2024 full-year results

Serica Energy plc

('Serica' or 'the Company')

Results for the year ended 31 December 2024

London, 1 April 2025 - Serica Energy plc (AIM: SQZ), a British independent upstream oil and gas company with operations in the UK North Sea, today announces its audited financial results for the year ended 31 December 2024. The results are included below and copies are available at www.serica-energy.com and www.sedar.com.

Chris Cox, Serica's CEO, stated:

"The highly positive results of the drilling campaign at Triton are not yet being reflected in our production and cashflow due to ongoing issues at the Triton FPSO. Our frustration is exacerbated by the fact that the Triton area alone could be delivering up to 30,000 boepd net to Serica with the addition of the wells already drilled.

We are confident, after detailed discussions with the Operator, Dana, of the work required to fix the issues, and we are pleased that the joint venture has agreed a plan to take advantage of the current downtime to bring forward the maintenance work scope originally scheduled for July. This removes the need for a summer maintenance shutdown, which combined with the activities undertaken should significantly increase uptime going forward.

I have previously stated my confidence in the excellence of the Serica subsurface team and the potential of the rocks across our portfolio, and we have increasing clarity on the work needed to convert that potential into shareholder value. Ongoing analysis has seen a small decrease in our 2P reserves but materially increased our 2C resources - and there is more to come as work continues. This indicates the strength of our organic pipeline, with a clear route to converting resources to reserves - the Kyle redevelopment looks particularly attractive, and multiple infill drilling opportunities around the Bruce Hub have been identified.

With the above in mind, we have elected to implement a prudent rebalancing of our capital allocation approach, giving us increased flexibility over the medium-term to allocate capital to the areas where it will deliver best value for shareholders. This adjustment will allow us to invest in the exciting drilling and development programmes in our portfolio and be opportunistic in accretive M&A, all while retaining our highly competitive shareholder distributions." 

Results summary ($ million unless stated)

1 2023 figures are pro forma following the completion of Tailwind acquisition on 23 March 2023

2 Includes pre-FID expenditure on E&E assets

3 Net of unamortised fees; See Reconciliation of non-IFRS measures

4 Attributable shareholder returns reflects Interim and Final Dividends in respect of the relevant year plus quantum of share buybacks

Highlights

Working to deliver more reliable and predictable production

· Production of 34,600 boepd in 2024 (2023 pro forma: 40,100 boepd), of which 64% was gas, impacted by unscheduled downtime at the Triton FPSO

· Production of c.27,600 boepd in Q1 2025, at a reduced level due to the shutdown of the Triton FPSO in February and March

· Following discussions with Dana Petroleum, the operator, the Triton joint venture partners have decided to bring forward the summer maintenance period, integrating it into the current work programme

- This will deliver increased uptime for the remainder of the year versus previous expectations

- Production from Triton is now expected to resume in June, with no further planned shutdowns in 2025

- The availability of the second compressor upon resumption will also mitigate the cause of instability that impacted 2024

Positive subsurface results set to boost production

· With our ongoing drilling programme, Serica was one of the most active operators of development drilling in the UK North Sea last year and remains so in 2025

· Initial results from this drilling activity have been encouraging, and the Triton FPSO produced over 25,000 boepd net to Serica on 23 January 2025, the day prior to production halting in the aftermath of Storm Éowyn, boosted by production from the first two wells in the five well Triton drilling campaign, Bittern B6 and Gannet GE05

· Drilling on the subsequent two wells, the W7Z well on the Guillemot North West field (Serica: 10%) and the EV02 well on the Evelyn field (Serica: 100%), is now complete, with both wells showing encouraging results

- W7Z is set to be hooked up for production shortly after the restart of production, with EV02 to then follow

· The COSL Innovator rig has now relocated and drilling has begun on the BE01 well on the Belinda field (Serica 100%), the final well of the campaign, with first production expected in early 2026

Material increase in 2C resources

· 2P reserves of 117.5 mmboe as at end-2024 (140 mmboe at end-2023), broadly evenly split between oil (55.1 mmboe) and gas (62.4 mmboe), following production of 12 mmboe in 2024

· Rigorous subsurface reassessment of the portfolio, focused on identifying deliverable opportunities, has resulted in a material increase in 2C resources to 88.7 mmboe at end-2024 (30.3 mmboe at end-2023), with the potential to convert significant resources into reserves in the medium-term

· Work is continuing across the portfolio to high-grade the identified opportunities, with capital allocation to focus on those projects that can deliver maximum value to shareholders

Profitable and cash generative despite active investment programme

· Profit before tax of $160 million (2023: $380 million) with reduction largely reflecting lower volumes sold and slightly reduced realised pricing largely driven by lower realised gas prices and increased gas mix (2024 61% gas as compared to 2023 pro forma 51%)

· Profit after tax of $92 million (2023 $128 million) reflecting a lower P&L tax rate benefitting from the combined impact of loss pool and active capital investment programme

· Adjusted CFFO less tax increased on the prior year to $403 million in 2024 (2023: $250 million), as a result of a significantly lower current tax charge in 2024 due to group relief effects resulting from the Q4 Triton performance

· Cash tax paid in 2024 of $153 million (2023: $348 million)

- Group relief in 2024 led to an overpayment of cash tax under the Instalment Payment Regulations. This will result in a $71 million cash tax rebate in 2025

· No cash tax payment was made in the January 2025 instalment, and Serica expects significantly reduced cash tax payments in 2025

Robust balance sheet and continued tax losses shelter supports investment in growth and returns

· Peer leading Balance Sheet strength with year-end leverage (Adjusted Net Debt to EBITDAX) of 0.2x (2023: Net Cash)

· No near-term expenditure on decommissioning activities, with year-end decommissioning provision of $146 million maintaining Serica's position as having the lowest decommissioning liability per 2P boe compared to all our UK and wider North Sea peers5

· As at 31 December 2024, Serica retained over $1 billion of recognised ring fence tax losses resulting in a year end Deferred Tax Asset of $577 million; upon completion of the Parkmead (E&P) Limited ('Parkmead') acquisition Group tax losses will be increased by c.25%

· Cash of $141 million as at latest practicable date of 27 March 2025 (31 December 2024: $148 million), with borrowings of $219 million, essentially flat Net Debt from year end notwithstanding the continued capex programme and lack of Triton production in February and March

· Final dividend declared today of 10 pence per share (2023: 14 pence per share) subject to approval at Serica's 2025 AGM

- The final dividend is payable on 25 July 2025 to shareholders registered on 27 June 2025, with an ex-dividend date of 26 June 2025

· Final dividend equates to an estimated $50 million6, bringing total shareholder returns in respect of 2024 to $114 million (including interim dividend of $45 million and $19 million of share buybacks), consistent with the comparable figure for 2023 of $112 million

- The Company has elected to adjust the final dividend as part of a prudent rebalancing of the capital allocation mix

- This rebalancing enhances flexibility to allocate capital to those areas where it will deliver best value for shareholders, combining a highly competitive level of shareholder returns with investment in exciting growth opportunities and retaining a resilient financial frame

- Serica additionally retains capacity within its shareholder authorities to carry out further share buybacks as part of its capital allocation strategy and will look to renew these authorities at its 2025 AGM 

Focused and disciplined value accretive M&A strategy

· Acquisition of Parkmead announced in December, providing optionality regarding future projects and bringing with it carried forward tax loss balances. The deal is moving towards completion, with NSTA consent now received

· The Company continues to be very active in screening cash-generative and value accretive M&A opportunities in both the UK North Sea and other geographies. Serica will remain disciplined and will only conclude transactions with a demonstrable investment case and potential to deliver material value to shareholders

Outlook and guidance

· Following operational issues at Triton in Q1, production guidance for 2025 has been amended to 33,000-37,000 boepd

- With maintenance work at the Triton FPSO set to complete in June, and no summer shutdown to then follow, portfolio production in H2 is forecast to be materially ahead of the full-year 2025 guidance range

· Capital expenditure and opex guidance unchanged, at $220-250 million and c.$330 million respectively

· Poised for material cash flows, supporting Serica's strategy and track record of delivering direct returns of capital to investors through a mixture of a material dividend and, selectively, share buy backs

· Work is ongoing regarding a potential move from the AIM to the Main Market of the LSE in 2025

5Serica defines its peers as listed independent E&P companies with material asset positions in the UK, Norway and Denmark

6 Approximated based on 10p per share and TVR ex Treasury shares as of 7 March and US$:GBP FX rate of 1.29

Regulatory

This announcement is inside information for the purposes of Article 7 of Regulation 596/2014.

The technical information contained in the announcement has been reviewed and approved by Fergus Jenkins, VP Technical at Serica Energy plc. Mr. Jenkins (MEng in Petroleum Engineering from Heriot-Watt University, Edinburgh) is a Chartered Engineer with over 25 years of experience in oil & gas exploration, development and production and is a member of the Institute of Materials, Minerals and Mining (IOM3) and the Society of Petroleum Engineers (SPE).

Enquiries:

Serica will host a live presentation on the Investor Meet Company platform today at 0900 BST. 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. 

CHAIR'S STATEMENT

I am pleased to introduce my second set of results as the Chair of Serica Energy. 2024 was a year in which we accomplished a great deal, but it was not without its challenges both internally and externally. It was a year in which we delivered a tremendously successful drilling programme, but we experienced unplanned outages that hit our production, and of course meant that our revenues did not benefit as they should have done. It was also a year in which uncertainty about government policies dominated the political landscape for operators in the UK North Sea, something on which there have been recent tentative signs of changing for the better. During the year, we also saw a significant change in the management team, and I am confident that we have the right team to drive the Company forward and thrive in the face of current challenges.

UK political challenges

The adverse impact of multiple increases and extensions to the Energy Profits Levy ('EPL') in the last few years can be seen in the decline of production and activity in the UK North Sea. During 2024 the new Labour Government was formed, promising a further increase in the tax burden for UK oil and gas producers further eroding investor confidence in the long-term prospects of the basin. Although a small increase in the overall tax rate to 78% did materialise, the government listened to the industry's representations and preserved 100% first-year tax allowances for capital investment. This was essential with the alternative being a rapid curtailment of a valuable national resource.

The energy debate is sometimes posited as a choice between domestically produced oil and gas and renewable sources. The fact is that the UK needs all of the above. Homegrown oil and gas supports quality jobs in our communities, enhances the UK's security, enables an equitable energy transition, and generates government tax revenues. Serica alone has paid over £500 million of tax during the last five years.

Between now and achieving net zero in 2050, the Climate Change Committee's energy transition pathway estimates that the UK will need 13-15 billion barrels equivalent of oil and gas, during which period the UK is projected to import more than half its essential oil and gas requirements. Although production from the UK North Sea is in decline, the steepness of that decline is in part due to government policies over recent years. Of the barrels that the UK needs, only an estimated four billion are set to be produced in the North Sea, worth an estimated value of £200 billion to the UK economy. This figure could rise to seven billion barrels with supportive fiscal and regulatory frameworks in place, generating a further estimated £150 billion for the UK. Oil and gas in the UK North Sea remains a very valuable national resource and it is common sense to prioritise its exploitation over imports.

At the time of writing, the UK Government has recently launched two formal consultations on UK North Sea licensing and taxation. In addition, we await the outcome of the consultation on guidance for Environmental Impact Assessments for new projects. The combined impact of these three processes will be pivotal in determining the future of the North Sea and we hope that the government pursues policies that are consistent with, rather than effectively negate, the decision to retain full first-year tax allowances for investment.

I am proud of the role Serica is playing in the country's energy debate. We have been and will continue to be at the forefront of the industry in speaking up in favour of homegrown oil and gas. A Town Called Bruce, the film we helped create with the GMB, illustrated the positive impact that we and our peers have on jobs and communities throughout the UK. As someone who has spent over three decades in the industry, I found the film both moving and inspiring. My thanks go to all those who contributed to creating the film. It can be found on our website and I thoroughly recommend a watch.

Heading into 2025, I am more positive on the direction of government policy than I was a year ago, but we are not out of the woods yet.

A new phase of Serica Energy, with a new team

We continue to remain prudent in how we allocate capital, and indeed are adjusting our framework in this regard with these results, focusing our capital spend where we see investment in our organic portfolio delivering rapid returns. Early production from the first two wells of the five due to be drilled in the Triton area has delivered excellent technical results and is a testament to our team's capabilities. A key focus is now on working with the operator of the Triton FPSO to make sure that we translate the excellent subsurface performance into sustaining strong production and cashflow.

Serica is continuing to evolve as a company. We started with our AIM listing some 20 years ago this year, with a very small team, trying and succeeding in growing the Company through innovative transactions. We are now moving into a new phase where we are cementing ourselves as a proven operator, focused on safety, operational delivery and GHG emissions reduction, and looking for other opportunities to become the operator of more assets, diversifying our portfolio and making it more robust, while retaining a balanced commodity mix. In this respect, it is fitting that we are also looking to move our listing to the main LSE market later this year.

As we move into this phase, the Board was delighted to appoint Chris Cox as CEO. Chris joined in July, bringing the experience of running a multi-asset business, understanding the necessary maintenance of similarly mid-to-late life fields, and delivering organic growth and building companies.

As we seek to grow further, we were also very pleased that Martin Copeland joined the business as CFO. Martin has the ability, energy and experience to identify and execute value-accretive M&A transactions, with the Parkmead acquisition an excellent example of a small but smart transaction, to optimise and deliver value from our portfolio. The importance of increasing our scale, but above all the diversification of our sources of production and revenue base, has been made only more apparent given the operational challenges we witnessed in Q4 2024 and the early part of 2025. We are continuing our drive for further diversification of our asset base, which we believe will allow us to deliver a more predictable and reliable financial performance - but we will only transact if we are convinced that doing so will deliver value to Serica's shareholders.

Building a stronger company

There remain challenges ahead, but I am confident that Serica is in a stronger position today than at any other point in its history. We have assets with the potential to generate significant cash, an attractive production mix of oil and gas, and a highly experienced management team and Board, with a strategy of optimising mid-to-late life assets in a way that has the potential to deliver significant shareholder value.

We continue to be very active in pursuing multiple M&A opportunities in both the UK North Sea and other geographies, firmly focused on deals that we believe will be accretive to shareholder value. As we seek to diversify and further strengthen the Company, we intend to retain a strong balance sheet to keep us resilient to uncertain future events, with the expectation of material cash generation going forward and multiple organic opportunities in which to allocate capital. Our confidence in our future prospects supports the ongoing payment of a substantial dividend, and the Board is pleased today to confirm a final distribution in respect of 2024 of 10 pence per share, bringing the total dividend for 2024 to 19 pence per share and overall shareholder distributions equivalent to 23 pence per share, in line with returns related to the 2023 financial year, when we also factor in the inaugural share buyback executed during the year.

The prudent rebalancing of our dividend reaffirms our commitment to material direct shareholder returns, takes into account the deferred revenues due to operational issues in 2024, and ensures that we retain liquidity to take full advantage of the many organic and inorganic opportunities ahead. As we do this, work is ongoing regarding a potential move from the AIM to the Main Market, which would increase our visibility and bring our investment story to the widest possible pool of investors. Serica is well positioned in the current environment, and I firmly believe that the best is yet to come.

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CHIEF EXECUTIVE OFFICER'S REVIEW

Since joining Serica in July, it would be fair to say that there have already been some ups and downs, and a couple of things that have surprised me. The first is the quality of the subsurface properties of our asset base. The number, and quality, of the opportunities for drilling more wells and accessing reserves at both BKR and in the Triton area is exceptional given the maturity of the assets and the fact that they have been operated in the past by major companies.

I have also been delighted with the team that we have in place to mature and deliver these opportunities. We effectively have the best of both from Serica and the team acquired from Tailwind, some of whom I was delighted to know from when I worked with them at BG. They are great at what they do, with the right people in the right roles, deploying key technologies in the right way, and they can be a real differentiator going forward. The tremendous results of the Triton drilling campaign illustrate what can still be achieved in delivering growth in our basin.

Of course, what we have not seen to date is our high-quality subsurface assets delivering appropriate production, cash flows, and in turn value to our shareholders. This has been disappointing and, put simply, our assets are not producing what they could be. While the majority of these issues have been on Triton, where Serica is not the operator, we are doing everything we can to work with the operator to ensure, as far as possible, that the issues that have caused the poor uptime of the FPSO do not happen again. The value we have created through the drill-bit is very much there, but it is being left in the ground, and we need to, and will, do more to stop this from happening.

Delivering value from mid-to-late life assets

Serica has the ability to continue delivering value from our portfolio of mid-to-late life assets, and the team is working hard to strengthen further a culture of performance excellence. This starts with safety, and everyone taking pride of ownership of their sphere of influence. The leadership team is totally committed to the safe running of operations, and we firmly believe that excellence in this area will also help deliver the production performance of which our asset base is so clearly capable.

This aspect was the other main surprise to me on coming into the Company - just how much more can be achieved from our current asset base if it can be made to run to its true potential. To date, there have been too many outages at Triton, and at BKR there is also very much the potential to do more and to optimise production. But this is a good problem to have - it is clearly far preferable to have a positive subsurface, with work to be done on facilities, than it is to have great facilities and bad rocks. We know the issues we face, and how to fix them - in contrast, you can't fix what nature has dealt you under the ground.

I have spent most of my career dealing with and managing the challenges of mid-to-late life assets, and it is not always straightforward. Facilities are designed to handle a particular flow rate and a particular type of fluid at a particular pressure, and these change over time. By the time they get to late life, fields are often producing a fraction of the fluid volumes for which they were designed, a lot of water may be coming through, and lower pressures mean facilities don't perform in the same way. These assets need care and attention, including detailed, well-planned and executed maintenance programmes. The operator needs to get the basics right, make sure everything runs within appropriate and optimised parameters, replace what is needed before it fails, and it is then entirely possible to ensure that the facilities are able to run safely and efficiently often well past their original design lives. This is hard, focused work but it is deliverable. We have the hydrocarbons, and we have the potential to continue supporting UK North Sea production for many years to come.

As part of our drive to increase reliability and performance, we are refining our structure in terms of operational roles and making sure the right people are laser focused on the right things. Amongst other high-quality appointments in key strategic roles, we are set to take on a Production Optimisation Manager imminently, tasked with helping to convert the subsurface quality into optimised production and cash flows.

The Triton area drilling campaign is a great illustration of the quality of our people. We have completed four wells out of five on Triton, with four positive results, and we will work hard to get the facilities functioning as they should to deliver this new production reliably. To have multiple wells come in that exceed pre-drill expectations and produce clean oil really is a fantastic outcome. We are confident that the fifth one to come, Belinda, will also be a good well, and we are excited by the value that could be unlocked now that the same subsurface team is turning its attention to the wider portfolio.

Opportunities ahead

We have announced today a material increase in our 2C resources to 89 mmboe, and the work done on our BKR hub to identify opportunities is not yet complete. At BKR our initial focus is on Bruce. Re-processed 3D seismic data is helping to unlock Bruce potential, and the team has built the first full field 3D simulation model. We have already identified multiple drilling opportunities, and while not all of those will turn out to be economic, as we do more work on them and run simulation models, we will high-grade the opportunity set throughout this year to create options for 2026 and beyond. No new wells have been drilled on Bruce since 2012 and new techniques and technologies can help access previously undrained and untargeted areas, and I look forward to updating you on our plans for BKR as they come together later in the year.

Given the ongoing lack of clarity over the long-term fiscal regime pending the outcome of the current consultations, our focus is largely on maturing possible infill drilling programmes, where these promise a similarly rapid payback to our Triton area drilling campaign. The retention of first year allowances in the Autumn Budget has allowed us to accelerate spend on resilience enhancement measures at both the Bruce Hub and on the Triton FPSO, and the Flare Gas Recovery project at Bruce qualifies for the decarbonisation allowance, meaning its c.$10 million cost will be more than fully offsetable against our tax liability. This will help our ongoing efforts regarding GHG emissions, with our carbon intensity from Bruce of 17.0 kgCO2/ boe in 2024 remaining below the UKCS average of 21 kg CO2/boe.

However, should the government provide clarity on a long-term fiscal and regulatory environment that supports the UK North Sea in providing a homegrown solution to the UK's hydrocarbon demand, then we have larger projects in the portfolio with the potential to deliver organic growth that would offset natural decline in our portfolio into the next decade.

Our next development project could be Kyle. Kyle is a redevelopment of an old field that was abandoned because its host infrastructure was removed. We were awarded the licence in the 33rd licence round run by the last government in October 2023, and it is a classic example of the kind of hidden potential that we hope the ongoing licensing consultation will address. Kyle was a new licence for us, but it has discovered hydrocarbons able to add material value to an existing hub, and we very much hope that the government will continue to allow new licences in similar circumstances. Kyle is very close to Triton and can be easily tied back via a single well development with the potential to convert over 11 mmboe of 2C resources into reserves. Wells in the reservoir have produced oil from it in the past and were still producing when the field was abandoned. Beyond Kyle, we have options in the Buchan Horst redevelopment, and what we hope to be multiple further exciting drilling opportunities around Bruce.

Resilience through diversification

As we seek to deliver organic growth, further asset diversification would also be a real positive for us, reducing the extent of our vulnerability to any future operational issues at one of our two main hubs. The chance to achieve further diversification from our existing portfolio is therefore attractive, while we continue to seek meaningful additions through M&A. Our current focus is on the UK, where we are well placed to act as a consolidator in what remains a buyer's market. The soon to be completed Parkmead acquisition was a small deal but one that adds real value to Serica. We think there is more to come in the UK. We are also keen to find value creating opportunities to provide geographical diversification that, despite the improving tone of government policy signals, will reduce our dependence on a single political jurisdiction.

As we continue to run the rule over multiple opportunities, we will also take care of our base business and make sure that our assets run better than they clearly have in 2024 and 2025 year to date and deliver the value of our current portfolio. As we seek to grow the Company, we are aware that we need to prove to our shareholders that we are a top-tier operator that can be trusted to utilise your capital to deliver value from our assets. And we will.

Material cash generation

With all assets producing, our portfolio is capable of delivering over 50,000 boepd. Issues at Triton during the first quarter which, albeit different, compound on the challenges of Q4 2024, mean that we have been a long way from our production potential in the first quarter, and our production guidance for 2025 has today been set at a revised range of 33,000 to 37,000 boepd. Given the potential flow rates, a period of stable production will help us to strive for the top end of this range.

With a robust gas price and stable oil price, and our sizeable carried forward loss position at Triton providing a tax shelter from Corporation Tax and Supplementary Charge, we are confident that future production can deliver material free cash flow. This should enable us to fund our organic growth prospects, while also allowing us to continue delivering healthy returns to our shareholders.

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REVIEW OF OPERATIONS

Reserves and resources

Serica's assets contained 117.5 mmboe of 2P oil and gas reserves net to the Company as of 31 December 2024 (31 December 2023: 140 mmboe), with a broadly even split between oil (55.1 mmboe) and gas (62.4 mmboe). 2P reserves include, for the first time, 5.6 mmboe of gas that will be produced to fuel production assets.

1 boe figures have been determined using field specific calorific values for gas. The methodology has been updated from previous years, which used an industry standard conversion factor for gas from all fields

The reduction in reserves reflects production of 12 mmboe in 2024, as well as the result of a rigorous reassessment of well performance and opportunities across the portfolio. This, combined with the continued uncertainties of the fiscal and regulatory backdrop, resulted in the deferral of planned drilling of the SCE/SCW wells on BKR, with 2P reserves reduced by 9.5 mmboe. However, the same technical reassessment has high-graded other potential prospects, albeit not to a level of maturity necessary to constitute reserves as at 31 December 2024.

The result of the subsurface work undertaken in 2024 has though delivered a material upgrade in resources, with the clear potential to move a proportion of these from 2C to 2P as work continues to mature opportunities towards investment decisions. We are now reporting 88.7 mmboe of 2C resources (31 December 2023: 30.3 mmboe), of which the Greater Buchan Area, into which our farm-in transaction completed in February 2024, comprises 30.0 mmboe. Notable other opportunities across the portfolio include the addition of 11.1 mmboe relating to the Kyle redevelopment, and work at Bruce has resulted in the Company booking an additional 11.8 mmboe of 2C resources - with work ongoing that has the potential to see this figure increase further and/or be converted to reserves.

The Company continues to pursue a returns-led approach to organic investment, investing in its assets to add value through increased production, decarbonisation through reduced emissions, and the extension of field life. The current work programme, with its focus on the five-well Triton drilling campaign, has the ability to sustain production above an annual average of 40,000 boepd well into 2026. Plans for the resumption of drilling around BKR, and potentially the redevelopment of Kyle and Buchan Horst, can boost reserves, increase production, and further illustrate our ability to identify value-adding opportunities in a mature basin, and in turn create significant shareholder value.

Production net to Serica (boepd)

Bruce Hub

Bruce Field - Blocks 9/8a, 9/9b and 9/9c, Serica 98% and operator

Rhum Field - Blocks 3/29a, Serica 50% and operator

Keith Field - Block 9/8a, Serica 100%

Production at the Bruce Hub averaged 19,800 boepd in 2024, a small increase on 2023. Production was robust in H1, with the Bruce Hub averaging 23,400 boepd ahead of the summer maintenance programme. Q4 was then impacted by a short period of unscheduled downtime on the Bruce platform, related primarily to a subsea intervention and consequent pause in production necessary to ensure enhanced longer-term production reliability on the Rhum field. 

On a field level, the Bruce Hub 2024 LWIV campaign undertaken with the Helix Well Enhancer was successfully completed in May, and the summer programme of Bruce field platform work included a range of activities designed to enhance production as well as routine integrity monitoring. Production at Bruce averaged 6,000 boepd in the year (2023: 6,500 boepd).

A number of minor projects are set to be undertaken in 2025 which will help improve resilience and efficiency, all managed by our soon to be appointed Production Optimisation Manager, helping to maximise the performance of BKR.

Looking further ahead, extensive subsurface work is ongoing to identify and rank opportunities for infill drilling. A number of opportunities have been uncovered, not all of which are included in the 2C resources of 33.4 mmboe now booked on Bruce. Work will continue to high-grade these prospects and deliver a drilling programme, with the potential for drilling to resume on the field from late 2026, which would be the first since 2012.

The Rhum field produced consistently and in line with expectations, with minimal capital work, in the first half of 2024. Necessary subsea intervention work to install a hydraulic override tool and address an issue with the R3 well resulted in Q4 not meeting our expectations. Average field production in 2024 totalled 13,800 boepd (2023: 12,500 boepd) of gas net to Serica. Limited capital expenditure is expected at Rhum in 2025, with well scale removal to improve well delivery under consideration.

Work in H1 2025 is focused on improving production rates, with an operational failure on the productive R3 well impacting production in March from the field. Work to increase resilience will now be undertaken ahead of the resumption of production from the K1 well on the Keith field, which has not produced since 2022.

The annual maintenance shutdown at the Bruce Hub will take place in Q3 and is scheduled to last for 12 days.

Triton Hub

Bittern 64.63%, Evelyn 100%, Gannet E 100%, Guillemot West & North West 10%, Belinda 100%

The Triton Hub experienced a mixed 2024 - where positive subsurface results were achieved from infill well drilling, but production was disappointing due to a number of unplanned outages that resulted in a year-on-year average production decline from 14,100 boepd to 9,000 boepd.

The first shutdown in May followed a trip on the single gas export compressor that was available, a weakness that continued throughout 2024, causing another significant outage in Q4 commencing from 26 October. Production was also adversely impacted by the summer shutdown for annual maintenance work on Triton overrunning by three weeks.

Unfortunately, problems have continued into the start of 2025, as issues resulting from Storm Éowyn caused production to be suspended at the end of January. Safety critical maintenance was scheduled following damage to a storage tank, and then integrity issues were discovered in pipework which is used to inject inert gas into the cargo tanks. Following an investigation into the causes, Dana inspected all piping and valves in the inert gas/gas free venting system to the cargo oil tanks, resulting in a more significant work scope being undertaken to replace whole sections of pipework in this system on the FPSO.

In order to reduce overall downtime this year, following discussions with Dana, the decision was made to bring forward the scheduled summer maintenance programme and carry it out concurrently with the ongoing work. Through integrating the work programmes it removes the downtime inherent in shutting down and restarting the plant for a separate maintenance periods, which alone adds around two weeks of production potential. The work scope for the maintenance programme has been optimised to fit the current schedule, and production is expected to resume in June and then have no planned downtime for the remainder of the year.

Immediately prior to this late-January shutdown, production from Triton achieved rates of 25,000 boepd net to Serica, with production from wells at Guillemot North West and Evelyn still to come. An amendment to mode of operation in start up of the gas export compressors appears to have solved the repeated issue with the gas seal system that impacted 2024. The second compressor will also be brought into commission once the FPSO is back up and running and this, together with the current work being completed, should help to deliver more consistent and reliable uptime, and hence production rates, going forward.

Serica continues to work closely with the operator, Dana, to ensure that maintenance work is delivered in a way that will see enhanced reliability at Triton. Serica employees have been reviewing the plans of the operator's team, which has itself been enhanced in recent months. Discussions also continue with Dana regarding options for the future of the FPSO, with a view to securing a lasting improvement in the operating performance. As confirmed by a third-party review undertaken by the engineering firm Kent, the FPSO itself is structurally sound, with no material issues found with its key systems, those being the double hull, turret or swivel, and with continued and timely maintenance the Triton FPSO has the potential to produce 2035 and potentially beyond.

The outages have meant that Serica's production has not yet truly benefitted from the tremendous results of the first wells in the five-well Triton drilling campaign.

The first well completed was the B6 horizontal well (a sidetrack from the B1 well) on the Bittern field, which entered production in September at a rate of over 5,000 boepd net to Serica. This very positive result was then followed by the Gannet GE05 well, which was tied in to the Triton FPSO on 25 October, under budget and ahead of time, and was brought onto stable production at a rate of over 6,000 bopd after the late 2024 outage period, in January.

The outage of the FPSO in Q1 2025 did not adversely affect the drilling work. The W7Z well on the Guillemot North West field is set to be brought onto production following the resumption of production on the FPSO, and the EV02 on the Evelyn field, drilled on time and under budget, is set to follow shortly after restart. EV02 has shown similarly promising signs to the other wells in the campaign, a further endorsement of our subsurface team's ability to enhance production and deliver value from mid-to-late life fields.

The COSL Innovator rig has now moved to drill the final well in the campaign, the BE01 well on the Belinda field (SQZ: 100%). Drilling began on 20 March and the well is forecast to enter production in early Q1 2026, following the drilling and installation of subsea infrastructure required for Belinda as a new field development.

Other Production Assets

Erskine Field - Blocks 23/26a (Area B) and 23/26b (Area B), Serica 18%

Erskine averaged 1,200 boepd net to Serica in 2024 (2023: 1,325 boepd), in what was very much a year of two halves. Production issues during H1 2024 led to production averaging 500 boepd net to the Company, following a compressor problem on the host Lomond platform. Production was re-established in early May, but taken offline shortly thereafter for the planned Lomond turnaround. Since the restart of production on 26 August, the field produced consistently at a rate of well over 2,000 boepd net to Serica. A late life compression project to extend the life of the field is planned to be carried out this year.

Columbus Field - Blocks 23/16f and 23/21a (part), Serica 75% (operator)

During the first half of 2024, Columbus production was steady, averaging 1,800 boepd net to Serica in H1. Following maintenance in Q3, which resulted in no production in that quarter, production resumed in October, averaging 2,000 boepd in Q4 and 1,400 boepd for 2024 as a whole (2023: 2,180 boepd).

Orlando Field - Block 3/3b, Serica 100%

Orlando produced steadily in 2024, averaging 3,300 boepd net to Serica (2023: 3,500 boepd). Production has also begun steadily in Q1, ahead of a scheduled shut-in of 28 days, originally planned for late October for annual maintenance on its host platform Ninian, which began in March 2025.

Development

Kyle Redevelopment (P2616), Serica (Operator) 100%

The Kyle Redevelopment, located in Block 29/2c, is a previously producing oilfield, 20 km southeast of Triton, which was shut-in in 2020 solely due to the decommissioning of the Banff FPSO host facility. Kyle presents a potential redevelopment opportunity with a single horizontal well tied-back to Triton via Bittern, similar to other Triton tie-backs.

Ongoing technical work since Serica was awarded the licence in the 33rd Licence Round in October 2023 has led to an enhanced understanding of the subsurface, and our work to date has upgraded the Company's view of the potential of the asset. Subsurface and front-end design work tenders are now set to be issued later this year. With the appropriate fiscal and licensing environment, there is the potential for first oil in 2028 on a project that could be approximately twice the size of Belinda, carrying over 11 mmboe of 2C resources. 

Greater Buchan Area - Blocks 20/5a, 205d, 21/1d & 21/1a, Serica 30%

In February 2024 Serica completed the acquisition of a 30% working interest in the Greater Buchan Area ('GBA') licences P.2498 and P.2170 with co-venture partners Jersey Oil & Gas (20%) and NEO Energy (50% and operator). The GBA encompasses several proven oil and gas accumulations - including Buchan Horst - and exploration prospects, some 150 km north-east of Aberdeen in the Outer Moray Firth.

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 and includes the possibility of powering the facilities from offshore wind to achieve UKCS leading low carbon emissions.

The viability of the project depends in large part on the future UKCS fiscal and regulatory regimes which are currently subject to government consultations.

Exploration assets

Skerryvore - Blocks 30/12c (part), 30/13c (split), 30/17h, 30/18c and 30/19c (part), Serica 20% working interest

The P2400 Licence is located in the Central North Sea, 60 km south of the Erskine field. Serica will take on the operatorship of the asset on completion of our acquisition of Parkmead's 50% holding in the licence, with CalEnergy holding the remaining 30%. The commitment work programme includes drilling an exploration well on the Skerryvore prospect by the end of September 2025. However, given the lack of clarity regarding the future fiscal and licensing regime, the joint venture has applied for an extension to the licence period.

----------------------

FINANCIAL REVIEW

Our financial performance in 2024 was impacted by the production issues experienced at Triton, which resulted in a material loss of production and revenue, albeit that our after tax results benefited from a substantial reduction in the tax charge in 2024 as compared to 2023.

Combining this with a year of material capital expenditure on our new wells in the Triton area 2024 was essentially neutral on a free cash flow basis. However, even though Q1 2025 has also witnessed unrelated production downtime at Triton, we view these as temporary issues that should not impact Serica's ability to continue delivering on our strategy. We retain a strong balance sheet with very low net debt and decommissioning liabilities, and an outlook that generates material free cash flow in coming years, enabling us to have capital allocation optionality to sustain our production and deliver returns for shareholders while retaining resilience for unforeseen events.

Capital allocation priorities

The United Kingdom continues to have an oil and gas tax rate that is unsuitable for a mature oil and gas basin, and the industry urgently needs clarity regarding the future regime to enable long-term investments to be made with confidence. The implementation of the new regime cannot wait, as the government currently intends, until 2030. Serica will be playing its part in responding to the recently launched consultations on the future tax regime and licensing and we expect to learn the outcome of these as well as the already concluded environmental consents consultation later in the year. Until this uncertainty is removed, will remain prudent in our capital allocation, focused on completing the tax-efficient, short-cycle investments in our portfolio which are delivering rapid returns.

Our investment in 2024 and continuing into 2025 has focused on the Triton drilling campaign, where individual wells can pay back comfortably within a year. In 2024, $260 million pre-tax capex was allocated towards drilling at Triton as well as some well intervention activity at BKR and certain pre-FID costs on our E&E assets. We are very pleased with the drilling results funded by this investment, and once steady production from the Triton FPSO is restored the wells drilled in 2024 will boost production and revenues.

Although the new government increased the headline tax rate to 78% and removed the EPL Investment Allowances, the Autumn Budget did importantly retain first year capital allowances at 100%. The retention of full expensing (in common with all other sectors of the UK economy) means that short-cycle investments will likely continue to deliver positive returns, and we expect them to remain a key component of our capital allocation priorities going forward. We expect pre-tax capex to be in the range of $220-250 million in 2025, with the majority of spend focused on the continuation of the Triton drilling programme, including the more extensive subsea work required for our Belinda development, where drilling has just commenced. Our subsurface team continue to mature other opportunities across the portfolio, especially in the Bruce area, and we are hopeful of being able to mature further infill opportunities enabling us at least to offset natural decline in the near-term.

The combined effect of our investment programme and the associated capital allowances, together with continuing to retain over $1 billion pool of ring-fence losses, materially benefitted our tax position in 2024. Although the blended headline tax rate in 2024 increased to 75.5% from 75% in 2023, as a result of the 3% increase in the EPL rate from 1 November, our book tax rate reduced from 66% in 2023 to 42% in 2024. Although we paid cash tax in 2024 of $153 million (2023: $348 million) our current tax charge for the year, before adjustment in respect of prior years, was reduced to only $14 million (2023: $226 million). This sharply reduced current tax charge reflected the impact of investment and capital allowances but, most materially, for the first time, also incorporated group relief for in year losses of the subsidiaries which hold our Triton area field interests being applied against the tax charge at our BKR entity.

The combination of these effects has also meant that our tax loss pool remained essentially unchanged at just over $1 billion dollars at 31 December 2024 (2023: $1 billion). In addition, following completion of the Parkmead acquisition we would expect to extend this tax shield by approximately a further $250 million of carried forward tax losses.

We now expect our loss pool to provide shelter for our Triton production through to the end of the decade and will continue to explore options to accelerate this use where possible.

Robust balance sheet

Our balance sheet remains robust, with material cash generation expected once we have Triton back onstream, enabling us to combine investment in sustaining and growing production with maintaining our strong track record of returning capital to shareholders. The resilience of this strategy for the delivery of shareholder value was illustrated in 2024, as we returned $132 million to investors, inclusive of dividends and share buyback, while investing approximately twice that amount in the portfolio, notwithstanding the production challenges we experienced especially in the latter part of the year.

Our liquidity position remains comfortable following the December redetermination of our RBL as well as available cash, and gives us material optionality over our expenditure, as we continue to invest in organic growth and seek M&A that will deliver further value to shareholders.

Change in presentational currency

Following the acquisition of Tailwind, which completed in March 2023, and the refinancing of the Group's RBL in January 2024, as communicated at the time of our 2024 half-year results, the Directors elected to change the Group's presentational currency from Pounds Sterling to US Dollars with effect from 1 January 2024. The Group believes that the presentational currency change will give investors and other stakeholders a clearer understanding of Serica's performance over time and align with the presentational currency of its peers. As a result of this change, the results for the year ended 31 December 2023 and the balance sheet as at 31 December 2023 have been restated in US Dollars ($).

Further analysis of the summary metrics provided in the Summary Financial Information table below is detailed in the following pages of this Financial Review.

Production for 2024 was 34,600 boepd, compared to 35,200 boepd for 2023 and 40,100 boepd for 2023 on a pro forma basis. The 2 million boe lower annual production as compared to the 2023 Pro Forma level, largely reflected the operational challenges we experienced with the Triton FPSO. Realised sales prices for gas for the period were lower than for 2023, averaging 76 pence per therm (2023 pro forma: 94 pence per therm), although realised oil prices were slightly higher in 2024 averaging $75/bbl (2023 pro forma: $67/bbl).

Serica generated EBITDAX of $379 million in 2024 compared to $475 million for 2023 and a profit before taxation down nearly 60% to $160.5 million for 2024 compared to $380.4 million for 2023. However, after a materially lower tax charge of $68.1 million (2023: $252.6 million), profit after tax for the year was down by just under 30% to $92.4 million compared to $127.8 million for 2023.

Sales revenues

The total 2024 sales revenue was $727.2 million, compared to pro forma 2023 sales revenue of $917.2 million. The reduction in like for like sales is largely driven by the impact of 2024 Triton unplanned outages, which resulted in over 2 million bbls lower volumes of oil sales as well as a lesser impact from marginally lower realised commodity prices, primarily driven by the reduction in NBP market prices and realised gas prices.

Sales comprised gas revenue of $374.7 million (PF 2023: $445.0 million), oil revenue of $317.5 million (PF 2023: $446.6 million) and NGL revenue of $35.0 million (PF 2023: $25.6 million). The fall in gas revenue was driven by lower realised pricing (76 pence per therm as compared to 94 pence per therm PF 2023) while the like-for-like oil revenue was down by almost 30% reflecting oil production down nearly 40% partially offset by higher realised oil prices ($75.4 per barrel as compared to $66.8 per barrel PF 2023). Like-for-like NGL revenues were up by 36%, with 25% higher sales volumes as well as higher realised prices for NGLs ($491 per metric tonne as compared to PF 2023: $453 per metric tonne).

Total product sales volumes for the period comprised approximately 386.7 million therms of gas (PF 2023: 379.6 million therms), 4.2 million lifted barrels of oil (PF 2023: 6.7 million barrels), and 70,872 metric tonnes of NGLs (PF 2023: 56,630 metric tonnes). This amounted to overall sales volumes some 2 million boe lower in the period of 12.2 million boe (PF 2023: 14.4 million). 

Gross profit

The gross profit for 2024 was $223.2 million compared to $382.1 million for 2023. Overall cost of sales of $504.0 million compared to $406.8 million for 2023. This comprised $337.3 million of field operating and lifting costs (2023: $281.6 million), movements in oil over/underlift increased to a credit of $20.6 million (2023: credit of $11.5 million), and $187.3 million of non-cash depletion charges (2023: $136.3 million).

The increase in total operating costs largely reflected a full year contribution from the enlarged business including Tailwind as compared to 2023, with a significant proportion of fixed element costs. Absolute field operating costs as reported were approximately 20% higher than 2023, largely reflecting a full year of the combined business. This translated into $/boe of $26 as compared to approximately $21 for 2023, with the increased unit rate mainly resulting from reduced production due to the unplanned Triton Area shut-ins during 2024.

EBITDAX, operating profit before net finance costs and tax

EBITDAX for 2024 was $379 million compared to $475 million for 2023.

The operating profit for 2024 was $186.5 million compared to $399.9 million (inclusive of a gain on acquisition of $41.9 million on the Tailwind transaction) for 2023. 

Net hedging expense of $43.5 million (2023: $5.8 million income) comprised unrealised hedging losses of $31.8 million (2023: gains of $25.3 million) and realised hedging losses of $11.7 million (2023: $19.5 million losses). Unrealised hedging losses arose from the non-cash movement in valuation of Serica's 2024 period-end commodity hedge positions, with the main contributor being mark to market of gas price derivatives which were entered into during 2024 to manage commodity price risks and to comply with minimum hedging requirements under the Group's RBL facility. Realised hedging expense during 2024 primarily related to out of the money UKA Emission Trading Scheme ('UKA ETS') carbon price swaps which have now rolled off.

Contract revenue of $31.3 million (2023: $30.0 million) arose from the partial 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 is released to the Income Statement across 2023, 2024 and 2025 as the underlying contract unwinds, with the final unwind impact of $5.4 million to be reflected in 2025.

Administrative expenses for 2024 of $21.6 million reflected a full year period of the enlarged group activities compared to $24.5 million for 2023. The 2023 comparable period also had additional, separately disclosed, transaction costs of $12.5 million relating to fees and other transaction costs associated with the Tailwind acquisition.

Profit before taxation and profit after taxation for the period

Profit before taxation for 2024 of $160.5 million (2023: $380.4 million) included a $2.5 million charge arising from an increase in the fair value of financial liabilities (2023: $9.4 million charge), $13.9 million of finance revenue (2023: $16.8 million) and $37.4 million of finance costs (2023: $26.9 million).

Finance revenue of $13.9 million (2023: $16.8 million) primarily represented interest income earned on cash deposits and decreased as a result of lower average cash balances held in the period compared to 2023. Finance costs of $37.4 million (2023: $26.9 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 increase reflects the full period of interest charges and fees on the RBL in 2024 compared to the shorter post-acquisition period in 2023.

The 2024 taxation charge of $68.1 million (2023: charge of $252.6 million) comprised current tax charges, before adjustment in respect of prior years, of $14.1 million (2023: $225.8 million) and a deferred tax charge of $54.2 million (2023: $24.4 million). The sharply reduced current tax charge reflected the materially lower profit before tax but also the group benefiting, for the first time, from the application of in year group relief effects.

Overall, profit after taxation for 2024 was $92.4 million compared to a profit after taxation of $127.8 million for 2023. This resulted in an earnings per share of 24 cents (2023: 35 cents) after taking into account the weighted average number of ordinary shares in issue.

GROUP BALANCE SHEET

Serica retains a robust balance sheet with a conservative Adjusted Net Debt to EBITDAX ratio of 0.2x as at 31 December 2024. This position of balance sheet strength and ample liquidity gives the group flexibility in capital allocation including the ability to fund its ongoing capital investment programmes while continuing to support distributions to shareholders.

Total property, plant and equipment increased from $905.8 million at year end 2023 to $991.6 million at 31 December 2024.

PP&E additions comprised book capital expenditure including accruals during 2024 of $264.0 million across the Triton Area ($200.0 million) and BKR ($54.3 million) asset hubs and Erskine field ($9.7 million). These were partly offset by depletion charges for 2024 of $188.3 million.

The net deferred tax asset of $55.1 million at 31 December 2024 compares to $107.1 million at year end 2023. This comprised the recognition of deferred tax assets in relation to tax losses and future relief available on decommissioning of $577 million, partially offset by deferred tax liabilities of $522 million arising on PP&E balances. Deferred tax liabilities arising upon the Group's PP&E balances will be released in future periods as those balances are depleted. The overall reduction in Net Deferred Tax Assets of $52.0 million as compared to 2023 largely arose from increased deferred tax liabilities recognised on higher PP&E balances and reflecting the increase in the EPL rate from 35% to 38%, and a reduction in the deferred tax asset recognised on the Group's oil revenue contract liability which substantially unwound during the year.

Decommissioning security advances of $35.1 million at 31 December 2023 were recovered and added to cash balances during H1 2024 when replaced shortly after completion of the new RBL facility by security in the form of letters of credit issued under the new financing facility.

The decrease in cash balances from $335.4 million at 31 December 2023 to $148.5 million at 31 December 2024 reflected cash flow from operations of $452 million offset by $153 million of cash tax payments, capital and abandonment expenditures paid of $278 million, $113 million of dividend payments, $19.0 million in respect of our inaugural share buyback programme conducted between April and June and $52.5 million on debt repayments in the period.

Current trade and other payables increased to $168.3 million at 31 December 2024 from $121.7 million at the end of 2023 reflecting the higher payable balances in relation to the Group's capital and decommissioning expenditure and higher deferred revenue in respect of certain revenue contracts. The UK corporation tax payable reversed from the prior year to a receivable of $71.0 million at 31 December 2024 (31 December 2023: $68.3 million payable) and reflects a recovery of overpayments of corporation tax, supplementary charge, and the EPL in respect of 2024 resulting primarily from the application of group tax relief.

Derivative financial liabilities of $42.4 million at 31 December 2024 represent the mark to market valuation of gas and oil hedging swap and collar products in place at the year end. New gas and oil hedging arrangements were entered into during 2024 to manage commodity price risks where management considered this prudent and/or available on attractive market terms and to comply with minimum hedging requirements under the Group's RBL.

Contract liabilities of $5.4 million at 31 December 2024 (31 December 2023: $36.7 million) reflect the outstanding portion of an underlying revenue offtake contract that was fair valued in connection with the Tailwind acquisition in March 2023. An original liability of $66.7 million was recognised in 2023 which is released to the Income Statement across 2023, 2024 and 2025 as the underlying contract unwinds.

Non-current financial liabilities of $81.9 million (31 December 2023: $82.8 million) comprise remaining deferred consideration projected to be paid under the BKR acquisition agreements of $49.7 million (31 December 2023: $44.9 million) and royalty liabilities of $32.2 million (31 December 2023: $37.9 million) for amounts payable to third parties under the terms of Triton asset acquisitions previously made by Tailwind. Current financial liabilities at 31 December 2023 reflected the final contingent consideration payment of shares issued in March 2024 in respect of the Tailwind acquisition.

Provisions of $146.0 million (31 December 2023: $148.8 million) predominantly relate to future decommissioning obligations and are split between current balances of $nil million (31 December 2023: $16.5 million) as decommissioning activities were undertaken during the year, and non-current balances of $146.0 million (31 December 2023: $132.3 million). The small decrease from the prior year was mainly due to expenditure in the period on the completed Arthur field programme partially offset by a charge from the unwinding of the discount applied. Increases were partially offset by currency translation adjustments.

Interest bearing loans of $219.1 million at 31 December 2024 represent drawn amounts of $231.0 million net of unamortised facility fees of $11.9 million under the $525 million RBL facility entered into in January 2024 which replaced the previous RBL facility assumed with the Tailwind acquisition (31 December 2023: $271.2 million).

The initial drawdown under the new RBL facility was $283.5 million (covering a repayment of $271.2 million for the previous RBL and $12.3 million of interest and new facility fees) in January 2024 and a repayment of $52.5 million was made in February 2024. The redetermined total amount available for drawdown under the facility at 31 December 2024 was at a level capped by the facility size of $525 million.

Overall, net assets have decreased from $834.2 million at year end 2023 to $796.5 million at 31 December 2024.

The increase in share capital from $245.3 million to $245.5 million arose from shares issued following the exercise of share options and the nominal value of shares issued for the Tailwind acquisition, while the decrease in other reserves from $37.7 million to $37.5 million arose from share-based payments related to share option awards. The merger reserve of $286.6 million in the consolidated Group accounts arose in connection with the shares issued for the 2023 Tailwind acquisition. 

CASH BALANCES AND FUTURE COMMITMENTS

Current cash position and price hedging

At 31 December 2024 the Group held adjusted net debt of $82.5million as compared to adjusted net cash of $99 million at 31 December 2023.

As at 27 March 2025, the Company held cash and cash equivalents of $141 million and debt drawings of $231 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 investments. Serica held the following instruments as at 31 December 2024:

Oil hedges

Gas hedges

Included in the Q1 2025 hedged volumes are volumes at fixed pricing under oil offtake agreements for approximately 0.4 million barrels at an average price of $61 per barrel. These legacy hedges were applied to an individual oil tanker lifting from the Triton area FPSO and fully utilised during January 2025.

Field and other capital commitments

Serica's planned 2025 investment programme includes two remaining wells from the 2024-25 drilling campaign in the Triton Area (Evelyn Phase 2 (EV02) and Belinda) and further capital work on the Bruce facilities including resilience upgrades as well as a flare gas recovery project.

At 31 December 2024, the Group had commitments for future capital expenditure relating to its oil and gas properties which relate primarily to the remaining Triton Area well programme (including EV-02 and Belinda), other Triton area work (including a new water injection line) and other capital works on Bruce. The Group's only significant exploration commitment work programme includes drilling an exploration well on the Licence P2400 (Skerryvore) prospect by the end of September 2025. Given the lack of clarity regarding the future fiscal and licensing regime, the joint venture has applied for an extension to the licence period.

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 2024, Serica's market capitalisation stood at $660 million based upon a share price of 135.2 pence which exceeded the net asset value of $796.5 million. By 28 March 2025 the Company's market capitalisation, based on a share price of 138p, had increased to $697 million.

*See note 2

Serica Energy plc

Group Statement of Comprehensive Income

For the year ended 31 December 2024

*See note 2

Serica Energy plc

Registered Number: 5450950

Group Balance Sheet

As at 31 December 2024

*See note 2

Approved by the Board on 31 March 2025

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 2024

*See note 2

*See note 2

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 2024 were authorised for issue by the Board of Directors on 31 March 2025 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 companies 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 2024. The principal accounting policies adopted by the Group are set out in note 2.

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 2024.

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 2026 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.

Change in presentation currency

On 1 January 2024, the Group changed its reporting currency from Pounds Sterling to US Dollars as the Group believes that the presentation currency change will give investors and other stakeholders a clearer understanding of Serica's performance over time and align with the presentation currency of its peers.

In accordance with IAS 8, Accounting Policies, Changes in Accounting Estimates and Errors, this change in presentation currency was applied retrospectively and accordingly, prior year comparatives have been restated.

Financial information included in the consolidated statements for the year ended 31 December 2023 has been restated in US Dollars as follows:

- Assets and liabilities in non-US denominated currencies were translated into US Dollars at the rate of exchange ruling at the relevant balance sheet date;

- Non-US Dollar income statements and cash flows were translated into US Dollars at average rates of exchange for the relevant period; and

- Share capital, merger reserve, and all other equity items were translated using the rates that were used in 2018 when the Group had changed its presentation currency from US Dollars to Pounds Sterling, or the subsequent rates prevailing on the date of each relevant transaction since.

Going Concern

The Directors are required to consider the availability of resources to meet the Group's liabilities for the period ending 30 June 2026, the 'going concern period'.

As at 27 March 2025 the Group held cash and term deposits of $141 million and undrawn RBL facility amount of $294 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. 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$75/bbl for oil for the remainder of 2025 and 82 pence/therm gas and US$72.5/bbl oil for H1 2026. Production, opex, capex and tax assumptions are those currently included in standard management forecasting. 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 continued full six month period shut-in of Triton hub production until 1 October 2025 and 25% reduced production volumes from the base case across the full portfolio of producing assets for H1 2026. Base case commodity pricing is retained for 2025 but lower commodity pricing of 50 pence/therm gas and US$60/bbl oil are assumed for the H1 2026 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 outflows 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.

Potential Transaction

On 7th March 2025, the Company announced that it was in discussion with Enquest Plc regarding a possible business combination (the "Potential Transaction"). The announcement was issued following media speculation, pursuant to Rule 2.4 of the UK Takeover Code and as such there is no certainty that a Firm Intention to Offer pursuant to Rule 2.7 will be made nor as to the terms of any such offer if made. The Potential Transaction is envisaged to be implemented by way of a reverse take-over with Enquest Plc making an all share offer for Serica.

Notwithstanding the preliminary nature of the discussions of the Potential Transaction, the Directors have undertaken appropriate analysis, commensurate with the early stage and uncertainty of the Potential Transaction, to satisfy themselves with the appropriateness of the going concern basis of reporting the Group's financial statements. The analysis considered inter alia the regulatory provisions of the Financial Conduct Authority ("FCA") and the Companies Act under the likely structure of the transaction as a reverse takeover, including requirements for shareholder approvals and the publishing of a prospectus covering the combined group, and consequently the obligations of directors and of the FCA Sponsor regime that would be available to the Board prior to recommending approval of any Potential Transaction to shareholders and to the legal completion of any such Potential Transaction.

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); and taxation including recognition of deferred tax 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 2024 in accordance with the stated policy. The Group considers the relationship between its market capitalisation and its book value, among other factors, when reviewing for indicators of impairment. As at 31 December 2024, the market capitalisation of the Group was below the book value of its equity, which was assessed by management as a trigger for potential impairment of its oil and gas assets.

The future recoverable amounts of the Group's oil and gas assets were assessed for impairment and no impairment was identified. See note 13 for further information.

Acquisition through business combination

The Group made a significant acquisition in prior year which was accounted for as a business combination under IFRS 3 (see note 29). In determining the fair value on acquisition of a pre-existing oil revenue contract a judgement was made to value the contract at the differential between the contract pricing and market price and to unwind the liability through 'contract revenue - other' in the income statement upon satisfaction of the performance obligations of the contract.

Taxation including the recognition of deferred tax assets

The Group's operations are subject to a number of specific tax rules which apply to exploration, development and production companies such as the Energy Profits Levy, ring-fenced Corporation Tax at 30%, the Supplementary Charge Tax of 10% and the application of investment allowances. As a result of these factors, the tax provision process necessarily involves the use of a number of judgements around expenditure deductible under different ring-fenced tax rules.

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 page 11) 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 2024 of 20.4 million (2023: $15.4million).

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 2024, assumptions underlying the calculation were updated from 2023. 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

The Group determined the fair value of a royalty liability assumed upon the Tailwind acquisition in 2023 at the time of the acquisition and subsequently as at 31 December 2023 and 2024. 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 - see use of judgements: Taxation. 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 entities are measured using the currency of the primary economic environment in which the entity operates ('functional currency'). The Group's financial statements are presented in 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 statement of profit or loss 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

As allowed under IFRS 6 and in accordance with clarification issued by the International Financial Reporting Interpretations Committee, the Group has continued to apply its existing accounting policy to exploration and evaluation activity, subject to the specific requirements of IFRS 6. The Group will continue to monitor the application of these policies in light of expected future guidance on accounting for oil and gas activities.

Pre-licence Award Costs

Costs incurred prior to the award of oil and gas licences, concessions and other exploration rights are expensed in the income statement.

Exploration and Evaluation ('E&E')

The costs of exploring for and evaluating oil and gas properties, including the costs of acquiring rights to explore, geological and geophysical studies, exploratory drilling and directly related overheads, are capitalised and classified as intangible E&E assets. These costs are directly attributed to regional CGUs for the purposes of impairment testing.

E&E assets are not amortised prior to the conclusion of appraisal activities but are assessed for impairment at an asset level and in regional CGUs when facts and circumstances suggest that the carrying amount of a regional cost centre may exceed its recoverable amount. Recoverable amounts are determined based upon risked potential, and where relevant, discovered oil and gas reserves. When an impairment test indicates an excess of carrying value compared to the recoverable amount, the carrying value of the regional CGU is written down to the recoverable amount in accordance with IAS 36. Such excess is expensed in the income statement. Where conditions giving rise to impairment subsequently reverse, the effect of the impairment charge is reversed as a credit to the income statement.

Costs of licences and associated E&E expenditure are expensed in the income statement if licences are relinquished, or if management do not expect to fund significant future expenditure in relation to the licence.

The E&E phase is completed when either the technical feasibility and commercial viability of extracting a mineral resource are demonstrable or no further prospectivity is recognised. At that point, if commercial reserves have been discovered, the carrying value of the relevant assets, net of any impairment write-down, is classified as an oil and gas property within property, plant and equipment, and tested for impairment. If commercial reserves have not been discovered then the costs of such assets will be written off.

Asset Purchases and Disposals

When a commercial transaction involves the exchange of E&E assets of similar size and characteristics, no fair value calculation is performed. The capitalised costs of the asset being sold are transferred to the asset being acquired. Proceeds from a part disposal of an E&E asset, including back-cost contributions are credited against the capitalised cost of the asset, with any excess being taken to the income statement as a gain on disposal.

Farm-ins

In accordance with industry practice, the Group does not record its share of costs that are 'carried' by third parties in relation to its farm-in agreements in the E&E phase. Similarly, while the Group has agreed to carry the costs of another party to a Joint Operating Agreement ("JOA") in order to earn additional equity, it records its paying interest that incorporates the additional contribution over its equity share.

Property, Plant and Equipment - Oil and gas properties

Capitalisation

Oil and gas properties are stated at cost, less any accumulated depreciation and accumulated impairment losses. Oil and gas properties are accumulated into single field cost centres and represent the cost of developing the commercial reserves and bringing them into production together with the E&E expenditures incurred in finding commercial reserves previously transferred from E&E assets as outlined in the policy above. The cost will include, for qualifying assets, any applicable borrowing costs.

Depletion

Oil and gas properties are not depleted until production commences. Costs relating to each single field cost centre are depleted on a unit of production method based on the commercial proved and probable reserves for that cost centre. The depletion calculation takes account of the estimated future costs of development of management's assessment of proved and probable reserves, reflecting risks applicable to the specific assets. Changes in reserve quantities and cost estimates are recognised prospectively from the last annual reporting date. Proved and probable reserves estimates obtained from an independent reserves specialist have been used as the basis for 2023 and 2024 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. The policy is applied consistently to similar transactions. See note 30 for details of the policy adopted for the acquisition of interests in the Greater Buchan Area.

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 change 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 accrual 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 statement of profit or loss and other comprehensive income and presented within operating profit.

Further details of the fair values of derivative financial instruments and how they are measured are provided in Note 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 receivables and contract assets

A receivable represents the Group's right to an amount of consideration that is unconditional (i.e., only the passage of time is required before payment of the consideration is due). A contract asset is the right to consideration in exchange for goods or services transferred to the customer.

Provision for expected credit losses of trade receivables and contract assets

For trade receivables and contract assets, the Group applies a simplified approach in calculating expected credit losses 'ECLs'. Therefore, the Group does not track changes in credit risk, but instead, recognises a loss allowance based on lifetime ECLs at each reporting date. The Group has established a provision matrix that is based on its historical credit loss experience, adjusted for forward-looking factors specific to the debtors and the economic environment. A financial asset is written off when there is no reasonable expectation of recovering the contractual cash flows. The Group's receivables have a good credit rating and there has been no noted change in the credit risk of receivables in the year.

Provisions

Provisions are recognised when the Group has a present legal or constructive obligation as a result of past events, it is probable that an outflow of resources will be required to settle the obligation, and a reliable estimate can be made of the amount of the obligation.

Revenue from contracts with customers

Revenue from contracts with customers is recognised when control of the goods or services are transferred to the customer at an amount that reflects the consideration to which the Group expects to be entitled to in exchange for those goods or services. Revenue is measured at the fair value of the consideration received or receivable and represents amounts receivable for goods provided in the normal course of business, net of discounts, customs duties and sales taxes. The Group has concluded that it is the principal in its revenue arrangements because it typically controls the goods or services before transferring them to the customer.

The sale of crude oil, gas or condensate represents a single performance obligation, being the sale of barrels equivalent on collection of a cargo or on delivery of commodity into an infrastructure. Revenue is accordingly recognised for this performance obligation when control over the corresponding commodity is transferred to the customer. The 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 2024. These include the following:

- Amendments to IAS 1 - Classification of Liabilities as Current or Non-current

- Amendments to IAS 1 - Non-current Liabilities with Covenants

- Amendments to IAS 7 and IFRS 7 - Supplier Finance Arrangements

- Amendments to IFRS 16 - Lease Liability in a Sale and Leaseback

The Group has not early adopted any other standard, interpretation or amendment that has been issued but is not yet effective. Other than the changes described above, 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 2024 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:

- IFRS 10 and IAS 28 (amendments) - Sale or Contribution of Assets between an investor and its Associate or Joint Venture

- Amendments to IAS 21 - Lack of exchangeability

- 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

*See note 2

Gas sales revenue in 2024 arose from three key customers (2023: three). Gas supply contract revenue in 2023 arose from the unwind of gas contract liabilities initially recognised upon the restructuring of certain gas swaps to other fixed price instruments under a gas sales contract in August 2021.

Oil sales revenue in 2024 was from three key customers (2023: three), and NGL sales in 2024 were made to eight customers (2023: six).

The revenue from three significant customers individually comprising $441.4 million, $181.1 million and $78.2 million constitutes more than 10% of total revenue amounting to $700.7 million (2023: three customers comprising $491.7 million, $203.7 million and $80.6 million individually comprising $776.0 million). 

5. Cost of Sales

*See note 2

6. Operating Profit

General and administrative expenses

General and administrative expenses of $21,601,000 (2023: $24,486,000) included depreciation of right of use assets of $1,070,000 (2023: $216,000). Transaction costs of $12,539,000 incurred in 2023 associated with the acquisition of Tailwind Energy Investments Ltd were disclosed separately on the face of the Income Statement and in note 29.

Depreciation and depletion expense

Depreciation of right of use assets totalled $2,114,000 (2023: $996,000) of which $1,044,000 (2023: $780,000) was allocated to cost of sales and $1,070,000 (2023: $216,000) allocated to administrative expenses.

Depletion charges on oil and gas properties are classified within cost of sales.

Auditor's Remuneration

*See note 2

No fees were paid to Ernst & Young LLP and its associates for non-audit services in 2023 or 2024.

7. Staff Costs and Directors' Emoluments