2025 full-year results

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 and 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	[phone]
Martin Copeland (CFO) / Andrew Benbow (Head of Investor Relations)
Peel Hunt (Nomad & Joint Broker)	[phone]
Richard Crichton / David McKeown / Emily Bhasin
Jefferies (Joint Broker)	[phone]
Sam Barnett / Cameron Jones
Vigo Consulting (PR Advisor)	[phone]
Patrick d'Ancona	[e-mail]

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. 

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.

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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.

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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]	2P 2025 pro forma[2]	2P 2024	2C 2025	2C 2025 pro forma	2C 2024
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	Treasury/own shares	Currency translation reserve	Accumulated funds	Total
		$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 £000	2024
	$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  liability	19	-	-	(60,227)
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:

Serica 2005 option plan	2025 Number	2025 WAEP	2024 Number	2024 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 Number	2024 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 CO₂e 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)

Transactions in income statement with Mercuria Energy Trading S.A.	Year ended 31 December 2025	Year ended 31 December 2024
	$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

Company	Share capital	Merger reserve	Other reserve	Treasury/ own Shares	Currency translation reserve	Accum'd funds	Total
	$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 CSOP	Competent Persons Report 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 FID FDP	Emissions Trading Scheme Final Investment Decision 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] 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] 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

 

END