes drilling an exploration
well on the Skerryvore prospect by the end of March 2027. With a primary
target volume of up to 36 mmboe recoverable, an attractive estimated chance of
success of 43%, and the potential to tieback into existing infrastructure,
Serica continues to explore options relating to the timing of the well
commitment.
Fynn Beauly - (P2634) Serica 50%
A 50% interest in P2634 licence, containing the Fynn Beauly heavy oil
discovery, was acquired when completing the acquisition of Parkmead (E&P)
Limited in April 2025. The current licence commitment is limited to technical
studies to assess potential development options.
----------------------
FINANCIAL REVIEW
Financial performance in 2025 was clearly significantly adversely impacted by
the lower than expected production. In total, we estimate that around $250
million of revenue was deferred due to the unscheduled Triton outages, giving
an illustration of what can be achieved when the portfolio is firing on all
cylinders. Serica is well positioned and, with improved operational
performance and a positive cash generation outlook especially in the current
market context, is set to capitalise on the numerous opportunities ahead.
Serica continuously reviews its capital allocation, and investment in those
areas that will create most value for shareholders. We have a portfolio that
is set to generate material cash flow, we are excited about the opportunities
we have on which this money can be spent, have confidence in the team in
place, and will provide more details on our capital allocation framework that
will support the delivery of sustainable shareholder value at our CMD in Q2.
There is of course a balance in spend on inorganic and organic growth, and the
Company delivered value-accretive, cash-generative M&A in 2025, which will
result in a net addition of over $50 million in cash as deals complete in
2026. We continue to assess a wide range of opportunities, both in the UK
North Sea and selectively in other areas in which we can apply our strategy,
as we seek to diversify the Company further and create additional value for
shareholders.
Summary Financial Information Units 2025 2024
Production and sales realised prices
Production boepd 27,600 34,600
Sales volumes mmboe 9.9 12.2
Natural Gas (net of NTS system charges) p/th 84 76
Crude Oil $/bbl 67 75
NGLs $/MT 492 491
Income Statement
Revenue $ million 601 727
EBITDAX((1)) $ million 210 379
Profit before taxation $ million 80 160
(Loss)/profit after taxation $ million (52) 92
Basic (loss)/earnings per share cents (13) 24
Other key financial figures
Capital expenditure((1)) $ million 250 278
Operating cashflow $ million 180 452
CFFO less current tax((1)) $ million 180 403
Dividends paid in year $ million 85 113
(1) See Reconciliation of non-IFRS measures for further detail
Production for 2025 averaged 27,600 boepd, compared to 34,600 boepd in 2024,
with sales volumes of 9.9 mmboe (2024: 12.2 mmboe). The reduction was driven
by a range of operational factors, but concentrated on the previously
announced unscheduled outages experienced at the non-operated Triton hub
during the year.
Realised prices were mixed year-on-year. Average natural gas realised prices
(net of NTS system charges) were circa 10% higher at 84 pence per therm in
2025 (2024: 76 pence per therm), while average realised oil prices were down
by just over 10% at $67/bbl (2024: $75/bbl) and NGL prices averaged $492/MT
(2024: $491/MT). Overall revenue decreased to $601 million (2024: $727
million), reflecting the lower sales volumes, partially offset by stronger gas
pricing and strengthening of sterling against the US dollar.
Reflecting the Company's largely fixed operating costs base, the revenue
impacts were amplified at the profit level. EBITDAX decreased to $210 million
in 2025 (2024: $379 million) and profit before taxation decreased to $80
million (2024: $160 million) with the 2025 outcome benefitting from $67
million of unrealised gains on hedging. Despite the pre-tax profit, the Group
reported a loss after taxation of $52 million in 2025 (2024: profit of $92
million), driven by a total tax charge of $132 million (2024: $68 million),
comprising $2 million of current tax (2024: $14 million) and $130 million of
deferred tax charge (2024: $54 million). The deferred tax charge included a
one-off non-cash deferred tax expense of $65 million as a result of the
extension of the Energy Profits Levy to 31 March 2030 which was substantively
enacted on 3 March 2025. Basic loss per share was 13 cents (2024: earnings per
share 24 cents).
Operating cash flow was sharply reduced at $180 million (2024: $452 million),
very largely reflecting lower profitability in the year. There was also a net
cash tax receipt of $63 million comprising refunds of 2024 tax overpayments of
$72 million net of $9 million cash tax paid in 2025. Capital expenditure,
including decommissioning spend, was $250 million (2024: $278 million) as we
completed the five well drilling programme at our Triton area assets.
Dividends to shareholders totalled $85 million (2024: $113 million) as the
Company continued to deliver on its strategy of investing in growth and
returns, despite a period of planned investment capex and notwithstanding the
unplanned operational outages at Triton.
Sales revenues
Revenue Units 2025 2024
Total revenue $ million 601 727
Gas Sales $ million 361 375
Crude Oil $ million 219 317
NGLs $ million 21 35
Total 2025 sales revenue was $601.4 million, compared to 2024 sales revenue of
$727.2 million and to 2023 pro forma sales revenue of $917 million. The
decrease was largely driven by lower sales volumes. This was partially offset
by higher NBP market prices and realised gas prices.
Sales comprised marginally lower gas revenue of $360.9 million (2024: $374.7
million) with volume reductions partially offset by higher average prices, and
the strengthening of the sterling against the US dollar but markedly lower oil
revenue of $219.0 million based on lower production compounded by lower
realised oil prices (2024: $317.5 million) and NGL revenue of $21.5 million
(2024: $35.0 million) with the reduction driven by lower volumes.
Total product sales volumes for the period comprised 326.9 million therms of
gas (2024: 386.7 million therms), 3.3 million lifted barrels of oil (2024: 4.2
million barrels), and 43,705 metric tonnes of NGLs (2024: 70,872 metric
tonnes). This amounted to overall sales volumes some 2.3 million boe lower in
the period of 9.9 million boe (2024: 12.2 million) and down 4.5 million boe as
compared with the 2023 pro forma volumes.
Gross profit
Gross profit for 2025 was $64.7 million compared to $223.2 million for 2024.
Cost of sales was $536.7 million (2024: $504.0 million), comprising $374.6
million of field operating and lifting costs (2024: $337.3 million), movements
in oil over/underlift charge of $9.7 million (2024: income of $20.6 million),
$158.1 million of non-cash depletion charges (2024: $187.3 million), partially
offset by movement in oil inventory income of $5.7 million (2024: $nil).
Cost of sales Units 2025 2024
Total operating costs $ million 537 504
Field operating costs $ million 367 330
Lifting costs/other $ million 8 8
Movement in over / underlift $ million 10 (21)
Movement in oil inventory $ million (6) -
DD&A $ million 158 187
The increase in total operating costs was driven by an increase in field
operating costs, primarily reflecting increased maintenance activity at the
Bruce platform to reduce maintenance backlogs and improving reliability of the
Bruce hub, on top of the fact that a significant proportion of the operating
cost base is fixed in nature and consequently does not reduce proportionally
to the reduced production and revenues. These effects were compounded by the
strengthening of sterling against the US dollar, as most of the Group's
operating costs are GBP-denominated. The decrease in non-cash DD&A of $29
million was the direct impact of the lower production levels during 2025, and
was largely offset by an increase in the charge relating to movements in
over/underlift and inventory of $25 million.
EBITDAX, operating profit before net finance costs and tax
EBITDAX for 2025 was $210 million (2024: $379 million).
Operating profit to EBITDAX((1)) Units 2025 2024
Operating profit $ million 112 186
Add back DD&A and depreciation $ million 159 188
Add back E&E costs $ million 1 2
(Deduct) /add back unrealised hedging $ million (67) 32
Deduct contract revenue - other $ million (5) (31)
Add back /(deduct) transaction costs and other $ million 6 (2)
Add back share-based payments $ million 4 4
EBITDAX((1)) $ million 210 379
(1) See Reconciliation of non-IFRS measures for further detail.
Operating profit for 2025 was $112.0 million compared to $186.5 million for
2024.
Net hedging income of $75.2 million (2024: $43.5 million expense) comprised
unrealised hedging gains of $67.4 million (2024: losses of $31.8 million) and
realised hedging gains of $7.8 million (2024: $11.7 million losses).
Unrealised hedging gains arose from the non-cash movement in the valuation of
commodity hedge positions at the year end, with the main contributor being
mark-to-market movements on gas price derivatives, largely in the form of zero
cost collars, entered into during 2024 and 2025 to manage commodity price
risks and to comply with minimum hedging requirements for periods extending to
the end of 2027 under the Group's RBL facility. Realised hedging gains during
2025 primarily related to in the money oil and gas swaps and collars.
Contract revenue of $5.4 million (2024: $31.3 million) arose from the final
unwind of an underlying revenue offtake contract that was fair valued in
connection with the Tailwind acquisition in 2023. An original liability of
$66.7 million was recognised which has been released to the Income Statement
across 2023, 2024 and 2025 as the underlying contract unwound.
Administrative expenses for 2025 of $23.1 million compared to $21.6 million
for 2024, reflecting increased costs on M&A-related activities and in
preparation for the planned move to the Main Market during the year, with
payroll and contractor costs increases offset by allocation of costs to
operations.
Profit before taxation and profit after taxation for the period
Profit before taxation for 2025 of $80.3 million (2024: $160.5 million)
included a $2.5 million charge arising from an increase in the fair value of
financial liabilities (2024: $2.5 million charge), and net finance costs of
$29.2 million of finance costs (2024: $23.5 million).
Finance revenue of $6.1 million (2024: $13.9 million) primarily represented
interest income earned on cash deposits and decreased due to lower average
cash balances held in the period and lower interest rates compared to 2024.
Finance costs of $35.3 million (2024: $37.4 million) included interest payable
and other financing fees on the RBL facility, as well as the non-cash discount
unwind on decommissioning provisions and other minor finance costs. The
decrease reflects the impact of lower interest rates during 2025 with the
drawn balance under the Group's RBL remaining at similar levels for both prior
and current year.
The 2025 taxation charge of $132.2 million (2024: charge of $68.1 million)
comprised current tax charges of $1.8 million (2024: $13.9 million) and a
deferred tax charge of $130.4 million (2024: $54.2 million). Current tax was
minimal and reflected adjustments in respect of prior years as current year
taxable income was fully sheltered by group relief impacts of tax losses
within the Group, primarily due to the Triton hub outages as well as the
application of capital allowances against the EPL charges resulting primarily
from significant capital expenditure on the Belinda and Evelyn fields. The
high deferred tax charge is a combination of higher deferred tax charge due to
the accounting impact of the enactment of the extension of the EPL to 2030
during the year, as well as incorporating the impact of utilisation of current
year tax losses for group relief.
Reported and Effective tax rate Units 2025 2024
Profit before tax $ million 80 160
Current tax $ million 2 14
Deferred tax charge $ million 130 54
Tax charge for the period $ million 132 68
Book tax rate 165% 42%
Applicable ring-fence aggregate tax rate 78% 75.5%
Overall, the Group reported a loss after taxation for 2025 of $51.8 million
(which included a one-off non-cash deferred tax charge of $65 million)
compared to a profit after taxation of $92.4 million for 2024. This resulted
in a loss per share of 13 cents (2024: earnings per share of 24 cents) after
taking into account the weighted average number of ordinary shares in issue.
GROUP BALANCE SHEET
The Group maintained access to its reserve-based lending ('RBL') facility and
together with its cash reserves and cash generated in the year, was able to
utilise its access to liquidity to fund ongoing capital investment, while
continuing to support shareholder returns.
Assets 31 December 2025 31 December 2024
$ million $ million
E&E 43 20
PP&E 1,156 992
Goodwill 56 -
Deferred tax asset - 55
Inventories 31 15
Trade and other receivables, financial assets 201 164
Corporate tax receivable 13 71
Cash & cash equivalents and restricted cash 31 148
Total Assets 1,531 1,465
Equity and liabilities 31 December 2025 31 December 2024
$ million $ million
Equity 670 797
RBL borrowings, drawn amounts 231 231
RBL unamortised fees (10) (12)
Provisions 252 146
Financial liabilities 94 124
Deferred tax liability 77 -
Contract liabilities - 5
Trade and other payables, lease liabilities 217 174
Total Equity and Liabilities 1,531 1,465
Exploration and evaluation asset increased from $20 million in 2024 to $43
million in 2025. This was primarily driven by (i) the acquisition of Parkmead
E&P in April 2025, which was accounted for as an asset acquisition and
resulted in $19.4 million of E&E additions primarily associated with the
increase in Serica's stake in the Skerryvore field from 20% to 70%, and (ii)
ongoing expenditure of $4.0 million on the planned redevelopment of the Kyla
field. Following the reclassification of the Kyla asset from 2C resources to
2P reserves, the related $4.7 million E&E asset was transferred to oil and
gas assets within property, plant and equipment.
Property, plant and equipment increased from $991.6 million at year end 2024
to $1,155.7 million at 31 December 2025. Additions comprised capital
expenditure during 2025, including accruals, of $258.2 million primarily
across the Triton Area ($218.5 million) and BKR ($36.1 million) asset hubs.
The Triton area included capital expenditure on new wells drilled on the
Belinda field ($110.9 million), Evelyn field ($46.2 million), pipeline
replacement investment on the Bittern field ($35.2 million) and Triton FPSO
life extension works ($26.2 million). These were partly offset by depletion
charges for 2025 of $158.1 million (2024: $187.3 million).
Serica also completed the acquisition of Prax Upstream Limited ('Prax
Upstream') on 11 December 2025 which is consolidated into the Group's results
from that date. The Prax Upstream acquisition has been accounted as a business
combination in accordance with IFRS 3, with the excess of the purchase
consideration over the provisional fair value of the identifiable net assets
acquired and liabilities assumed on the acquisition being recognised as
provisional goodwill of $56 million in the 2025 balance sheet. The provisional
fair value recognised at the acquisition date is based on information
available as at the acquisition date, and reflects only the assets and
liabilities that Serica controlled at that date. As a result, this accounting
treatment does not reflect potential value (including the realisation of
anticipated synergies) from future events. Since existing SPAs (to acquire a
40% working interest in the Greater Laggan Area from TotalEnergies as well as
small stakes in Catcher and Golden Eagle from One Dyas) had been signed by
Prax Upstream but not completed at the date of acquisition, they are treated
as future events and therefore excluded from the determination of fair value.
Management consequently considers that the provisional goodwill primarily
represents expected future economic benefits from post-acquisition
developments, including those expected to arise on completion of the existing
SPAs including the prospective benefits associated with utilisation of tax
assets acquired as part of Prax Upstream.
The Balance Sheet deferred tax position moved from a net deferred tax asset of
$55.1 million at 31 December 2024 to a net deferred tax liability of $77.1
million at 31 December 2025. The overall swing in deferred tax of $132.2
million largely arose from increased deferred tax liabilities of $168.2
million on higher PP&E balances following significant recent capital
expenditure on new wells in the Triton fields, compounded by the accounting
impact of enactment during the year of the extension of the EPL from 2028 to
2030, as well as deferred tax liabilities of $52.4 million on movements in the
mark-to-market position of commodity derivatives. These were partly offset by
increased deferred tax assets of $72.0 million recognised in respect of higher
loss carried forward and investment allowance balances and increased deferred
tax assets of $19.7 million on higher decommissioning provision at the year
end.
Following acquisitions, tax losses more than doubled in 2025, totalling $2.2
billion of ring fence Corporation Tax losses (end-2024: $1.2 billion), $1.9
billion of Supplementary Charge losses (end-2024: $1.0 billion), and $0.5
billion of Energy Profits Levy ('EPL') losses (end-2024: $156 million). Tax
assets are held in entities across the portfolio, with the exception of Serica
Energy (UK) Limited, where the holding in the Bruce Hub creates scope for
tax-efficient investment.
The decrease in cash and restricted cash balances from $148.5 million at 31
December 2024 to $30.9 million at 31 December 2025 reflected cash flow from
operations of $180.0 million supplemented by net $63.4 million of cash tax
receipts and $14.3 million of net cash and restricted cash acquired on
completion of Prax Upstream Limited, and offset by capital and abandonment
expenditures paid of $250.1 million, net finance costs paid of $20.4 million,
$84.9 million of dividend payments, $11.7 million paid for the acquisition of
Parkmead E&P Limited and $10.1 million for the purchase of own shares in
the Employee Benefit Trust undertaken at an average price of 171p per share,
to meet expected awards.
Trade and other payables increased to $217.4 million at 31 December 2025 from
$173.5 million at the end of 2024, largely reflecting payable balances of Prax
Upstream of $28.4 million. The UK corporation tax receivable of $13.0 million
at 31 December 2025 (31 December 2024: $71.0 million receivable) reflects a
recovery of overpayments of corporation tax, supplementary charge, and the EPL
in respect of 2025 resulting primarily from the application of group tax
relief.
Net derivative financial assets of $29.9 million at 31 December 2025 represent
the mark to market valuation of gas and oil hedging swap and collar products
in place at the year end. This is in contrast to net derivative financial
liabilities of $37.2 million at 31 December 2024. The swing from net
liabilities to net assets is largely the result of the accounting impact of
the fall in gas forward curve prices over the period of the hedges from 2024
to 2025, since most of the hedges in place at the Balance Sheet date were gas
hedges.
Contract liabilities fell to $nil at 31 December 2025 (31 December 2024: $5.4
million) as we expensed the final outstanding portion of an underlying revenue
offtake contract that was fair valued in connection with the Tailwind
acquisition in March 2023.
Non-current financial liabilities of $89.8 million (31 December 2024: $81.9
million) comprise remaining contingent consideration projected to be paid
under the BKR acquisition agreements of $60.2 million (31 December 2024: $49.7
million), royalty liabilities of $24.8 million (31 December 2024: $32.2
million) for amounts payable to third parties under the terms of Triton asset
acquisitions previously made by Tailwind and deferred consideration relating
to the Parkmead acquisition of $4.8 million.
Provisions of $252.3 million (31 December 2024: $146.0 million) predominantly
relate to decommissioning obligations and comprise current balances of $17.5
million (31 December 2024: $nil million) and non-current balances of $233.8
million (31 December 2024: $146.0 million). The increase from 2024 reflects a
combination of additions to the decommissioning provision in relation to the
new Belinda and Evelyn wells of $32.0 million, decommissioning provision
related to the Lancaster field of $56.4 million assumed on the acquisition of
Prax Upstream and other movements of $17.9 million.
Interest bearing loans of $221.5 million at 31 December 2025 represent drawn
amounts of $231.0 million net of unamortised facility fees of $9.5 million
under the $525 million RBL facility entered into in January 2024.
Overall, net assets have decreased from $796.5 million at year end 2024 to
$669.6 million at 31 December 2025.
CASH BALANCES AND FUTURE COMMITMENTS
Current cash position and price hedging
At 31 December 2025 the Group held adjusted net debt of $200 million as
compared to adjusted net cash of $83 million at 31 December 2024.
Adjusted Net Debt 31 December 2025 31 December 2024
$ million $ million
Interest bearing loan (221) (219)
Add back unamortised fees (10) (12)
Cash & cash equivalents 19 148
Restricted cash 12 -
Adjusted Net Debt (200) (83)
As at 20 March 2026, the Company held Adjusted Net Debt of $152 million.
Hedging
Serica carries out hedging activity to manage commodity price risk, to meet
its contracted arrangements under its RBL facility and to ensure there is
sufficient funding for future capital allocation objectives. Serica held the
following instruments in respect of 2026 and 2027 for its existing assets as
at 20 March 2026:
Oil hedges
2026 2027
Weighted Average: Units Q1-26 Q2-26 Q3-26 Q4-26 Q1-27 Q2-27 Q3-27 Q4-27
Swap price $/bbl 80 68 68 68 0 0 0 0
Collar floor net $/bbl 64 60 60 63 62 63 63 63
Total weighted average $/bbl 73 62 62 63 62 63 63 63
Collar ceiling $/bbl 76 72 71 72 71 71 71 71
Hedged Volume Kboe/d 18 17 15 23 19 16 15 15
Gas hedges
2026 2027
Weighted Average: Units Q1-26 Q2-26 Q3-26 Q4-26 Q1-27 Q2-27 Q3-27 Q4-27
Swap price p/therm 94 0 0 0 0 0 0 0
Collar floor net p/therm 83 63 61 71 71 56 56 62
Total weighted average p/therm 85 63 61 71 71 56 56 62
Collar ceiling p/therm 139 96 93 121 121 62 62 85
Hedged Volume Kboe/d 8 10 9 8 8 7 7 7
Field and other capital commitments
Serica's planned 2026 investment programme includes further capital work on
the Bruce facilities and Triton FPSO.
At 31 December 2025, the Group had commitments for future capital expenditure
relating to its oil and gas properties which relate primarily to projects
being undertaken to increase the operational lifetime of both the Bruce and
Triton hubs. The Group's only significant exploration commitment work
programme includes drilling an exploration well on the Licence P2400
(Skerryvore) prospect regarding which, given the lack of clarity regarding the
future fiscal and licensing regime, the licence was extended to 31 March 2027.
Cash projections are run periodically to examine the potential impact of
extended low oil and gas prices as well as possible production interruptions.
Serica currently has substantial net cash resources and relatively low
operating costs per boe which means that the Company is well placed to
withstand such risks and its capital commitments can be funded from existing
cashflow in most scenarios.
OTHER
Asset values
At 31 December 2025, Serica's market capitalisation stood at $925.3 million
based upon a share price of 174.8 pence which exceeded the net asset value of
$669.6 million. By 24 March 2026 the Company's market capitalisation, based on
a share price of 252.0p, had increased to $1,329 million.
Serica Energy plc
Group Income Statement
For the year ended 31 December 2025
2025 2024
Note $000 $000
Continuing operations
Sales revenue 4 601,429 727,178
Cost of sales 5 (536,689) (503,981)
Gross profit 64,740 223,197
Hedging income/(expense) 16 75,166 (43,474)
Contract revenue - other 16 5,408 31,292
Exploration and pre-licence costs (1,100) (1,595)
E&E asset write-offs 12 (147) (851)
General and administrative expenses 6 (23,075) (21,601)
Transaction costs 29 (5,533) -
Foreign exchange gain 38 3,234
Share-based payments 25 (3,523) (3,735)
Operating profit before net finance costs 111,974 186,467
and tax
Change in fair value of financial liabilities 19 (2,471) (2,538)
Finance revenue 8 6,102 13,927
Finance costs 8 (35,262) (37,358)
Profit before taxation 80,343 160,498
Taxation charge for the year 9 (132,165) (68,069)
(Loss)/profit for the year (51,822) 92,429
(Loss)/profit for the year attributable to:
Equity owners of the Company (51,822) 92,429
(Loss)/earnings per ordinary share - EPS
Basic EPS on (loss)/profit for the year ($) 10 (0.13) 0.24
Diluted EPS on (loss)/profit for the year ($) 10 (0.13) 0.23
Serica Energy plc
Group Statement of Comprehensive Income
For the year ended 31 December 2025
2025 2024
$000 $000
(Loss)/profit for the year (51,822) 92,429
Other comprehensive profit/(loss)
Items that may be subsequently reclassified to income statement:
Exchange differences on translation 15,909 (5,217)
Other comprehensive profit/(loss) for the year 15,909 (5,217)
Total comprehensive (loss)/profit for the year (35,913) 87,212
Total comprehensive (loss)/profit attributable to:
Equity owners of the Company (35,913) 87,212
Serica Energy plc
Registered Number: 05450950
Group Balance Sheet
As at 31 December 2025
2025 2024
Note $000 $000
Non-current assets
Exploration & evaluation assets 12 43,283 20,367
Property, plant and equipment 13 1,155,716 991,588
Goodwill 29 56,497 -
Derivative financial assets 16 5,667 -
Deferred tax asset 9 - 55,139
1,261,163 1,067,094
Current assets
Inventories 14 31,423 14,884
Trade and other receivables 15 170,993 158,117
Corporate tax receivable 13,026 71,013
Derivative financial assets 16 24,260 5,185
Restricted cash 17 12,060 -
Cash and cash equivalents 17 18,840 148,460
270,602 397,659
TOTAL ASSETS 1,531,765 1,464,753
Current liabilities
Trade and other payables 18 211,646 168,287
Derivative financial liabilities 16 - 31,185
Contract liabilities 16 - 5,408
Financial liabilities 19 4,140 -
Lease liabilities 26 2,308 1,418
Provisions 20 18,712 -
Non-current liabilities
Derivative financial liabilities 16 - 11,201
Financial liabilities 19 89,756 81,923
Deferred tax liability 9 77,132 -
Lease liabilities 26 3,415 3,769
Provisions 20 233,594 145,974
Interest bearing loans 21 221,488 219,130
TOTAL LIABILITIES 862,191 668,295
NET ASSETS 669,574 796,458
Share capital 23 245,715 245,537
Merger reserve 23 286,590 286,590
Other reserve 25 41,063 37,540
Treasury/own shares 23 (6,678) (8,931)
Accumulated funds 101,087 249,834
Currency translation reserve 1,797 (14,112)
TOTAL EQUITY 669,574 796,458
Approved by the Board on 25 March 2026
Chris Cox
Martin Copeland
Chief Executive Officer
Chief Financial Officer
Serica Energy plc
Group Statement of Changes in Equity
For the year ended 31 December 2025
Share capital Merger reserve Other reserve Currency translation reserve Accumulated funds Total
Treasury/own shares
$000 $000 $000 $000 $000 $000 $000
At 1 January 2025 245,537 286,590 37,540 (8,931) (14,112) 249,834 796,458
Loss for the year - - - - - (51,822) (51,822)
Other comprehensive profit - - - - 15,909 - 15,909
Total comprehensive income/(loss) - - - - 15,909 (51,822) (35,913)
Issue of shares 178 - - - - - 178
Share-based payments - - 3,523 - - - 3,523
Treasury/own shares - - - (9,819) - - (9,819)
Release of shares - - - 12,072 - (12,072) -
Dividend paid - - - - - (84,853) (84,853)
At 31 December 2025 245,715 286,590 41,063 (6,678) 1,797 101,087 669,574
At 1 January 2024 245,257 283,367 37,650 - (8,895) 276,789 834,168
Profit for the year - - - - - 92,429 92,429
Other comprehensive loss - - - - (5,217) - (5,217)
Total comprehensive (loss)/income - - - - (5,217) 92,429 87,212
Issue of shares 280 3,223 - - - - 3,503
Share-based payments - - 3,735 - - - 3,735
Treasury/own shares - - - (18,775) - - (18,775)
Release of shares - - - 9,844 - (9,844)
Share payments - - (3,845) - - 3,845 -
Dividend paid - - - - - (113,385) (113,385)
At 31 December 2024 245,537 286,590 37,540 (8,931) (14,112) 249,834 796,458
Serica Energy plc
Group Cash Flow Statement
For the year ended 31 December 2025
2025 2024
$000 $000
Note
Cash inflow from operations 24 179,946 452,222
Taxation received/(paid) 63,358 (152,517)
Decommissioning spend (1,088) (18,142)
Net cash flow generated from operating activities 24 242,216 281,563
Investing activities:
Interest received 5,486 13,927
Expenditures relating to E&E assets (6,467) (11,123)
Expenditures relating to property, plant and equipment (242,567) (249,050)
Acquisition of asset interests 30 (11,720) (7,665)
Business combination, net cash acquired 29 2,235 -
Net cash flow used in investing activities (253,033) (253,911)
Financing activities:
Payments of lease liabilities 26 (1,943) (2,697)
Proceeds from issue of shares 23 178 280
Repayment of borrowings 21 (51,848) (323,700)
Proceeds from borrowings 21 51,848 283,500
Dividends paid 11 (84,853) (113,385)
EBT/Share buyback 23 (9,819) (18,775)
Finance costs paid (25,900) (38,501)
Net cash flow used in financing activities (122,337) (213,278)
Net decrease in cash and cash equivalents (133,154) (185,626)
Effect of exchange rates on cash and cash equivalents 3,534 (1,347)
Cash and cash equivalents at 1 January 24 148,460 335,433
Cash and cash equivalents at 31 December 24 18,840 148,460
Serica Energy plc
Notes to the Financial Statements
1. Authorisation of the Financial Statements and Statement of Compliance
with UK adopted International Accounting Standards
The Group's financial statements for the year ended 31 December 2025 were
authorised for issue by the Board of Directors on 25 March 2026 and the
balance sheet was signed on the Board's behalf by Chris Cox and Martin
Copeland. Serica Energy plc is a public limited company incorporated and
domiciled in England & Wales with its registered office at 72 Welbeck
Street, London, W1G 0AY. The principal activity of the Company and its
subsidiaries (together the 'Group') is to identify, acquire and subsequently
exploit oil and gas reserves. A listing of the Group's subsidiaries is
contained in note 31 to these Group financial statements. 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 UK
adopted International Accounting Standards as they apply to the financial
statements of the Group for the year ended 31 December 2025. The principal
material accounting policies adopted by the Group are set out in note 2.
2. Material Accounting Policies
Basis of Preparation
Other than as noted in the new and amended standards and interpretations
section below, the accounting policies which follow set out those policies
which have been applied consistently in preparing the financial statements for
the year ended 31 December 2025.
The Group financial statements have been prepared on a historical cost basis
and presented in US dollars. All values are rounded to the nearest thousand US
dollars ($000) except when otherwise indicated.
In preparing the Group financial Statements management has considered the
impact of climate change. These considerations did not have a material impact
on the financial reporting judgements and estimates and consequently climate
change is not expected to have a significant impact on the Group's going
concern assessment to June 2027 nor the viability of the Group over the next
five years. However, governmental and societal responses to climate change
risks are still developing, and are interdependent upon each other, and
consequently financial statements cannot capture all possible future outcomes
as these are not yet known. It is recognised that Net Zero targets and
third-party expectations may drive government action that imposes further
requirements and costs on companies in the future. The Group has additional
planned expenditure related to flare gas recovery and other emission reduction
measures, however, as all of the Group's existing portfolio of producing
assets are currently projected to cease production by 2036, it is believed
that any such future changes would have a relatively limited impact compared
to assets with longer durations. The Group will continue to consider the
impact of climate change on any future business developments.
Going Concern
The Directors are required to consider the availability of resources to meet
the Group's liabilities for the period till 30 June 2027, the 'going concern
period'.
As at 20 March 2026 the Group held cash and cash equivalents of $94 million,
restricted cash of $12 million, and undrawn RBL facility amount of $198
million. See note 21 for further details of the current RBL facility.
The Group has a balance in product mix between gas and oil, and two main
operating hubs which reduces the potential impact of production interruptions.
The Group regularly monitors its cash, funding and liquidity position,
including available facilities and compliance with facility covenants. Ongoing
capital requirements also include surety bonds which provide cover for
decommissioning security. 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. In recent years, 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 two
cash projections for the going concern period. These projections cover a base
case forecast and an extreme stress test scenario for the operations of the
Group. RBL repayments have been assumed based on the current redetermination
and no covenant compliance matters noted.
The base case assumptions for the going concern period included commodity
pricing of 82 pence/therm for gas and US$69/bbl for oil for the remainder of
2026 and 76 pence/therm gas and US$72/bbl oil for H1 2027. Production, opex,
capex and tax assumptions are those currently included in standard management
forecasting which includes the continuation of existing surety bonds, the
completion during 2026 of previously announced acquisitions (note 29) and
associated surety bonds which provide cover for decommissioning security. The
forward-looking price assumptions are considered as reasonable in light of
recent commodity forward pricing and a consensus of published forecasts from
the industry, brokers and other analysts.
The stress test assumptions assume a six-month Triton hub production shut-in
and 25% reduced production volumes from the base case across the full
portfolio of producing assets for H1 2027. Base case commodity pricing is
retained for 2026 but lower commodity pricing of 50p/therm gas and US$60/bbl
oil are assumed for the H1 2027 period in this scenario which are
significantly below the range of current market expectations for the going
concern period. Under this scenario, which would result in lower cash inflows
and any repayments of the RBL facility as redetermined, the Group was able to
maintain sufficient cash to meet its obligations and maintain covenant
compliance. A number of mitigating factors and mitigating actions that are
under management control are available to management in the stress test event.
These would mitigate the reduced operating cash flows experienced and are not
included in the projection.
After making enquiries and having taken into consideration the above factors,
the Directors considered it appropriate 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 sources of estimation uncertainty
The preparation of financial statements in conformity with UK adopted
International Accounting Standards requires management to make judgements and
estimates 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 Group has identified the
following areas where significant judgement, estimates, and assumptions are
required.
I) Uses of judgement
Key sources of judgement that may have a significant risk of causing material
adjustment to the amounts recognised in the financial statements are as
follows: assessing whether impairment triggers exist that might lead to the
impairment of the Group assets (including oil and gas producing &
development assets and Exploration and Evaluation "E&E" assets).
Details on these sources of judgements are given below.
Assessment of the impairment indicators 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.
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 2025
in accordance with the stated policy.
II) Sources of estimation uncertainty
Key sources of estimation uncertainty
The key sources of estimation uncertainty that may have a significant risk of
causing material adjustment to the amounts recognised in the financial
statements are: the assessment of commercial reserves and production profiles;
and decommissioning provisions.
Details on these key sources of estimation uncertainty are given below.
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 depletion charge for the period, decommissioning
provisions, whether deferred tax assets are recoverable and assessing whether
any impairment charge is required. Estimates of oil and gas reserves require
critical judgement. The Group uses proven and probable (2P) reserves
(excluding fuel gas) (see Review of Operations) as the basis for calculations
of depletion and expected future cash flows from underlying assets because
this represents the reserves management intends to develop. 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. A 10%
reduction in the assessed quantity of commercial reserves would lead to an
increase in the depletion charge for 2025 of $15.4 million (2024:
$20.4million).
Decommissioning provisions
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 estimates and assumptions, actual results could differ from these
estimates. Expected timing of expenditure can also change, for example in
response to changes in laws and regulations or their interpretation, and/or
due to changes in commodity prices. The payment dates are uncertain and depend
on the production lives of the respective fields. For further details
including sensitivities of the calculation to changes in input variables (see
note 20).
Non-key sources of estimation uncertainty
Non-key sources of estimation uncertainty include determining the fair value
of contingent consideration, royalty liabilities, 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. Any
cash flows specific to the contingent consideration also reflect applicable
commercial terms and risks. In calculating the fair value of the remaining
contingent consideration on the BKR acquisitions payable as at 31 December
2025, assumptions underlying the calculation were updated from 2024. 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 19).
Royalty liabilities
In calculating the fair value of the royalty payable, assumptions included
commodity prices, future production and discount rates. For further details
including sensitivities of the calculation to changes in input variables (see
note 19).
Recoverability of deferred tax assets
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. There is no critical estimation uncertainty at the end of the reporting
period.
Basis of Consolidation
The consolidated financial statements include the accounts of Serica Energy
plc (the "Company") and entities controlled by the Company (its subsidiaries)
made up to 31 December each year. Together these comprise the "Group".
Control is achieved when the Company:
• has power over the investee;
• is exposed, or has rights, to variable returns from its involvement with
the investee; and
• has the ability to use its power to affect its returns.
The Company reassesses whether or not it controls an investee if facts and
circumstances indicate that there are changes to one or more of the three
elements of control listed above. Consolidation of a subsidiary begins when
the Company obtains control over the subsidiary and ceases when the Company
loses control of the subsidiary. Specifically, the results of the subsidiaries
acquired or disposed of during the year are included in profit or loss from
the date the Company gains control until the date when the Company ceases to
control the subsidiary.
The results and financial position of all of the Group entities that have a
functional currency different from the presentation currency are translated
into the presentation currency as follows:
· Assets and liabilities for each balance sheet presented are
translated at the closing rate at the date of that balance sheet;
· Income and expenses for each income statement are translated at
average exchange rates (unless this average is not a reasonable approximation
of the rates prevailing on the transaction dates, in which case income and
expenses are translated at the rate on the dates of each transaction);
· The exchange differences arising on translation for consolidation are
recognised in other comprehensive income; and
· Any fair value adjustments to the carrying amounts of assets and
liabilities arising on the acquisition are treated as assets and liabilities
of the acquired entity and are translated at the spot rate of exchange at the
reporting date.
Where necessary, adjustments are made to the financial statements of
subsidiaries to bring the accounting policies used in line with the Group's
accounting policies. All inter-company balances and transactions have been
eliminated upon consolidation.
Foreign Currency Translation
Items included in the financial statements of each of the Group's subsidiaries
are measured using the currency of the primary economic environment in which
the entity operates ('functional currency'). The Group's financial statements
are presented in US dollars, the currency which the Group has elected to use
as its presentational currency.
In the financial statements of Serica Energy plc and its individual
subsidiaries, 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
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 income statement in accordance with IFRS 9.
Goodwill/gain on acquisition
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 on acquisition 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
Oil and gas operations are usually conducted by the Group as co-licensees in
unincorporated joint operations with other companies. Most of the Group's
activities are conducted through joint operations, whereby the parties that
have joint control of the arrangement have the rights to the assets and
obligations for the liabilities, relating to the arrangement. The Group
recognises its share of assets, liabilities, income and expenses of the joint
operation in the consolidated financial statements on a line-by-line basis.
Full details of Serica's working interests in those petroleum and natural gas
exploration and production activities classified as joint operations are
included in table of Licence Holdings at the end of the Annual Report.
Exploration and Evaluation Assets
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.
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, Disposals and Exchanges
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
annual reporting date. Proved and probable reserves estimates obtained from an
independent reserves specialist have been used as the basis for 2024 and 2025
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 carrying amount 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. When the cost of an asset includes contingent or
variable consideration that may become payable to the vendor, the Group
develops an accounting policy for the recognition and measurement of those
costs and the associated liability as is appropriate having regard to the
nature of the obligation to make the contingent or variable payments.
Subsequent measurement of such consideration is capitalised with E&E or
oil & gas assets when payable as applicable. The policy is applied
consistently to similar transactions. See note 30.
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 are added to or
deducted from the cost of the assets to which it relates. If a decrease in the
decommissioning liability exceeds the carrying amount of the asset, the excess
is recognised immediately in profit or loss. 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. The discount and inflation rates applied have taken into
consideration the applicable rig rates and expected timing of cessation of
production on each field.
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 using an observable year-end oil or gas market price
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.
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 of
deposit.
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
loans and borrowings, trade and other payables, BKR consideration liabilities,
royalty liabilities, deferred shares in relation to the Tailwind acquisition
and derivative liabilities. All financial liabilities are recognised initially
at fair value.
Royalty Liabilities
The fair value of the royalty liability is estimated as at applicable
reporting dates from a valuation technique using future expected discounted
cash flows and the calculations involve a range of assumptions related to oil
prices, production volumes and discount rates (see note 19).
BKR consideration
The fair value of the BKR consideration is estimated as at applicable
reporting dates from a valuation technique using future expected discounted
cash flows. The methodology uses several significant unobservable inputs (see
note 19).
Loans and Borrowing
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.
Emissions liabilities
The Group operates in an energy intensive industry and is therefore required
to partake in emission trading schemes ("ETS"). The Group recognises an
emission liability in line with the production of emissions that give rise to
the obligation. To the extent the liability is covered by allowances held, the
liability is recognised at the cost of these allowances held and if
insufficient allowances are held, the remaining uncovered portion is measured
at the spot market price of allowances at the balance sheet date. The expense
is presented within 'production costs' under 'cost of sales' and the liability
is presented in 'trade and other payables'.
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 income statement 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 16.
Equity
Equity instruments issued by the Company are recorded in equity at the
proceeds received, net of direct issue costs.
Treasury/own shares
The Group's holdings in its own equity instruments are shown as deductions
from shareholders' equity. Treasury shares represent Serica shares repurchased
and available for specific and limited purposes. For accounting purposes,
shares held in Employee Benefit Trusts to meet the future requirements of the
employee share-based payment plans are treated in the same manner as treasury
shares and are, therefore, included in the consolidated financial statements
as treasury/own shares. The cost of treasury shares subsequently sold or
reissued is calculated on a weighted-average basis. Consideration, if any,
received for the sale of such shares is also recognised in equity. No gain or
loss is recognised in the income statement on the purchase, sale, issue or
cancellation of equity shares.
Trade and other receivables and contract assets
Trade and other 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 receivables
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.
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, including FPSOs. Revenue is
accordingly recognised for this performance obligation when control over the
corresponding commodity is transferred to the customer. The Group principally
satisfies its performance obligations at a point in time and the amounts of
revenue recognised relating to performance obligations satisfied over time are
not significant. The normal credit term is 15 to 30 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 and does not give rise to equal taxable and deductible
temporary differences.
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.
Dividends
The Company recognises a liability to pay a dividend when the distribution is
authorised, and the distribution is no longer at the discretion of the
Company. A corresponding amount is recognised directly in equity.
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
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 new standards,
amended standards or interpretations, which are effective for annual periods
beginning on or after 1 January 2025. These include the following:
- Amendments to IAS 21 - Lack of Exchangeability
The Group has not early adopted any other standard, interpretation or
amendment that has been issued but is not yet effective. Other than the
Amendments to IAS 21 described above, which had no impact, the accounting
policies adopted are consistent with those of the previous financial year.
There are no new or amended standards or interpretations adopted from 1
January 2025 onwards, that have a significant 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. These include the
following:
- Amendments to IFRS 9 and IFRS 7 - Classification and Measurement of
Financial Instruments
- Amendments to IFRS 9 and IFRS 7 - Power Purchase Agreements
- Annual Improvements to IFRS Accounting Standards-Volume 11
- IFRS 18 - Presentation and Disclosure in Financial Statements
- IFRS 19 - Subsidiaries without Public Accountability: Disclosures
The Group intends to adopt them when they become effective. The Group is
reviewing the potential impacts of IFRS 18 but the other new or amended
standards not yet adopted are not expected to have a material impact on the
financial statements.
3. Segment
Information
For the purposes of segmental reporting, the Group currently operates a single
class of business being oil and gas exploration, development and production
and related activities in a single geographical area, being presently the UK
North Sea.
4. Sales Revenue
2025 2024
$000 $000
Gas sales 360,925 374,719
Oil sales 218,984 317,478
NGL sales 21,520 34,981
Total revenue 601,429 727,178
Gas sales revenue in 2025 arose from three key customers (2024: three). Oil
sales revenue in 2025 was from three key customers (2024: three), and NGL
sales in 2025 were made to eight customers (2024: eight).
The revenue from three significant customers individually comprising $416.5
million, $115.9 million and $60.5 million constitutes more than 98% of total
revenue amounting to $592.9 million (2024: three customers comprising $441.4
million, $181.1 million and $78.2 million individually comprising $700.7
million).
5. Cost of Sales
2025 2024
$000 $000
Operating costs 366,605 329,820
Lifting costs 8,006 6,874
Change in decommissioning estimates expensed (note 20) - 601
Depletion and depreciation (note 13) 158,141 187,250
Movement in liquids overlift/underlift 9,660 (20,564)
Movement in oil inventory (5,723) -
536,689 503,981
6. Operating Profit
General and administrative expenses
General and administrative expenses of $23,075,000 (2024: $21,601,000)
included depreciation of right of use assets of $1,045,000 (2024: $1,070,000).
Depreciation and depletion expense
Depreciation of right of use assets totalled $2,085,000 (2024: $2,114,000) of
which $1,040,000 (2024: $1,044,000) was allocated to cost of sales and
$1,045,000 (2024: $1,070,000) allocated to administrative expenses.
Depletion charges on oil and gas properties of $157,101,000 (2024:
$186,206,000) are classified within cost of sales.
Auditor's Remuneration
2025 2024
£000
$000 $000
Audit of the Group accounts * 1,425 960
Audit of the Company's accounts 53 50
Audit of accounts of Company's subsidiaries 216 120
Total audit fees 1,694 1,130
*Group audit fees disclosed in 2025 include $264,000 related to incremental
2024 audit fees.
No fees were paid to Ernst & Young LLP and its associates for non-audit
services in 2024 or 2025.
7. Staff Costs and Directors' Emoluments
a) Staff Costs - Group 2025 2024
$000 $000
Wages and salaries 39,408 35,641
Social security costs 6,197 7,238
Other pension costs 4,281 3,140
Share-based long-term incentives 3,523 3,735
53,409 49,754
The average number of persons employed by the Group during the year was 233
(2024: 222), with 13 in
management functions (2024: 12), 193 in technical functions (2024: 185) and 27
(2024: 25) in finance and
administrative functions.
Staff costs for key management personnel:
Short-term employee benefits 3,670 3,855
Post-employment benefits 178 130
Share-based payments (note 25) 951 193
4,799 4,178
b) Directors' Emoluments
The emoluments of the individual Directors were as follows. All amounts are
paid in £ sterling.
Figures in the table below are translated into $ at a 2025 average exchange
rate.
2025 2025 2025 2025 2025 2024
Salary and Bonus Pension Benefits Total Total
fees in kind
$000 $000 $000 $000 $000 $000
M Flegg (1),(2) - - - - - 569
A Bell (1),(3) - - - - - 61
D Latin 369 - - - 369 971
C Cox (1),(4) 817 511 107 1 1,436 599
M Copeland (1),(5) 547 274 71 1 893 684
M Webb (6) - - - - - 64
K Coppinger 132 - - - 132 96
J Schmitt (7) 44 - - - 44 89
M Soeting 112 - - - 112 89
R Lawson 92 - - - 92 77
G Vermersch 92 - - - 92 77
K Van Hecke 112 - - - 112 89
S Lloyd Rees 104 - - - 104 77
2,421 785 178 2 3,386 3,542
Note (1) Cash in lieu of pension
Note (2) Mitch Flegg stepped down as director on 23 April 2024.
Note (3) Andrew Bell retired on 5 February 2024
Note (4) Chris Cox was appointed on 1 July 2024
Note (5) Martin Copeland was appointed on 5 February 2024
Note (6) Malcolm Webb retired on 27 June 2024
Note (7) Jerome Schmidt resigned on 22 May 2025
2025 2024
Number of Directors securing benefits under defined
contribution schemes during the year 2 4
Number of Directors who exercised share options - 2
2025 2024
$000 $000
Aggregate gains made by Directors on the exercise of options - -
Details of Directors' interests in share options and other long-term incentive
plans are included in the Directors' Remuneration report in the Corporate
Governance section of the Annual Report.
The Group defines key management personnel as the Directors of the Company.
There are no transactions with Directors other than their remuneration as
disclosed above and those described in Note 28.
8. Finance Revenue/Costs
2025 2024
$000 $000
Bank interest receivable 4,704 13,927
Other interest receivable 1,398 -
Total finance revenue 6,102 13,927
2025 2024
$000 $000
Loan interest payable 19,194 22,917
Loan commitment fees amortised (note 21) 2,358 2,199
Other financing fees 4,057 3,945
Other charges and interest payable 3,016 2,733
Unwinding of discount on provisions (note 20) 6,637 5,564
Total finance costs 35,262 37,358
9. Taxation
2025 2024
$000 $000
a) Tax charged/(credited) in the income statement
Charge for the year - 14,191
Adjustment in respect of prior years 1,761 (315)
Total current income tax charge 1,761 13,876
Deferred tax
Origination and reversal of temporary differences in the
current year 130,175 61,128
Adjustment in respect of prior years 229 (6,935)
Total deferred tax charge 130,404 54,193
Tax charge in the income statement 132,165 68,069
b) Reconciliation of the total tax charge/(credit)
The tax in the income statement for the year differs from the amount that
would be
expected by applying the standard UK corporation tax rate for the following
reasons:
2025 2024
$000 $000
Accounting profit before taxation 80,343 160,498
Statutory rate of corporation tax in the UK of 40% (2024: 40%) 32,137 64,199
Permanent differences 9,875 9,067
Movement in unrecognised deferred tax assets 2,453 811
Investment Allowance (9,342) (14,216)
EPL - Rate differential - 11,085
EPL - Income taxed at different rates 90,793 28,263
EPL - Investment allowance - (25,158)
Income tax at different rates 4,259 1,268
Adjustment in respect of prior years 1,990 (7,250)
Tax charge reported in the income statement 132,165 68,069
c) Recognised and unrecognised tax losses
Deferred tax assets are recognised only to the extent that it is probable that
sufficient taxable profits will be available in future against which
deductible temporary differences, tax losses and allowances can be utilised.
In accordance with IAS 12 Income Taxes, the Group assessed at 31 December 2025
the recoverability of deferred tax assets recognised in respect of ring fence
losses and allowances and other deductible temporary differences, together
with the availability of future taxable profits based on corporate assumptions
to support recognition.
At 31 December 2025, the Group had recognised deferred tax assets of $635.8
million (2024: $576.6 million), arising principally from ring fence losses,
decommissioning liabilities, other temporary differences, derivative financial
liabilities and the oil revenue contract liability. These deferred tax assets
are expected to be recovered through offset against deferred tax liabilities,
principally those arising on property, plant and equipment of $689.6 million
and derivative financial assets of $23.3 million, and through future taxable
profits. Overall, the Group moved from a net deferred tax asset of $55.1
million at 31 December 2024 to a net deferred tax liability of $77.1 million
at 31 December 2025, primarily reflecting the increase in deferred tax
liabilities associated with higher property, plant and equipment balances and
the extension of the Energy Profits Levy to 31 March 2030.
At 31 December 2025, the Group had not recognised deferred tax assets for tax
losses, allowances and other deductible temporary differences amounting to
approximately $1,684 million (2024: $148 million). These other deductible
temporary differences include investment allowances, decommissioning
provisions and employee share options. The significant increase compared with
the prior year primarily reflects tax losses, allowances and other deductible
temporary differences arising on the acquisitions of Parkmead (E&P)
Limited and Prax Upstream Limited for which no deferred tax asset has been
recognised at the balance sheet date, as there is insufficient evidence that
sufficient future taxable profits will be available for recovery. These
deferred tax assets may be recognised in future periods to the extent that it
becomes probable that suitable taxable profits will arise against which they
can be utilised.
Unrecognised tax losses and allowances 2025 2024
$000 $000
Tax losses with no expiry:
Ring fence tax losses 855,158 -
Mainstream corporation tax losses 154,036 140,088
1,009,194 140,088
Other deductible temporary differences and allowances:
Investment allowances 593,697 -
Decommissioning provisions 56,136 -
Employee share options 5,242 7,788
Unused tax credits 20,023 -
675,098 7,788
Total unrecognised tax losses and allowances 1,684,292 147,876
In addition, there are attributes carried forward relating to supplementary
tax charge ($718.3 million) and energy profit levy ($224.9 million) which are
subject to tax rates of 10% and 38% respectively which can be offset against
ring fence tax losses.
d) Deferred tax
The deferred tax included in the balance sheet is as follows:
2025 2024
$000 $000
Deferred tax liability:
Temporary differences on capital expenditure (689,587) (521,436)
Derivative financial assets (23,343) -
Deferred tax liability (712,930) (521,436)
Deferred tax asset:
Tax losses 492,772 427,568
Decommissioning liabilities 77,977 58,264
Investment allowances 60,602 53,765
Contract liability - 4,218
Other temporary differences 4,447 3,743
Derivative financial liabilities - 29,017
Deferred tax asset 635,798 576,575
Net deferred tax (liability)/ asset (77,132) 55,139
Reconciliation of net deferred tax assets/(liabilities)
2025 2024
$000 $000
At 1 January 55,139 107,071
Acquisitions (note 29) 6,654 -
Tax charge during the year recognised in profit (130,404) (54,193)
Currency translation adjustment (8,521) 2,261
At 31 December (77,132) 55,139
The deferred tax in the Group income statement is as follows:
2025 2024
$000 $000
Deferred tax in the income statement:
Temporary differences on capital expenditure 157,225 73,285
Tax losses (57,086) (5,842)
Other temporary differences 30,265 (13,250)
Deferred income tax charge 130,404 54,193
e) Changes to UK corporation tax legislation
Changes to UK corporation tax legislation
In October 2024, the UK government announced changes (effective from 1
November 2024) to the Energy Profits Levy including a 3% increase in the rate
taking the headline rate of tax on North Sea profits to 78%, an extension to
the period of application of the Levy to 31 March 2030 and the removal of the
Levy's main investment allowance. The changes to the rate and to the
investment allowance were substantively enacted in November 2024 and have been
applied in both 2024 and 2025 when accounting for current tax and deferred
tax.
The extension of the EPL to 31 March 2030 was substantively enacted on 3 March
2025 and has therefore been reflected in the 2025 financial statements. The
impact of the extension is an additional deferred tax expense of $65 million
that has been recognised in the current financial statements.
Following the introduction of the Energy Profits Levy in 2022, on 24 May 2024,
Finance (No.2) Act 2024, enacted the Energy Security Investment Mechanism
(ESIM). The original ESIM threshold prices were $71.40 per barrel for oil and
54 pence per therm for gas. These thresholds were based on a 20-year average
to the end of 2022. These thresholds were adjusted from 1 April 2024, and will
be adjusted annually thereafter, by the preceding December's year-on-year
increase in the Consumer Prices Index. The ESIM operates to remove EPL if
both average oil and gas prices fall to, or below, from 1 April 2026 to $78.65
per barrel for oil and 61p per therm for gas (as adjusted for prior year CPI
with effect from 1 April 2024), for two consecutive quarters. The headline tax
rate on UK oil and gas profits will then return to 40 per cent. The UK
Government has also announced the oil and gas price mechanism ("OGPM"). The
OGPM will be a revenue-based tax but will only apply during periods of high
prices and the amount that will be chargeable to the OGPM will be the part of
the consideration that exceeds the threshold. The OGPM will come into effect
once the EPL ends - either on 1 April 2030 or earlier if the ESIM triggers.
The UK has introduced legislation implementing the Organisation for Economic
Co-operation and Development's ("OECD") proposals for global minimum
corporation tax rate (Pillar Two) which is effective for periods beginning on
or after 31 December 2023. The only jurisdiction in which the Group has
material operations is the UK, and the Group does not expect an exposure to
Pillar Two income taxes.
10. Earnings Per Share
Basic earnings or loss per ordinary share amounts are calculated by dividing
net profit or loss for the year attributable to ordinary equity holders of the
parent by the weighted average number of ordinary shares outstanding during
the year. The weighted average number of shares outstanding excludes treasury
shares and shares held by Employee Benefit Trusts.
Diluted earnings per share amounts are calculated by dividing the net profit
attributable to ordinary equity holders of the Company by the weighted average
number of ordinary shares outstanding during the year plus the weighted
average number of ordinary shares that would be issued on the conversion of
dilutive potential ordinary shares granted under share-based payment plans
(see note 25) and, for the 2024 period, deferred consideration for a previous
acquisition into ordinary shares.
The following reflects the income and share data used in the basic and diluted
earnings per share computations:
2025 2024
$000 $000
Net (loss)/profit from continuing operations (51,822) 92,429
Net (loss)/profit attributable to equity holders of the parent (51,822) 92,429
2025 2024
'000 '000
Basic weighted average number of shares 392,017 389,095
Dilutive potential of ordinary shares granted under - 10,110
share-based payment plans
Dilutive potential of ordinary shares under deferred - 339
consideration for acquisition
Diluted weighted average number of shares 392,017 399,544
2025 2024
$ $
Basic EPS on (loss)/profit for the year ($) (0.13) 0.24
Diluted EPS on (loss)/profit for the year ($) (0.13) 0.23
7,248,484 share options, that could potentially dilute the basic earnings per
share in the future, were not included in the calculation of diluted earnings
per share because they are anti-dilutive for the 2025 year-end.
11. Dividends Proposed
Proposed dividends on ordinary shares
A final cash dividend for 2025 of 10.0 pence per share (2024: 10.0 pence per
share) is proposed which would generate a payment of approximately $52.7
million (2024: $49.0 million). Proposed dividends on ordinary shares are
subject to approval at the annual general meeting and are not recognised as a
liability as at 31 December.
Dividends on ordinary shares paid in 2025
A final cash dividend for 2024 of 10.0 pence per share was proposed in April
2025 and approved at the annual general meeting on 22 May 2025 and $53.9
million (£39.3 million) was paid in July 2025.
An interim cash dividend for 2025 of 6.0 pence per share was announced in
August 2025 and $31.0 million (£23.5 million) was paid in November 2025.
12. Exploration and Evaluation Assets
Total
$000
Cost:
1 January 2024 2,457
Acquisitions (note 30) 7,665
Additions 11,123
Write-offs (851)
Currency translation adjustment (27)
31 December 2024 20,367
Acquisitions (note 30) 19,391
Additions 6,467
Transfers (note 13) (4,694)
Write-offs (147)
Currency translation adjustment 1,899
31 December 2025 43,283
Net book amount:
31 December 2025 43,283
31 December 2024 20,367
During the year, following the reclassification of the Kyla asset from 2C
resources to 2P reserves, management concluded that technical feasibility and
commercial viability had been demonstrated. Accordingly, the related E&E
asset of $4.7 million was transferred from E&E assets to oil and gas
assets within property, plant and equipment.
13. Property, Plant and Equipment
Oil and gas properties Equipment, fixtures and fittings Right-of-use assets Total
$000 $000 $000 $000
Cost:
1 January 2024 1,312,468 270 5,342 1,318,080
Additions 264,000 - 5,069 269,069
Decom asset revisions (note 20) 9,711 - - 9,711
Currency translation adjustment (10,576) (4) (114) (10,694)
31 December 2024 1,575,603 266 10,297 1,586,166
Acquisitions (note 29) 1,877 - - 1,877
Additions 257,410 - 791 258,201
Transfers (note 12) 4,694 - - 4,694
Decom asset revisions (note 20) 41,676 - - 41,676
Currency translation adjustment 42,746 20 444 43,210
31 December 2025 1,924,006 286 11,532 1,935,824
Depreciation and depletion:
1 January 2024 410,229 270 1,821 412,320
Charge for the year (note 5) 186,206 - 1,044 187,250
Charge for the year - G&A - - 1,070 1,070
Currency translation adjustment (6,021) (4) (37) (6,062)
31 December 2024 590,414 266 3,898 594,578
Charge for the year (note 5) 157,101 - 1,040 158,141
Charge for the year - G&A - - 1,045 1,045
Currency translation adjustment 26,150 20 174 26,344
31 December 2025 773,665 286 6,157 780,108
Net book amount:
31 December 2025 1,150,341 - 5,375 1,155,716
31 December 2024 985,189 - 6,399 991,588
Depreciation and depletion
Depletion charges on oil and gas properties are classified within 'cost of
sales'. $1,040,000 (2024: $1,044,000) and $1,045,000 (2024: $1,070,000) of
right of use asset depreciation has been charged to cost of sales and
administrative expenses respectively.
Impairment indicator
The Group reviewed its oil and gas property, plant and equipment for
indicators of impairment at 31 December 2025. In the prior year, an impairment
indicator was identified as the Group's market capitalisation was lower than
the book value of its net assets. An impairment assessment was performed at
that time, which did not result in an impairment charge. At 31 December 2025,
management concluded that this prior year indicator was no longer present and
that no new impairment indicators existed at the reporting date. Accordingly,
no impairment test was required for these assets and no impairment charge was
recognised in the year.
14. Inventories
2025 2024
$000 $000
Materials and spare parts 11,065 7,365
Hydrocarbons 20,358 7,519
31,423 14,884
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. Inventories are recorded net of an
obsolescence provision of $4.1 million (2024: $3.8 million).
15. Trade and Other Receivables
2025 2024
$000 $000
Trade receivables and accrued income 63,030 56,847
Amounts recoverable from JV partners 2,979 2,733
Other receivables 10,988 7,436
BKR advance payments 41,476 27,989
Prepayments 8,177 9,572
VAT recoverable 6,872 6,923
Liquids underlift 37,471 46,617
170,993 158,117
Trade receivables at 31 December 2025 arose from seven (2024: seven)
customers. They are non-interest bearing and are generally on 15 to 30-day
terms.
BKR advance payments consist of annual contractual cash advances made towards
remaining BKR contingent consideration potentially payable, recorded as a
financial liability (see note 19).
None of the Group's receivables are considered impaired and there are no
financial assets past due but not impaired at the year end. The Directors
consider the carrying amount of trade and other receivables approximates to
their fair value. Management considers that there are no other significant
concentrations of credit risk within the Group.
16. Derivative Financial Assets/(Liabilities)
2025 2024
$000 $000
Financial assets
Derivative financial instruments (<1 year) 24,260 5,185
Derivative financial instruments (>1 year) 5,667 -
Derivative financial instruments 29,927 5,185
Financial liabilities
Derivative financial instruments (<1 year) - (31,185)
Derivative financial instruments (>1 year) - (11,201)
Derivative financial instruments - (42,386)
Fair value hierarchy
All financial instruments for which fair value is recognised or disclosed are
categorised within the fair value hierarchy, based on the lowest level input
that is significant to the fair value measurement as a whole, as follows:
Level 1: Quoted (unadjusted) market prices in active markets for identical
assets or liabilities; Level 2: Valuation techniques for which the lowest
level input that is significant to the fair value measurement is directly
(i.e. as prices) or indirectly (i.e. derived from prices) observable; Level 3:
Valuation techniques for which the lowest level input that is significant to
the fair value measurement is unobservable. The valuation methodology for
derivative financial instruments is detailed below and for contingent
consideration is disclosed in note 19. A table summarising the Group's
liabilities measured at fair value is included in note 22.
Derivative financial instruments
The Group enters into derivative financial instruments with various
counterparties. Commodity and foreign currency derivative contracts are
designated as at fair value through profit and loss (FVTPL), and gains and
losses on these contracts are recognised in the income statement. Derivative
financial instruments held at 31 December 2024 and 2025 comprised oil and gas
swaps and collars. These were valued by counterparties, with the valuations
reviewed internally and corroborated with readily available market data of
forward pricing (level 2). Details of the Group's derivative financial
instruments held as at 31 December 2025 are provided in note 22. The
mark-to-market of the Group's open contracts as at 31 December 2025 was a net
asset of $29.9 million (2024: net liability of $37.2 million).
The following gains and losses were recognised in the income statement:
Commodity contracts designated as FVTPL 2025 2024
$000 $000
Mark-to-market unrealised gains/(losses) 67,371 (31,814)
Unrealised hedging income/(expense) 67,371 (31,814)
Oil and gas swaps and options matured during the year 7,795 (4,940)
Other contracts matured during the year - (6,720)
Realised hedging income/(expense) 7,795 (11,660)
Hedging income/(expense) 75,166 (43,474)
Unrealised hedging gains in 2025 arose from oil and gas instruments held
(2024: losses on gas instruments partially offset by unrealised gains on oil
and UKA ETS instruments held). Unrealised hedging losses on gas and other
swaps comprise unrealised charges on the movement during the year in the
calculated fair value liability and asset of outstanding gas price or other
derivative contracts measured at the respective balance sheet dates.
Realised hedging gains measured at fair value through profit or loss for 2025
comprise gains realised on oil and gas swaps. For 2024 losses were realised on
oil, gas and UKA ETS swaps.
Contract liabilities
2025 2024
$000 $000
Contract liabilities - 5,408
- 5,408
On acquisition of Tailwind Energy Investments Ltd in 2023 a pre-existing oil
revenue contract was fair valued, resulting in contract liabilities of $66.7
million (£54.2 million) being recognised. The contract liabilities represent
the differential in contract pricing and market price and are realised as
performance obligations are considered met in the underlying revenue contract.
To the extent the contract liability represents the fair value differential
between contract price and market price, it is unwound through 'contract
revenue - other' upon satisfaction of the performance obligation. $5.4 million
has been released to the Income Statement in 2025 (2024: $31.3 million).
17. Cash and Cash Equivalents
2025 2024
$000 $000
Cash at bank and in hand 18,840 123,390
Short-term deposits - 25,070
Cash and cash equivalents 18,840 148,460
Restricted cash 12,060 -
Cash and restricted cash 30,900 148,460
As at 31 December 2025, the cash and restricted cash balance of $30.9 million
(2024: $148.5 million) contained amounts of $12.1 million held in separate
bank accounts for the purpose of providing security against Lancaster field
decommissioning work on the Aoka Mizu FPSO. This amount does not meet the
definition of cash and cash equivalents in IAS 7 and held in escrow accounts
for expected future decommissioning expenditure. In 2024 $31.0 million held in
a separate bank account for the purpose of providing security against letters
of credit issued in respect of certain decommissioning liabilities). The use
of cash is restricted by virtue of contractual restrictions with a 3(rd) party
and did not prevent the balance from meeting the definition of cash and cash
equivalents in IAS 7.
Cash at bank earns interest at floating rates based on daily bank deposit
rates. Short-term deposits are made for varying periods with original
maturities of between one day and three months at the date acquired. They are
considered to be readily convertible into cash and subject to an insignificant
risk of changes in value. The placing of deposits depends on the immediate
cash requirements of the Group and they earn interest at the respective short
to medium-term deposit rates.
The Group's exposure to credit risk arises from potential default of a
counterparty, with a maximum exposure equal to the carrying amount. The Group
seeks to minimise counterparty credit risks by only depositing cash surpluses
with major banks of high-quality credit standing and spreading the placement
of funds over a range of institutions.
Financial institutions, and their credit ratings, which held greater than 10%
of the Group's cash and short-term deposits at the balance sheet date were as
follows:
S&P/Moody's 2025 2024
credit rating $000 $000
Barclays Bank plc A-1 189 59,472
Lloyds Bank plc A-1 7,925 55,980
DNB Bank ASA P-1 7,613 32,945
HSBC A-1 15,173 -
18. Trade and Other Payables
2025 2024
$000 $000
Trade payables 31,074 40,884
Other payables 11,570 2,112
Deferred revenue 7,171 22,357
Accrued expenses 144,862 87,485
Liquids overlift 16,969 15,449
211,646 168,287
Trade payables are non-interest bearing and are generally on 15 to 30 day
terms.
Accrued expenses include accruals for operating and capital expenditure in
relation to the oil and gas assets. The Directors consider the carrying amount
of trade and other payables approximates to their fair value.
Deferred revenue includes $7.2 million (2024: $22.4 million) relating to oil
not yet delivered. $22.4 million from FY 2024 has been moved to revenue in
2025, reflecting the completion of the performance obligation.
19. Financial Liabilities
BKR Deferred Royalty
consideration consideration liability Total
$000 $000 $000 $000
At 31 December 2024 49,754 - 32,169 81,923
Acquisitions (note 30) - 8,275 - 8,275
Change in fair value liability 7,322 457 (5,308) 2,471
Payments and settlements (639) - - (639)
Transfer to accruals - - (2,107) (2,107)
Currency translation adjustment 3,790 183 - 3,973
At 31 December 2025 60,227 8,915 24,754 93,896
Classified as:
Current - 4,140 - 4,140
Non-current 60,227 4,775 24,754 89,756
At 31 December 2025 60,227 8,915 24,754 93,896
Classified as:
Current - - - -
Non-current 49,754 - 32,169 81,923
At 31 December 2024 49,754 - 32,169 81,923
BKR consideration
On 30 November 2018 Serica completed the four BKR acquisitions. The following
elements of consideration were outstanding at 31 December 2024 and 2025:
· BP, Total E&P and BHP 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 contingent 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. Serica makes annual contractual
advance stage payments to counterparties in respect of the potential deferred
consideration (see note 15) that might ultimately be due.
· Serica will pay to each of BP, Total E&P and BHP, contingent
consideration equal to 90% of their respective shares of the realised value of
oil in the Bruce pipeline at the end of field life (see note 20).
Fair value measurement of BKR contingent consideration
The fair value of the contingent consideration is estimated as at applicable
reporting dates from a valuation technique using future expected discounted
cash flows. This methodology uses several significant unobservable inputs
which are categorised within Level 3 of the fair value hierarchy.
The calculations are complex and involve a range of projections and
assumptions related to estimates of future decommissioning expenditure,
taxation, future operating and development costs, production volumes, oil and
gas sales prices and discount rates. The underlying assumptions have been
updated from 2024. Estimated contingent consideration payments have been
calculated at a discount rate of 10% (2024: 10%).
Given the multiple input variables and judgements used in the calculations,
and the inter relationships between changes in these variables, an estimate of
a reasonable range of possible outcomes of undiscounted value of the
contingent consideration has not been considered feasible. In isolation, the
calculations are most sensitive to discount rates, the timing of and estimated
decommissioning costs, and future commodity prices.
A sensitivity analysis to the discount rate used shows a decrease in the
discount rate used from 10% to 9% would result in an increase in the fair
value of the contingent consideration by $4.3 million, and an increase from
10% to 11% would result in a decrease in the fair value of the contingent
consideration by $3.8 million.
Royalty liability
Royalty represents amounts payable under a sale and purchase agreement subject
to future production volumes and commodity prices over the life of certain
assets in the Triton Cluster.
The fair value of the royalty liability is estimated as at applicable
reporting dates from a valuation technique using future expected discounted
cash flows. This methodology uses several significant unobservable inputs
which are categorised within Level 3 of the fair value hierarchy. The
calculations involve a range of assumptions related to oil prices, production
volumes and discount rates. Estimated payments have been calculated at a
discount rate of 9% (2024: 9.0%).
Given the multiple input variables and judgements used in the calculations,
and the inter relationships between changes in these variables, an estimate of
a reasonable range of possible outcomes of undiscounted value of the royalty
liability has not been considered feasible. In isolation, the calculations are
most sensitive to assumed future commodity prices, oil and gas reserves,
production profiles and estimated decommissioning costs.
A sensitivity analysis to the oil price assumption used shows a 10% increase
in the oil price assumed would result in an increase in the fair value of the
royalty liability by $7.6 million (2024: $8.8 million).
Deferred consideration
The deferred consideration represents deferred consideration totalling £7
million payable in two tranches in 2026 and 2027 in respect of the acquisition
of 100% of the shares in Parkmead (E&P) Limited (renamed Serica Energy
Norte Limited during 2025) from Parkmead Group Plc in April 2025 (see note
30). Payments have been calculated at a discount rate of 8.2%.
20. Provisions
Decommissioning Other
provision provision Total
$000 $000 $000
At 1 January 2024 148,346 412 148,758
Change in estimate (note 13) 9,711 - 9,711
Change in estimate expensed (note 5) 601 - 601
Unwinding of discount (note 8) 5,564 - 5,564
Payments (18,142) (97) (18,239)
Currency translation adjustment (421) - (421)
At 31 December 2024 145,659 315 145,974
Acquisitions (note 29) 56,480 - 56,480
Change in estimate (note 13) 41,676 - 41,676
Unwinding of discount (note 8) 6,637 - 6,637
Payments (1,088) (108) (1,196)
Additions - 987 987
Currency translation adjustment 1,748 - 1,748
At 31 December 2025 251,112 1,194 252,306
Classified as:
Current 17,518 1,194 18,712
Non-current 233,594 - 233,594
At 31 December 2025 251,112 1,194 252,306
Classified as:
Current - - -
Non-current 145,659 315 145,974
At 31 December 2024 145,659 315 145,974
Decommissioning provision
The decommissioning provision represents the present value of decommissioning
costs relating to oil and gas interests in the UK which are expected to be
incurred up to 2036.
Bruce, Keith and Rhum fields
The Group makes full provision for the future costs of decommissioning its
production facilities and pipelines on a discounted basis. With respect to the
Bruce, Keith and Rhum fields, the decommissioning provision is based on the
Group's contractual obligations of 3.75%, 8.33334% and 0% respectively of the
decommissioning liabilities rather than the Group's equity interests acquired.
The Group's provision represents the present value of decommissioning costs
which are expected to be incurred up to 2036 and assumes no further
development of the Group's assets. The liability is discounted at a rate of
4.7% (2024: 4.5%) and the unwinding of the discount is classified as a finance
cost (see note 8).
Triton area
The Triton area decommissioning provision is based on Serica group's
obligations which are in excess of certain agreed decommissioning liability
caps with the previous owners of Tailwind's equity interests in Triton. The
Group's provision represents the present value of decommissioning costs which
are expected to be incurred up to 2036 and assumes no further development of
the Group's assets. These provisions have been created based on the Group's
internal estimates and, where available, operator estimates and third-party
reports. The increase in the current year includes additions to
decommissioning provisions arising from the Belinda and Evelyn wells drilled
during 2025 and other revisions to existing estimates. These estimates are
reviewed regularly to take into account any material changes to the
assumptions. The liability is discounted at a rate of 4.7% (2024: 4.5%) and
the unwinding of the discount is classified as a finance cost (see note 8).
Orlando and Columbus fields
The Group makes full provision for the decommissioning liabilities for these
fields on its respective equity interests. The Group's provision, as at 31
December 2025, represents the present value of decommissioning costs which are
expected to be incurred between 2026 and up to 2030 and assumes no further
development of the Group's assets. The liability is discounted at rates
ranging from 3.6% to 4.1% (2024: 4.5%) and the unwinding of the discount is
classified as a finance cost (see note 8).
Erskine field
No provision for decommissioning liabilities for the Erskine field is recorded
as at 31 December 2024 or 2025 as the Group's current estimate for such costs
is under the agreed capped level to be funded by BP. This has been fixed at a
gross £174.0 million (£31.32 million net to Serica) with this figure
adjusted for inflation.
Lancaster field
The provision for decommissioning relates to the costs required to
decommission the Lancaster EPS installations and the costs required to clean,
remove and restore the Aoka Mizu FPSO at the end of the charter term. The
liability has been discounted at a rate of 3.6% and the unwinding of the
discount is classified as a finance cost (see note 8).
The assumed cessation of production ('COP') of the Lancaster field is May
2026. Decommissioning costs are expected to be incurred between 2026 to 2028,
work on the FPSO will commence shortly after COP with these costs classified
as short-term.
Other
The estimation of costs, inflation and discount rates are considered to be
judgemental and actual decommissioning costs will ultimately depend upon
future market prices for the necessary decommissioning works required, which
will reflect market conditions at the relevant time. Furthermore, the timing
of decommissioning is likely to depend on when the fields cease to produce at
economically viable rates. This in turn will depend upon future oil and gas
prices, which are inherently uncertain. If the cost estimates were increased
by 10% and the discount rate reduced by 1%, the value of the provisions could
increase by c.$45.3 million (2024: c. $30.9 million).
The Group considers the impact of climate change and Net Zero targets,
including action that may impose further requirements and costs on companies
in the future, on decommissioning provisions, specifically the timing of
future cash flows, and has concluded that it does not currently represent a
key source of estimation uncertainty. As all of the Group's currently
producing assets are projected to cease production by 2036 it is believed that
any such future changes would have limited impact compared to assets with
longer durations.
The Group has in issue £76.0 million ($102.3 million) of surety bonds to
cover its obligations under DSAs for fields and infrastructure.
21. Interest Bearing Loans and Borrowings
The Group's loan is carried at amortised cost as follows:
2025 2024
$000 $000
Reserve based lending - at 1 January 219,130 271,200
Repayments of borrowings - original facility - (271,200)
Proceeds from borrowings 51,848 283,500
Repayments of borrowings - new facility (51,848) (52,500)
RBL commitment fees on entering loan - (14,069)
Amortisation of fees (note 8) 2,358 2,199
Reserve based lending - at 31 December 221,488 219,130
Due within one year - -
Due after more than one year 221,488 219,130
221,488 219,130
The Group has a Reserve Based Lending (RBL) facility of $525 million with a
syndicate of leading international banks, with a borrowing base of $490
million, of which $231 million was drawn as at 31 December 2025 (31 December
2024: $231 million). The RBL facility is a multi-currency revolving credit
facility that provides significant liquidity to support future acquisitions
and investments.
The facility amortises on a six-monthly basis from 1 July 2027 to final
maturity on 31 December 2029. The interest rate for loan drawings is SOFR
plus a margin of 3.90% per annum and the Borrowing Base Assets comprise all of
Serica's interests in producing fields with the exception of Serica's largest
single producing field the Rhum field. The available amount under the facility
is subject to semi-annual redeterminations. The RBL includes a financial
covenant to maintain net debt/EBITDAX cover ratio below 3.5x and other terms
and conditions are consistent with Loan Market Association terms for
comparable syndicated RBL financings, with the financial covenant tested on a
biannual basis. As at 31 December 2025 Serica is fully compliant with the
financial covenant and all other terms of the facility. The facility also
includes a separate $100 million sub limit which can be utilised to issue
Letters of Credit without the need for cash security.
The facility agreement also has an uncommitted accordion feature which
provides an option for an additional financing of up to $525 million,
amounting to total facilities of up to $1,050 million. The accordion facility
can be exercised within thirty-six months of the RBL signing date of January
2024, subject to certain conditions.
During the year, the Group made drawdowns of $6 million in October 2025, £25
million in November 2025 and $13 million in December 2025, all of which were
voluntarily repaid in full in December 2025. In the prior year, an amount of
$283.5 million was drawn down from the RBL facility in January 2024 to repay a
previous RBL balance of $271.2 million as well as previous RBL interest and
fees ($1.7 million) and the main portion of RBL commitment fees ($10.6
million). These payments were made directly by the RBL banks to the relevant
parties on Serica's instructions. In February 2024, the Group made a voluntary
repayment of $52.5 million.
In December 2025, Serica completed the semi-annual redetermination under its
RBL facility. Following that redetermination, the borrowing base was confirmed
at $456 million effective 1 January 2026 with no change to the committed
facility of $525 million.
22. Financial Instruments
The Group's financial instruments comprise cash and cash equivalents, bank
loans and borrowings, accounts payable and accounts receivable, derivative
financial instruments and contingent consideration. It is management's opinion
that the Group is not exposed to significant interest, credit or currency
risks arising from its financial instruments other than as discussed below:
- Serica has exposure to interest rate fluctuations on its cash deposits
and given the level of expenditure planned over 2026/27 this is managed in the
short-term through selecting treasury deposit periods of one to three months.
Cash and treasury credit risks are mitigated through spreading the placement
of funds over a range of institutions each carrying acceptable published
credit ratings to minimise concentration and counterparty risk.
- Serica sells oil, gas and related products only to recognised
international oil and gas companies and has no previous history of default or
non-payment of trade receivables. Where Serica operates joint ventures on
behalf of partners it seeks to recover the appropriate share of costs from
these third parties. The majority of partners in these ventures are well
established oil and gas companies. In the event of non-payment, operating
agreements typically provide recourse through increased venture shares.
- Serica retains certain non-$ cash holdings and other financial
instruments relating to its operations. The $ reporting currency value of
these may fluctuate from time to time causing reported foreign exchange gains
and losses. Serica maintains a broad strategy of matching the currency of
funds held on deposit with the expected expenditures in those currencies.
Management believes that this mitigates most of any actual potential currency
risk from financial instruments.
It is management's opinion that the fair value of its financial instruments
approximate to their carrying values, unless otherwise noted.
Interest Rate Risk Profile of Financial Assets and Liabilities
The interest rate profile of the financial assets and liabilities of the Group
as at 31 December is as follows:
Group
Year ended 31 December 2025
Within 1 year 1-2 years 2-5 years Total
Floating rate $000 $000 $000 $000
Cash and restricted cash 30,900 - - 30,900
Loans and borrowings - (68,000) (163,000) (231,000)
(200,100)
Year ended 31 December 2024
Within 1 year 1-2 years 2-5 years Total
Fixed rate $000 $000 $000 $000
Short-term deposits 25,070 - - 25,070
25,070
Within 1 year 1-2 years 2-5 years Total
Floating rate $000 $000 $000 $000
Cash 123,390 - - 123,390
Loans and borrowings - - (231,000) (231,000)
(107,610)
The following table demonstrates the sensitivity of finance revenue and
finance costs to a reasonably possible change in interest rates, with all
other variables held constant, of the Group's profit before tax (through the
impact on fixed rate short-term deposits and applicable bank loans).
Increase/decrease in interest rate Effect on profit Effect on profit
before tax before tax
2025 2024
$000 $000
+0.75% (1,018) 319
-0.75% 1,018 (319)
The other financial instruments of the Group that are not included in the
above tables are non-interest bearing and are therefore not subject to
interest rate risk.
Credit risk
The Group's exposure to credit risk relating to financial assets arises from
the default of a counterparty with a maximum exposure equal to the carrying
value as at the balance sheet date. Cash and treasury credit risks are
mitigated through spreading the placement of funds over a range of
institutions each carrying acceptable published credit ratings to minimise
counterparty risk.
In addition, there are credit risks of commercial counterparties including
exposures in respect of outstanding receivables. The Group's oil and gas sales
are all contracted with well-established oil and gas or energy companies.
Also, where Serica operates joint ventures on behalf of partners it seeks to
recover the appropriate share of costs from the third-party counterparties.
The majority of partners in these ventures are well established oil and gas
companies. In the event of non-payment, operating agreements typically provide
recourse through increased venture shares. Receivable balances are monitored
on an ongoing basis with appropriate follow-up action taken where necessary.
Foreign currency risk
The Group enters into transactions denominated in currencies other than its US
dollar reporting currency. The Group's non-US dollar denominated balances,
subject to exchange rate fluctuations, at year-end were as follows:
2025 2024
$000 $000
Cash and cash equivalents:
Pounds Sterling 13,617 121,618
Norwegian kroner - -
Euros 74 269
Accounts receivable:
Pounds Sterling 103,983 78,306
Euros 217 369
Trade and other payables:
Pounds Sterling 136,834 113,081
Norwegian kroner 16 259
Euros 620 224
The following table demonstrates the Group's sensitivity to a 10% increase or
decrease in the Pounds Sterling against the US Dollar. The sensitivity
analysis includes only foreign currency denominated monetary items and adjusts
their translation at the year-end for a 10% change in the foreign currency
rate.
Effect on profit Effect on profit
before tax before tax
Increase/decrease in foreign exchange rate 2025 2024
$000 $000
10% strengthening of US$ against Pounds Sterling 1,923 31,300
10% weakening of US$ against Pounds Sterling (1,923) (31,300)
Liquidity risk
The table below summarises the maturity profile of the Group and Company's
financial assets and liabilities at 31 December 2025 based on contractual
undiscounted payments. The Group monitors its risk to a potential shortage of
funds by monitoring the maturity dates of existing debt.
As at 31 December 2025 Within 1 year 1 to 2 years 2 to 5 years >5 years Total
$000 $000 $000 $000 $000
Assets
Derivative financial assets 24,260 5,667 - - 29,927
Liabilities
Trade and other payables* 187,506 - - - 187,506
Leases 2,507 1,920 1,632 - 6,059
Loans and borrowings 21,091 84,377 174,699 - 280,167
Royalty liability - 3,671 17,461 16,312 37,444
Deferred consideration 4,171 4,978 - - 9,149
As at 31 December 2024 Within 1 year 1 to 2 years 2 to 5 years >5 years Total
$000 $000 $000 $000 $000
Assets
Derivative financial assets 5,185 - - - 5,185
Liabilities
Trade and other payables* 130,481 - - - 130,481
Leases 1,418 1,301 2,468 - 5,187
Loans and borrowings 22,920 37,036 256,728 - 316,684
Derivative financial liabilities 31,185 11,201 - - 42,386
Royalty liability - 9,123 21,725 13,870 44,718
*excludes overlift balances and deferred revenue
Amounts payable as BKR contingent consideration are explained in detail in
note 19.
Commodity price risk
The Group is exposed to commodity price risk due to the fluctuations in
prevailing market commodity prices. Where and when appropriate the Group will
put in place suitable hedging arrangements to mitigate the risk of a fall in
commodity prices as per the Group's hedging policy. This will also meet any
hedging requirements under the RBL. All gas production is currently sold at
prices linked to the spot market and the significant majority NGL production
is sold at prices linked to the spot market. Oil production for 2026 will be
sold at spot market linked pricing.
At 31 December 2025 Serica held the following hedging arrangements in place.
Oil hedges
2026 2027
Weighted Average Units Q1-26 Q2-26 Q3-26 Q4-26 Q1-27
Swap price $/bbl 75 - - - -
Collar floor net $/bbl 69 61 60 61 60
Total weighted average $/bbl 70 61 60 61 60
Collar ceiling $/bbl 85 77 76 72 69
Hedged Volume Kboe/d 4 7 5 3 3
Gas hedges
2026 2027
Weighted Average Units Q1-26 Q2-26 Q3-26 Q4-26 Q1-27
Swap price p/therm 94 - - - -
Collar floor net p/therm 83 67 65 71 71
Total weighted average p/therm 85 67 65 71 71
Collar ceiling p/therm 139 102 99 121 121
Hedged Volume Kboe/d 8 7 5 8 8
Fair values of financial assets and liabilities
Management assessed that the fair values of cash and short-term deposits,
trade receivables, trade payables and other current liabilities approximate
their carrying amounts largely due to the short-term maturities of these
instruments. As such the fair value hierarchy is not provided.
The table below details the Group's fair value measurement hierarchy for
liabilities and assets as at 31 December:
Fair value measurement using
Quoted
prices in Significant Significant
active observable unobservable
markets inputs inputs
Level 1 Level 2 Level 3
Assets/(liabilities) measured at fair value Note $000 $000 $000
Year ended 31 December 2025
Derivative financial assets 16 - 29,927 -
Contingent consideration 19 - - (60,227)
liability
Royalty liability 19 - - (24,754)
Year ended 31 December 2024
Derivative financial assets 16 - 5,185 -
Derivative financial liabilities 16 - (42,386) -
Contingent consideration liability 19 - - (49,754)
Royalty liability 19 - - (32,169)
There were no transfers between Level 1 and Level 2 during 2024 or 2025.
Capital management
The primary objective of the Group's capital management is to maintain
appropriate levels of funding to meet the commitments of its forward programme
of exploration, production and development expenditure, and to safeguard the
entity's ability to continue as a going concern and create shareholder value.
At 31 December 2025, capital employed of the Group amounted to $891.1 million
(comprised of $669.6 million of equity shareholders' funds and $221.5 million
of borrowings), compared to $1,015.6 million at 31 December 2024 (comprised of
$796.5 million of equity shareholders' funds and $219.1 million of
borrowings).
The Board regularly reassesses the appropriate dividend payments proposed
within the capital structure of the Group. Any future payment of dividends is
expected to depend on the earnings and financial condition of the Company and
such other factors as the Board considers appropriate.
23. Equity Share Capital
As at 31 December 2025, the share capital of the Company comprised one "A"
share of GB£50,000 and 393,568,407 ordinary shares of US$0.10 each. The "A"
share has no special rights.
The balance classified as total share capital includes the total net proceeds
(both nominal value and share premium) on issue of the Group's equity share
capital, comprising US$0.10 ordinary shares and one 'A' share.
Allotted, issued and Share Share Total Share Merger
fully paid: Number capital premium capital reserve
Group '000 $000 $000 $000 $000
As at 1 January 2024 391,321 39,132 206,125 245,257 283,367
Shares issued 2,147 215 65 280 3,223
As at 1 January 2025 393,468 39,347 206,190 245,537 286,590
Shares issued 100 10 168 178 -
As at 31 December 2025 393,568 39,357 206,358 245,715 286,590
During 2025, 100,000 ordinary shares were issued to satisfy awards under the
Company's share-based incentive schemes.
As at 24 March 2026 the issued voting share capital of the Company was
393,468,407 ordinary shares and one "A" share.
Group merger reserve
Merger relief was applied by the Group's parent entity Serica Energy plc upon
the respective issues of 108,170,426 ordinary shares in March 2023, 1,438,849
ordinary shares in September 2023 and 1,438,849 ordinary shares in March 2024,
for the acquisition of Tailwind Energy Investments Ltd. The valuation of the
shares issued was based on the fair value at the date of issue, with the
nominal value of the shares issued credited to share capital and the excess
value of $286.6 million (£230.3 million) above nominal share capital credited
to a merger reserve in the consolidated Group accounts.
Treasury/own shares reserve
Treasury and own shares represent Serica shares repurchased and available for
specific and limited purposes. A balance of 3,013,783 own shares (2024:
4,430,193 treasury shares) included in the reserve of $6,678,000 is held at 31
December 2025 (2024: $8,931,000). The Company purchased 4,500,000 ordinary
shares during 2025.
24. Additional Cash Flow Information
Net cash flows from operating activities consist of:
For the year ended 31 December 2025
2025 2024
$000 $000
Operating activities: Note
(Loss)/profit for the year (51,822) 92,429
Adjustments to reconcile (loss)/profit for the year
to net cash flow generated from operating activities:
Taxation charge 132,165 68,069
Change in fair value liabilities 2,471 2,538
Change in provisions 987 601
Net finance costs 29,160 23,431
Depletion and depreciation 159,186 188,320
Oil and NGL over/underlift 9,660 (20,564)
E&E asset write-offs 147 851
Unrealised hedging (gains)/losses (67,371) 31,814
Contract revenue - other (5,408) (31,292)
Share-based payments 3,523 3,735
Other non-cash movements 111 (81)
Decrease in DSA cash advances - 35,055
(Increase)/decrease in trade and other receivables (10,826) 36,170
(Increase) in inventories (7,562) (1,140)
Increase/(decrease) in trade and other payables (14,475) 22,286
Cash inflow from operations 179,946 452,222
Taxation received/(paid) 63,358 (152,517)
Decommissioning spend (1,088) (18,142)
Net cash inflow from operating activities 242,216 281,563
Reconciliation of movement in net cash flow to movement in
net cash/(borrowings)
2025 2024
$000 $000
Repayment of borrowings 51,848 323,700
Proceeds from borrowings (51,848) (283,500)
Interest and other loan finance costs paid in year 23,251 26,862
Arrangement fees - 14,069
Amortisation of fees (2,358) (2,199)
Interest and other loan finance costs payable in year (23,251) (26,862)
Movement in total borrowings (net) (2,358) 52,070
Cash acquired on business combination 21,819 -
Movement in cash and cash equivalents (154,973) (185,626)
(Increase) in net debt in the year (135,512) (133,556)
Opening net (debt)/cash (70,670) 64,233
Currency translation adjustments 3,534 (1,347)
Closing net debt (202,648) (70,670)
Analysis of Group net debt
2025 2024
$000 $000
Cash 18,840 123,390
Short-term deposits - 25,070
Loans (net) (221,488) (219,130)
Closing net debt (202,648) (70,670)
25. Share-Based Payments
Share Option Plans
The Company operates three discretionary incentive share option plans: the
Serica Energy plc Long Term Incentive Plan (the "LTIP"), which was adopted by
the Board on 20 November 2017 which permits the grant of share-based awards,
the 2017 Serica Energy plc Company Share Option Plan ("2017 CSOP"), which was
adopted by the Board on 20 November 2017, and the Serica 2005 Option Plan,
which was adopted by the Board on 14 November 2005. Awards can no longer be
made under the Serica 2005 Option Plan. However, options remain outstanding
under the Serica 2005 Option Plan. The LTIP and the 2017 CSOP together are
known as the "Discretionary Plans".
The Discretionary Plans will govern all future grants of options by the
Company to Directors, officers, key employees and certain consultants of the
Group. The Directors intend that the maximum number of ordinary shares which
may be utilised pursuant to the Discretionary Plans will not exceed 10% of the
issued ordinary shares of the Company from time to time in line with the
recommendations of the Association of British Insurers.
The objective of these plans is to develop the interest of Directors,
officers, and key employees of the Group in the growth and development of the
Group by providing them with the opportunity to acquire an interest in the
Company and to assist the Company in retaining and attracting executives with
experience and ability.
Serica 2005 Option Plan
No options were granted in 2024 or 2025 under the Serica 2005 Option Plan and
as at 31 December 2025, no options granted by the Company under the Serica
2005 Option Plan were outstanding. All options awarded under the Serica 2005
Option Plan since November 2009 had a three-year vesting period.
The following table illustrates the number and weighted average exercise
prices (WAEP) of, and movements in, share options during the year:
2025 2024 2024
Number 2025 Number WAEP
Serica 2005 option plan WAEP
£ £
Outstanding as at 1 January 300,000 0.07 800,000 0.07
Exercised during the year (300,000) 0.07 (500,000) 0.07
Outstanding as at 31 December - - 300,000 0.07
Exercisable as at 31 December - - 300,000 0.07
The weighted average remaining contractual life of options outstanding as at
31 December 2024 was 0.5 years. The weighted average share price during 2025
across the period that options were exercised in was $1.75 (2024: $2.39).
For the Serica 2005 option plan, the exercise price for all outstanding
options at the 2024 year-end was $0.09.
Long Term Incentive Plan
The following awards granted to certain Directors and employees under the LTIP
are outstanding as at 31 December 2025.
Performance Share Awards
Performance Share Awards have a three-year vesting period and are subject to
performance conditions based on average share price growth targets to be
measured by reference to dealing days in the period of 90 days ending
immediately prior to expiry of a three-year performance starting on the date
of grant of a Performance Share Award. Performance Share Awards are structured
as nil-cost options and may be exercised up until the tenth anniversary of the
date of grant.
Performance and Retention Share Awards 2025 2024
Number Number
Outstanding as at 1 January 8,142,517 9,917,330
Granted during the year 2,048,825 2,546,134
Expired or cancelled during the year (503,699) (1,297,830)
Exercised during the year (3,256,809) (3,023,117)
Outstanding as at 31 December 6,430,834 8,142,517
Exercisable as at 31 December 1,428,703 4,604,881
The weighted average remaining contractual life of options outstanding as at
31 December 2025 is 7.8 years (2024: 6.7 years). The weighted average share
price during 2025 across the period that options were exercised in was $2.01
(2024: $1.93).
LTIP awards in 2024
In May 2024, the Company granted nil-cost Performance Share Awards over
1,785,363 ordinary shares under the LTIP. The award was made to members of the
Group's executive team and senior management.
The vesting criteria include sliding scale measures of share price performance
(35% weighting) and of relative total shareholder return performance (35%
weighting), in each case, in respect of a three year period ending at the end
of April 2027; together with annual emissions intensity targets (30%
weighting) in respect of 2024, 2025 and 2026. For the awards to vest in full,
the 90 day end average share price must be at least equal to 400p, the
Company's relative total shareholder return performance must be at least upper
quartile relative performance (relative to a comparator group of companies)
and an emissions intensity target (relating to CO(2)e per barrel of oil
equivalent from the Group's entire producing portfolio of assets) met in
respect of each of 2024, 2025 and 2026. 1,462,611 of the total awards were
outstanding and are not exercisable at 31 December 2025.
In November 2024, the Company granted nil-cost Retention Share Awards over
760,771 ordinary shares under the LTIP. The award was made to members of the
Group's senior management. These awards are not subject to market conditions
and vest after three years of service by the individual. All of the total
awards were outstanding and are not exercisable at 31 December 2025.
LTIP awards in 2025
In May 2025, the Company granted nil-cost Performance Share Awards over
2,048,825 ordinary shares under the LTIP. The award was made to members of the
Group's executive team and senior management.
The vesting criteria are based on two performance conditions a) up to a
maximum of 70% of the total number of shares held under an award vest and
become exercisable subject to achievement of relative TSR performance targets,
measured at the end of a three-year performance period commencing on 1 May
2025; and b) up to a maximum of 30% of the total number of shares held under
an award vest and become exercisable, subject to the achievement of Bruce
gross emissions reduction related targets set for the last calendar year
comprised within a three-year performance period commencing on 1 January.
2,048,825 of the total awards were outstanding and are not exercisable at 31
December 2025.
Share-based compensation
The Company calculates the value of share-based compensation using a
Black-Scholes option pricing model (or other appropriate model for those
options subject to certain market conditions) to estimate the fair value of
share options at the date of grant. There are no cash settlement alternatives.
The options granted in 2024 and 2025 were consistently valued in line with the
Company's valuation policy. For the options subject to market conditions,
assumptions made included a weighted average risk-free interest rate of 4%, a
weighted average expected life of 5 years, and a volatility factor of expected
market price of in a range from 55-70%. The expected volatility reflects the
assumption that the historical volatility is indicative of future trends,
which may not necessarily be the actual outcome. The weighted fair value of
options granted during the year was $1.63 (2024: $1.68). The estimated fair
value of options is amortised to expense over the options' vesting period.
$3,523,000 has been charged to the income statement for the year ended 31
December 2025 (2024: $3,735,000) and a similar amount credited to the
share-based payments reserve, classified as 'Other reserve' in the balance
sheet. The 'Other reserve' was comprised solely of the share-based payment
reserve which totaled $41,063,000 as at 31 December 2025 (2024: $37,540,000).
A charge of $951,000 (2024: $193,000) of the total charge was in respect of
key management personnel (defined in note 7).
26. Leases
The Group holds a right of use asset for oil and gas operations (note 13) and
related lease liability. This lease is secured by the assets leased and bears
interest at a fixed rate with repayments due over a 5-year period. A
depreciation charge of $1,040,000 (2024: $1,044,000) was expensed within cost
of sales.
The Group entered into a five-year lease at its new registered office, 72
Welbeck Street, following the expiry of its previous London office lease at 52
George Street in 2024. A depreciation charge of $1,045,000 (2024: $1,070,000)
was expensed within administrative expenses in respect of office leases.
Changes in lease liabilities arising from financing activities 2025 2024
$000 $000
Lease liability at beginning of the year 5,187 2,360
Acquisitions 957 -
Additions during the year 806 5,069
Cash payments for leases (1,943) (2,697)
Lease interest expense 475 524
Currency translation adjustment 242 (69)
Lease liability at end of the year 5,723 5,187
Of which:
Current 2,308 1,418
Non-current 3,415 3,769
5,723 5,187
27. Capital Commitments and Contingencies
The Company also has obligations to carry out defined work programmes on its
oil and gas properties, under the terms of the award of rights to these
properties. The Company is not obliged to meet other joint venture partner
shares of these programmes.
Serica's planned 2026 investment programme includes further capital work on
the Bruce facilities and Triton FPSO. At 31 December 2025, the Group had
commitments for future capital expenditure relating to its oil and gas
properties amounting to $185 million.
The Group's only significant exploration commitment is the drilling of a
commitment well on Licence P2400 (Skerryvore - Serica 20%). Given the lack of
clarity regarding the future fiscal and licencing regime, the joint venture
applied for an extension to the period, and the NSTA has agreed to extend the
P2400 licence to 31 March 2027.
Serica has posted cash collateral of approximately $12.1 million under
decommissioning security arrangements which is disclosed as restricted cash.
Other
The Group occasionally has to provide security for a proportion of its future
obligations to defined work programmes or other commitments.
28. Related Party Transactions and Transactions with Directors
The Group financial statements include the financial statements of Serica
Energy plc and its subsidiaries listed in note 30. Balances and transactions
between the Company and its subsidiaries, which are related parties, have been
eliminated on consolidation and are not disclosed in this note. The related
party balances have no fixed repayment terms and bore no interest.
The Group's main related parties comprise the Directors and Mercuria Group
entities, the latter being related parties due to the significant shareholding
of a Mercuria Group subsidiary, Mercuria Holdings (UK) Limited, in Serica
Energy plc. Balances and transactions with Mercuria Energy Trading S.A., a
subsidiary of the Mercuria Group are disclosed below.
Balances with related party at year end 2025 2024
$000 $000
Mercuria Energy Trading S.A.
Trade and other payables - (4,336)
Accruals (9,793) (8,398)
Year ended 31 December 2025 Year ended 31 December 2024
Transactions in income statement with Mercuria Energy Trading S.A.
$000 $000
Revenue 115,851 181,124
Cost of sales (8,006) (6,874)
Loss on commodity derivative contracts - (1,155)
Finance costs - (24)
The above transactions were conducted under contracts already in place when
Serica acquired Tailwind Energy Investments Ltd on 23 March 2023, principally
the Offtake and Marketing Agreement covering oil offtake from Serica's share
in the Triton area and part of Serica's share in Columbus. These contracts
were set on prevailing market terms.
Transactions with North Sea Midstream Partners Limited ('NSMP') are also
considered related party transactions with effect from 1 July 2024, when a
director assumed a key management personnel position within Serica Energy plc
and a close member of his family held a key management position within NSMP
during 2024. The Group incurred pipeline tariff costs of $13.0 million
recorded within cost of sales in 2024 and had a trade payable of $2.0 million
owed to NSMP at 31 December 2024. The close family member of the director no
longer held the key management position within NSMP in 2025 and transactions
with NSMP during 2025 are not considered related party transactions.
There are no related party transactions, or transactions with Directors that
require disclosure except for the remuneration items disclosed in the
Directors Report and note 7 above. These disclosures include the compensation
of key management personnel.
29. Acquisition of Prax Upstream Limited
Overview of transaction
On 11 December 2025, the Company completed the acquisition of 100% of the
shares of Prax Upstream Limited (PUL) for a purchase consideration of $19.6
million and as a result of this acquisition Serica now holds a 100% operated
interest in the Lancaster Field. The activities acquired comprise a production
oil & gas asset in the West of Shetland Area that is capable of managing
the provision of goods and generating income from its activities, and as it is
therefore considered to constitute a business as defined in IFRS 3 Business
Combinations, the acquisition is accounted for as a business combination.
At the acquisition date PUL was party to separate executed Sale and Purchase
Agreements ('Existing SPAs') with TotalEnergies and ONE-Dyas for the purchase
of certain assets for base consideration payable of $1 and $6.75 million
respectively. The base consideration in both transactions will be adjusted by
customary completion adjustments in the interim period. The Existing SPAs are
subject to standard partner and regulatory approvals, and post completion,
expected in H1 2026, Serica will hold a 40% operated interest in the Greater
Laggan Area ('GLA'), 10% interest in the Catcher Field, 5.21% interest in the
Golden Eagle Development ('GEAD').
Acquisition of PUL - assets acquired and liabilities assumed
The consolidated 2025 financial statements included the fair values of the
identifiable assets and liabilities as at the date of acquisition 11 December
2025, and the results of the combined transaction assets for the three-week
period from the acquisition date.
Assets acquired and liabilities assumed at date of acquisition Provisional Fair value
recognised on
acquisition
$000
Assets
Property, plant and equipment (note 13) 1,877
Net deferred tax asset (note 9) 6,654
Debtors, prepayments and other assets 4,824
Inventory 8,410
Restricted cash 12,060
Cash and cash equivalents 21,819
55,644
Liabilities
Trade and other payables 35,120
Lease liabilities (note 26) 957
Provisions (note 20) 56,480
92,557
Total identifiable net liabilities at fair value (36,913)
Cash consideration 19,584
Other consideration -
Purchase consideration 19,584
Provisional goodwill on acquisition 56,497
The cash inflow on acquisitions is as follows:
Cash consideration paid (19,584)
Cash acquired with subsidiary 21,819
Net cash inflow on acquisition 2,235
Fair value of consideration
The combined purchase consideration of the transaction was $19.6 million
(£14.8 million), which comprised cash of $19.6 million (£14.8 million).
The excess of the purchase consideration over the provisional fair value of
the net liabilities assumed was recognised as provisional goodwill in the 2025
balance sheet. Debtors and other assets included in the total identifiable net
assets at fair value were equivalent to gross contractual amount receivables.
The provisional fair value assets and liabilities identified at acquisition do
not include future value that Serica expects to generate from future events
being the completion of the Existing SPAs (including synergies). Serica did
not own or control the assets and liabilities associated with the existing
SPAs as at the date of acquisition of PUL as the SPAs were still subject to
standard partner and regulatory approvals. Serica is not recognising deferred
tax assets that are contingent on controlling those assets.
The provisional goodwill recognised can primarily be attributed to post
completion value that Serica believes will crystallise upon completion of the
existing SPAs including the potential benefits of additional tax losses which
have not been recognised on acquisition of PUL. The Total SPA is expected to
complete at the end of March 2026 and the One-Dyas SPA in June 2026. No
element of goodwill is expected to be deductible for income tax purposes and
is unallocated at year end and will be reviewed and finalised in the next
year.
The purchase price allocation remains provisional as permitted by IFRS 3. The
fair value of identifiable assets and liabilities may be adjusted within the
measurement period of up to one year from the acquisition date and therefore
finalised in Serica's full year 2026 financial statements.
From the date of acquisition, the Prax assets contributed $nil of revenue and
a loss of $1 million to profit before tax from continuing operations of the
Group. If the combination had taken place at the beginning of the year, PUL
would have contributed $130.5 million of revenue for the year ended 31
December 2025. Management consider that it is impractical to assess the impact
on profit before tax if the acquisition had completed on 1 January 2025. Prior
to its acquisition by Serica, PUL's parent entity was in administration and
PUL's pre-acquisition results include significant administration process
related and other exceptional items that do not permit a reliable
reconstruction on a basis consistent with the Group's accounting policies.
Transaction costs of $4.2 million were incurred in 2025 and expensed in the
income statement. Other transaction costs of $1.3 million were incurred in
2025 on the separate acquisition of assets from Spirit Energy which was
announced on 16 December 2025 and expected to complete in 2026.
30. Acquisition of asset interests
Acquisition of Parkmead E&P Limited
In April 2025, Serica Energy (UK) Limited acquired 100% of the shares in
Parkmead (E&P) Limited (renamed Serica Energy Norte during 2025) from
Parkmead Group Plc ('Parkmead'), an entity holding a 50% working interest in
licence P2400 (Skerryvore) and a 50% working interest in licence P2634 (Fynn
Beauly). The transaction provides optionality regarding future projects,
simplifies decision making, and provides strategic flexibility relating to the
existing position in Skerryvore through consolidating the interests in the
P2400 licence, in which Serica Energy (UK) Limited already holds a 20%
interest. Following completion of the transaction, Serica holds 70% and is the
operator. The P2634 licence was awarded in the 33rd Licencing Round in July
2024 to Parkmead (E&P) Limited, as operator, and Orcadian Energy, and
includes the Fynn Beauly heavy oil discovery. The current licence commitment
is limited to technical studies to assess the feasibility of reducing Fynn
Beauly oil viscosity using enhanced oil recovery techniques.
The acquisition was made for the following consideration.
- An initial consideration of £7 million ($9.1 million).
- An additional deferred consideration of £7 million ($9.1 million) to be
paid in stages over 2026 and 2027
- Contingent consideration which comprises contingent payments linked to
certain development milestones - payable on receipt by Serica of approval by
the North Sea Transition Authority ('NSTA') for a field development plan
('FDP') relating to Skerryvore or Fynn Beauly. These payments are calculated
based on £0.8/bbl of net 2P reserves contained within the respective FDP,
subject to a cap of £30 million and £90 million respectively.
The transaction was treated as an asset acquisition as it did not include
relevant supplementary and other substantive activities beyond the assets
acquired to be considered a business combination. The amounts of initial and
deferred consideration and minor other costs are recorded as an Exploration
and Evaluation asset acquisition cost of $19.4 million (see note 12).
Serica's accounting policy (see note 2) in respect of this asset acquisition
is that the cost of asset on initial recognition excludes any variable or
contingent payments. Accordingly, no liability is currently recognised for
those contingent amounts dependent on FDP approvals and the quantification of
net 2P reserves at that time, which will not be known until respective FDP
approvals.
Acquisition of interest in Greater Buchan Area
In February 2024, Serica Energy (UK) Limited acquired JOG Fox Limited (renamed
Serica GBA Limited during 2024), an entity holding 30% non-operated interests
in the P2498 and P2170 licences (together the Greater Buchan Area from Jersey
Oil & Gas ('JOG'). The interests were subsequently transferred to Serica
Energy (UK) Limited in October 2024. The partners in the GBA are Serica Energy
(UK) Limited (30%), NEO Energy (50% and operator) and JOG (20%). This
transaction gives Serica the option of participating in the re-development of
the Buchan field and other potential developments in the GBA. The transaction
was treated as an asset acquisition as it did not include relevant
supplementary and other substantive activities beyond the assets acquired to
be considered a business combination.
The transaction is structured as a farm-in, with modest up-front consideration
payments, a carry of pre-Financial Investment Decision ("FID") and development
costs, and modest contingent consideration payments.
In return for a 30% working interest in the GBA licences, on completion Serica
made a cash payment to JOG of $7.7 million (£6 million) which reflected
adjustments between buyer and seller to reflect an economic date for the
transaction of 1 April 2023. This amount is recorded as an Exploration and
Evaluation asset acquisition cost (see note 12). Serica is not committed under
the terms of the transaction to participate in the GBA developments.
In the event of participation at each relevant stage, Serica will make further
payments to JOG as follows:
· $7.5 million on approval of the Buchan Horst FDP by the NSTA
· A 7.5% carry of the Buchan Horst field pre-FID and development costs
(paying 37.5% for a 30% working interest). The development cost carry is
capped at 7.5% of the budget approved by the Buchan Joint Venture for the
development of the Buchan Horst field at the time of the FDP. Subject to the
cap, the development cost carry equates to a 1.25 carry ratio for development
costs; the same as an arrangement previously agreed between JOG and NEO Energy
· $3 million on approval by the NSTA of a J2 FDP
· $3 million on approval by the NSTA of a Verbier FDP
Serica's accounting policy (see note 2) in respect of this asset acquisition
is that the cost of asset on initial recognition excludes any variable or
contingent payments dependent on FDP approvals. Accordingly, no liability is
currently recognised for those contingent amounts.
31. Subsidiaries
The Group and the Company (unless indicated) had investments in the following
subsidiaries as follows:
Name of company: Holding Nature of business % voting rights and shares held % voting rights and shares held
2025 2024
Serica Holdings UK Ltd (ii) Ordinary Holding 100 100
Serica Energy Investments Limited (ii) Ordinary Holding 100 100
Serica Energy Holdings BV (i & iii) Ordinary Holding 100 100
Serica Energy (UK) Ltd (i & ii) Ordinary E&P 100 100
NSV Energy Limited (v) Ordinary Holding - 100
Serica Energy Meltemi Limited (i & ii) Ordinary E&P 100 100
Serica Energy Sirocco Limited (v) Ordinary Holding - 100
Serica Energy Chinook Limited (i & ii) Ordinary E&P 100 100
Serica Energy Mistral Limited (i & ii) Ordinary E&P 100 100
Serica Energy Bora Limited (v) Ordinary E&P - 100
Serica Energy Corporation (i & iv) Ordinary Dormant 100 100
APD Ltd (v) Ordinary Dormant - 100
PDA Asia Ltd (v) Ordinary Dormant - 100
Serica UK Exploration Limited (i & ii) Ordinary Dormant 100 100
Serica GBA Limited (i & ii) (note 30) Ordinary Dormant 100 100
Serica Energy Norte Limited (i & ii) Ordinary E&P 100 -
Prax Upstream Limited (ii) Ordinary E&P 100 -
Prax Hurricane Basement Limited (i & ii) Ordinary Dormant 100 -
Prax Hurricane GLA Limited (i & ii) Ordinary E&P 100 -
Prax Hurricane Group Limited (i & ii) Ordinary Dormant 100 -
Prax Hurricane GWA Limited (i & ii) Ordinary E&P 100 -
Prax Hurricane Holdings Limited (i & ii) Ordinary Holding 100 -
Prax Hurricane Petroleum Limited (i & ii) Ordinary Dormant 100 -
Prax Hurricane (Strathmore) Limited (i & ii) Ordinary Dormant 100 -
Prax Hurricane (Whirlwind) Limited (i & ii) Ordinary E&P 100 -
(i) Held by a subsidiary undertaking
(ii) Incorporated in the UK
(iii) Incorporated in the Netherlands
(iv) Incorporated in the British Virgin Islands
(v) Entity struck off in year
The registered office of Serica Holdings UK Limited, Serica Energy (UK)
Limited, Serica Energy Investments Limited, Serica Energy Meltemi Limited ,
Serica Energy Mistral Limited, Serica UK Exploration Limited, Serica GBA
Limited, Prax Upstream Limited, Prax Hurricane Basement Limited, Prax
Hurricane GLA Limited, Prax Hurricane Group Limited, Prax Hurricane GWA
Limited, Prax Hurricane Holdings Limited, Prax Hurricane Petroleum Limited,
Prax Hurricane (Strathmore) Limited and Prax Hurricane (Whirlwind) Limited is
4(th) Floor, 72 Welbeck Street, London, W1G 0AY.
The registered office of Serica Energy Chinook Limited and Serica Energy Norte
Limited is H1 Building, Hill of Rubislaw, Anderson Drive, Aberdeen, AB15 6BY.
The registered office of the Company's subsidiaries incorporated in the
Netherlands is Hoogoorddreef 15, 1101 BA Amsterdam, The Netherlands.
The registered office of Serica Energy Corporation is P.O. Box 71, Road Town,
Tortola, British Virgin Islands.
32. Events Since Balance Sheet Date
There have been no events since the balance sheet date that require
disclosure.
Serica Energy plc
Registered Number: 05450950
Company Balance Sheet
As at 31 December 2025
2025 2024
Note $000 $000
Non-current assets
Property, plant and equipment 3,202 3,977
Investments in subsidiaries 3 588,637 525,803
591,839 529,780
Current assets
Trade and other receivables 4 210,155 123,456
Cash and cash equivalents 5 2,945 85,870
213,100 209,326
TOTAL ASSETS 804,939 739,106
Current liabilities
Trade and other payables 6 16,166 11,147
Leases 3,005 3,512
TOTAL LIABILITIES 19,171 14,659
NET ASSETS 785,768 724,447
Share capital 7 210,444 210,266
Merger reserve 7 398,762 398,762
Other reserve 7 41,063 37,540
Treasury/own shares 7 (6,678) (8,931)
Accumulated funds 92,572 89,325
Currency translation reserve 49,605 (2,515)
TOTAL EQUITY 785,768 724,447
The profit for the Company was $100.2 million for the year ended 31 December
2025 (2024: $157.2 million).
Approved by the Board on 25 March 2026
Chris Cox
Martin Copeland
Chief Executive Officer
Chief Financial Officer
Serica Energy plc
Company Statement of Changes in Equity
For the year ended 31 December 2025
Share capital Merger reserve Other reserve Accum'd funds Total
Company Treasury/ own Shares Currency translation reserve
$000 $000 $000 $000 $000 $000 $000
As at 1 January 2025 210,266 398,762 37,540 (8,931) (2,515) 89,325 724,447
Profit for the year - - - - - 100,172 100,172
Exchange differences on translation - - - - 52,120 - 52,120
Total comprehensive income - - - - 52,120 100,172 152,292
Share-based payments - - 3,523 - - - 3,523
Issue of share capital (note 8) 178 - - - - - 178
Treasury shares/own shares - - - (9,819) - - (9,819)
Release of shares - - - 12,072 - (12,072) -
Dividend paid - - - - - (84,853) (84,853)
At 31 December 2025 210,444 398,762 41,063 (6,678) 49,605 92,572 785,768
At 1 January 2024 209,986 395,539 37,650 - 9,465 51,473 704,113
Profit for the year - - - - - 157,236 157,236
Exchange differences on translation - - - - (11,980) - (11,980)
Total comprehensive income - - - - (11,980) 157,236 145,256
Share-based payments - - 3,735 - - - 3,735
Issue of share capital (note 8) 280 3,223 - - - - 3,503
Treasury shares - - - (18,775) - - (18,775)
Release of shares - - - 9,844 - (9,844) -
Share payments - - (3,845) - - 3,845 -
Dividend paid - - - - - (113,385) (113,385)
At 31 December 2024 210,266 398,762 37,540 (8,931) (2,515) 89,325 724,447
1. Corporate information
The Company's financial statements for the year ended 31 December 2025 were
authorised for issue by the Board of Directors on 25 March 2026 and the
balance sheet was signed on the Board's behalf by Chris Cox and Martin
Copeland. Serica Energy plc is a public limited company incorporated and
domiciled in England & Wales with its registered office at 4(th) Floor, 72
Welbeck Street, London, W1G 0AY. The principal activity of the Company and its
subsidiaries (together the 'Group') is to identify, acquire and subsequently
exploit oil and gas reserves.
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 2025.
The Company financial statements have been prepared on a historical cost basis
and presented in US dollars. The Company's functional currency remains as
Pounds Sterling. All values are rounded to the nearest thousand US dollars
($000) except when otherwise indicated.
These separate financial statements have been prepared in accordance with
Financial Reporting Standard 101, 'Reduced Disclosure Framework' ('FRS 101')
and the Companies Act 2006. The Company meets the definition of a qualifying
entity under FRS 100, 'Application of Financial Reporting Requirements' as
issued by the Financial Reporting Council. The Company, as permitted by FRS
101, has taken advantage of the disclosure exemptions available under that
standard in relation to share-based payments, financial instruments, fair
value measurement, capital management, presentation of comparative information
in respect of certain assets, presentation of a cash flow statement, standards
not yet effective, impairment of assets and related party transactions. Where
relevant, equivalent disclosures have been given in the Group accounts.
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 of the parent Company was $104,208,000 (2024:
$157,236,000).
Going concern
The Directors' assessment of going concern concludes that the use of the going
concern basis is appropriate and the Directors have a reasonable expectation
that the Group, and therefore the Company, will be able to continue in
operation and meet its commitments as they fall due over the going concern
period. See note 2 of the Group financial statements for further details.
Critical accounting estimates and judgements
The management of the Company has to make estimates and judgements when
preparing the financial statements of the Company. Uncertainties in the
estimates and judgements could have an impact on the carrying amount of assets
and liabilities and the Company's results.
The most important judgements and estimates in relation thereto are:
Impairment of investments in subsidiaries
Management is required to assess the carrying value of investments in
subsidiaries in the parent company balance sheet for impairment. This requires
a judgement whether impairment triggers exist that might lead to the
impairment of investments in subsidiaries. If a trigger is identified then the
assessment for impairment requires an estimate of amounts recoverable from the
underlying subsidiaries considering the oil and gas assets within them and
their associated liabilities.
Investments
In its separate financial statements the Company recognises its investments in
subsidiaries at cost less any provision for impairment.
Trade and other receivables and contract assets
Provision for expected credit losses of trade receivables and contract assets
The Company holds inter-company loans with subsidiary undertakings with
repayment dates being repayable on demand. These inter-company loans are
disclosed on the face of the balance sheet. None are past due nor impaired.
The carrying value of these loans approximates their fair value. The expected
credit loss on these loans with subsidiary undertakings is expected to be
immaterial, both on initial recognition and subsequently.
Financial instruments
Equity
Equity instruments issued by the Company are recorded in equity at the
proceeds received, net of direct issue costs.
Treasury/own shares
The Company's holdings in its own equity instruments are shown as deductions
from shareholders' equity. Treasury shares represent Serica shares repurchased
and available for specific and limited purposes. For accounting purposes,
shares held in Employee Benefit Trusts to meet the future requirements of the
employee share-based payment plans are treated in the same manner as treasury
shares and are, therefore, included in the Company's financial statements as
treasury/own shares. The cost of treasury shares subsequently sold or reissued
is calculated on a weighted-average basis. Consideration, if any, received for
the sale of such shares is also recognised in equity. No gain or loss is
recognised in the income statement on the purchase, sale, issue or
cancellation of equity shares.
Foreign currencies
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 are
charged to the income statement.
The Company has a functional currency of GBP£ sterling but from 1 January
2024 changed the presentational currency to US$ for its financial statements.
Items are translated into the presentation currency as follows:
· Assets and liabilities for each balance sheet presented are
translated at the closing rate at the date of that balance sheet;
· Income and expenses for each income statement are translated at
average exchange rates (unless this average is not a reasonable approximation
of the rates prevailing on the transaction dates, in which case income and
expenses are translated at the rate on the dates of each transaction).
· The exchange differences arising on translation are recognised in
other comprehensive income.
3. Investments
Total
Company - Investment in subsidiaries $000
Cost:
At 1 January 2024 534,808
Revisions (811)
Currency translation adjustment (8,194)
At 31 December 2024 525,803
Acquisitions 23,792
Currency translation adjustment 39,042
At 31 December 2025 588,637
Provision for impairment:
At 1 January 2024, 31 December 2024 and 31 December 2025 -
Net book amount:
At 31 December 2025 588,637
At 31 December 2024 525,803
At 1 January 2024 534,808
2025 acquisition of Prax Upstream Limited
The Company completed the acquisition of Prax Upstream Limited in December
2025 (see note 29 of the Group financial statements) for $23.8 million
comprising consideration and other transaction costs.
2023 acquisition of Tailwind Energy Investments Ltd
Merger relief was applied by the Company upon the issue of ordinary shares in
2023 for the acquisition of Tailwind Energy Investments Ltd. The valuation of
the shares issued was based on the fair value at the date of issue, with the
nominal value of the shares issued credited to share capital and the excess
value above nominal share capital credited to a merger reserve in the Company
accounts (see note 7).
Details of the investments in which the Company's subsidiaries are provided in
note 31 of the Group financial statements.
Historic reorganisation
In the Company financial statements, the cost of the investment acquired on an
historic reorganisation in 2005 was calculated with reference to the market
value of Serica Energy Corporation as at the date of the reorganisation. As a
UK company, under Section 612 of the Companies Act 2006, the Company is
entitled to merger relief on its share reorganisation with Serica Energy
Corporation, and the excess of £88,088,000 over the nominal value of shares
issued (US$7,475,000) was credited to a merger reserve. The merger reserve is
adjusted for any write-down in the value of the investment in subsidiary.
4. Trade and Other receivables
2025 2024
$000 $000
Due within one year:
Amounts owed by Group undertakings 206,375 121,776
Other receivables 3,780 1,680
210,155 123,456
At the reporting date the amounts owed by Group undertakings to the Company
are disclosed net of an impairment of $nil (2024: $nil). These amounts have
not been secured, have no maturity and bear no interest.
The Company holds inter-company loans with subsidiary undertakings being
repayable on demand. The carrying value of these loans approximates their fair
value. The expected credit loss on these loans with subsidiary undertakings is
expected to be immaterial, both on initial recognition and subsequently.
5. Cash and cash equivalents
2025 2024
$000 $000
Cash at bank and in hand 2,945 60,800
Short-term deposits - 25,070
Cash and cash equivalents 2,945 85,870
6. Trade and Other Payables
2025 2024
$000 $000
Current:
Amounts owed to Group undertakings 8,944 8,205
Trade payables 749 1,262
Other payables 1,315 1,358
Accrued expenses 5,158 322
16,166 11,147
Accrued expenses in 2025 include amounts payable for transaction costs from
the Company's acquisition of Prax Upstream Limited.
7. Equity Share Capital and Reserves
As at 31 December 2025, the share capital of the Company comprised one "A"
share of GB£50,000 and 393,568,407 ordinary shares of US$0.10 each. The "A"
share has no special rights.
The balance classified as total share capital includes the total net proceeds
(both nominal value and share premium) on issue of the Company's equity share
capital, comprising US$0.10 ordinary shares and one 'A' share.
Allotted, issued and fully paid: Share Share Total
Number capital premium Share capital
Company '000 $000 $000 $000
As at 1 January 2024 391,321 39,132 170,854 209,986
Shares issued 2,147 215 65 280
As at 1 January 2025 393,468 39,347 170,919 210,266
Shares issued 100 10 168 178
As at 31 December 2025 393,568 39,357 171,087 210,444
Company merger reserve
Merger relief was applied by the Company upon the issue of ordinary shares for
the acquisition of Tailwind Energy Investments Ltd in 2023. The valuation of
the shares issued was based on the fair value at the date of issue, with the
nominal value of the shares issued credited to share capital and the excess
value above nominal share capital credited to a merger reserve in the Company
accounts.
Treasury/own shares reserve
A balance of 3,013,783 shares (2024: 4,430,193) included in the reserve of
$6,678,000 is held at 31 December 2025 (2024: $8,931,000). The Company
purchased 4,500,000 ordinary shares during 2025.
Other reserve
The 'Other reserve' was comprised solely of the share-based payment reserve
which totaled $41,063,000 as at 31 December 2025 (2024: $37,540,000).
8. Auditor's remuneration
Fees payable to the Company's auditor for the audit of the Company and Group
financial statements are disclosed in note 6 of the Group financial
statements.
9. Directors' remuneration
The emoluments of the Directors are paid to them in their capacity as
Directors of the Company for qualifying services to the Company and the Group.
Further information is provided in note 7 of the Group financial statements.
The directors do not believe it is practicable to apportion these amounts
between their services as directors of the Company and their services as
directors of the operating group subsidiary entities.
Reconciliation of non-IFRS measures
Serica uses certain measures of performance that are not specifically defined
under IFRS or other generally accepted accounting principles ('GAAP'). These
non-IFRS measures, which are presented within the financial review, are
defined below:
EBITDAX: Earnings before interest, tax, depreciation and amortisation,
impairments, transaction costs, unrealised hedging expenses, FX translation
effects, asset revaluation effects, other non-cash gains or expenses and
exploration expenditure. This is a useful indicator of underlying business
performance and the definition adopted by Serica is consistent with that
stipulated in the Group's reserve based lending ("RBL") facility. A
reconciliation from Operating Profit to EBITDAX is provided below:
$000 2025 2024
Operating Profit 111,974 186,467
Add Back Transaction Costs 5,533 -
Add Back DD&A 158,141 187,250
Add Back Depreciation in G&A 1,045 1,070
Add Back E&E Expenses and licence costs 1,247 2,446
Deduct contract revenue - other (5,408) (31,292)
Add Back/(Deduct) Unrealised Hedging (67,371) 31,814
(Deduct)/Add Back FX Effects/Remeasurements 949 (2,633)
Add back share based payments 3,523 3,735
EBITDAX 209,633 378,857
Capital Expenditure (Capex and Abex): Comprises the cash spend (prior to tax
allowances) on the acquisition of PP&E assets, the purchase of exploration
and appraisal assets and decommissioning spend. Depicts how much the Group has
spent, on a cash basis, on purchasing fixed assets in order to further its
business goals and objectives. It is a useful indicator of the Group's organic
expenditure on oil and gas assets, and exploration and appraisal assets,
incurred during a period on a pre-tax basis.
$000 2025 2024
Purchase of PP&E Assets 242,567 249,050
Purchase of E&E Assets 6,467 11,123
Decommissioning Spend 1,088 18,142
Capital Expenditure 250,122 278,315
Adjusted CFFO less tax: comprises Cash inflow from Operations adjusted by the
current tax charge for the year as reflected in Note 9 and also excludes cash
movement arising from the return or posting of security deposits for
decommissioning and hedging. Serica considers that this is a useful measure of
the cash generation of the business after tax charge more directly related to
the activity of the period, prior to the decisions made by the Group in
relation to capital allocation.
$000 2025 2024
Cash inflow from operations 179,946 452,222
Less current tax (excluding prior year adjustments) - (14,191)
Changes in DSA advances - (35,055)
Adjusted CFFO less tax 179,946 402,976
Free cash flow: net cash flow from operating activities less cash used in
investing activities (excluding acquisition costs) and financing activities.
This measure is considered a useful indicator of the Group's ability to
invest, repay the Group's debt and meet other payment obligations. Group free
cash flow reconciles to net cash flow from operating activities as follows:
$000 2025 2024
Net cash flow from operating activities 242,216 281,563
Net cash flow from investing activities (253,033) (253,911)
Net cash flow from financing activities (122,337) (213,278)
Adjusted by:
Repayment of loans and borrowings (net) - 40,200
Facility fees and interest - 12,300
Proceeds from issue of shares (net of costs) (178) (280)
Payment of dividends 84,853 113,385
EBT/Share buyback 9,819 18,775
Acquisition and transactions costs 15,018 -
Free Cash flow (23,642) (1,246)
Adjusted Net cash / (debt): Total cash and cash equivalents plus restricted
cash on the consolidated balance sheet less the drawn balance under RBL. This
is an indicator of the Group's indebtedness and contribution to capital
structure.
$000 2025 2024
Interest bearing loans (221,488) (219,130)
Add back unamortised fees (9,512) (11,870)
Cash and cash equivalents 18,840 148,460
Restricted cash 12,060 -
Adjusted Net (Debt) (200,100) (82,540)
GLOSSARY
AIM Alternative Investment Market
bbl barrel of 42 US gallons
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
CFFO Cashflow from Operations
CGU Cash Generating Unit
COP Cessation of Production
CPR Competent Persons Report
CSOP Company Share Options Plan
DD&A Depreciation, Depletion and Amortisation
DTA Deferred Tax Asset
EBITDAX Earnings Before Interest Depreciation Amortisation and Exploration
EBT Employee Benefits Trusts
ECL Expected Credit Loss
E&E Exploration & Evaluation
EPL Energy Profits Levy
ETS Emissions Trading Scheme
FID Final Investment Decision
FDP Field Development Plan
FPSO Floating Production and Storage and Offloading
GAAP Generally Accepted Accounting Practices
GBA Greater Buchan Area
GLA Greater Laggan Area
GMA Greater Markham Area
IFRS International Financial Reporting Standards
JOA Joint Operating Agreement
LSE London Stock Exchange
LTIP Long Term Incentive Plan
M&A Mergers & Acquisitions
mmbbl million barrels
mmboe million barrels of oil equivalent
MOL Main Oil Line
NBP National Balancing Point
NGLs Natural gas liquids extracted from gas streams
NSTA North Sea Transition Authority
NTS National Transmission System
OGPM Oil & Gas Price Mechanism
Overlift Volumes of oil or NGLs sold in excess of volumes produced
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
PPA Purchase Price Allocation
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
RBL Reserves Based Loan
Reserves Estimates of discovered recoverable commercial hydrocarbon reserves calculated
in accordance with the revised June 2018 Petroleum Resources Management System
(PRMS) version 1.01
SPA Sale and Purchase Agreement
Underlift Volumes of oil or NGLs produced but not yet sold
UKCS United Kingdom Continental Shelf
1 (#_ftnref1) The 2P 2025 Reserves and 2C 2025 Contingent Resources for all
assets except West of Shetland are based on an independent evaluation carried
out by RISC, effective 31 December 2025. The 2P 2025 Reserves for West of
Shetland are based on an independent evaluation by Sproule ERCE, effective 31
December 2025
2 (#_ftnref2) The 2P 2025 pro forma figures include the 2P 2025 Reserves and
2C Contingent Resources evaluated by RISC and Sproule ERCE, as well as figures
for assets that have been acquired but are pending completion. The figures for
these assets are unaudited, based on independent evaluations by Sproule ERCE,
effective 30 June 2025 for the TotalEnergies and ONE-Dyas transaction assets
(West of Shetland and Other Production Assets, respectively) and 31 December
2024 for the Spirit Energy transaction assets (Southern North Sea), adjusted
for 2025 production
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