Results for the six months ended 30 June 2025

Serica Energy plc

('Serica' or 'the Company')

Results for the six months ended 30 June 2025

London, 5 August 2025 - Serica Energy plc (AIM: SQZ), a British independent upstream oil and gas company with operations in the UK North Sea, today announces its unaudited financial results for the six months ended 30 June 2025. The results are included below and copies are available at www.serica-energy.com and www.sedar.com.

Chris Cox, Serica's CEO, stated:

"Serica has felt like a coiled spring in the first half of 2025. The resilience of our gas production from the Bruce Hub and strong Q1 gas prices, coupled with a robust contribution from our other producing assets, helped deliver a creditable financial performance despite the downtime at the Triton FPSO. With the ramp up from Triton progressing, we should soon return to production levels of around 50,000 boepd, with more to come as new wells at Guillemot and Evelyn come onstream. Optimisation work by the Serica team at the Bruce Hub is also beginning to deliver results, and will boost production in the second half of the year.

We continue to make progress on advancing future production opportunities. Subsea tie-in work on Belinda is progressing well, and this new field will come onstream at the start of 2026. As we plan future drilling programmes across our wider asset base, we will look to replicate the success of the five well drilling campaign at Triton. This achieved tremendous subsurface results that are of material size to Serica, and was delivered ahead of schedule and under budget. Our future drilling plans have the potential to offset natural field declines into the next decade.

The expected increase in production compared to the last 12 months is set to provide material cash generation, funding organic growth and sustained dividends while we continue to seek to create shareholder value through disciplined M&A."

Results summary ($ million unless stated)

Highlights

Positive subsurface performance set to boost production

· Production of 24,700 boepd net to Serica in H1 2025 (H1 2024: 43,700 boepd), impacted materially by the shut-in of the Triton FPSO from 28 January to the end of the period

· Work to increase production from the Bruce Hub is starting to deliver results, with well optimisation work and the resumption of production at Keith leading to an increase in production post-period end, which averaged 21,600 boepd in July compared to 16,700 boepd in H1 2025

· The completion of the BE01 well on the Belinda field (Serica 100%), which delivered rates of 7,500 boepd on test, brought to an end the highly successful five well drilling programme at Triton

- All five wells delivered positive results which met or exceeded pre-drill estimates

- The programme was delivered 25 days ahead of schedule and c.$31 million net to Serica under budget

Cash position remains robust, providing optionality over capital allocation

· Cash of $174 million (31 December 2024: $148 million), an increase since year end 2024 despite the ongoing capital expenditure programme and no production from Triton since January

- Cash was boosted by the receipt of the $71 million cash tax refund in June 2025, the result of Group relief in 2024 leading to an overpayment of cash tax in 2024 under the Instalment Payment Regulations

- Capital expenditure on a cash basis of $138 million in H1, as work continued on the Triton drilling campaign

· Net debt reduced by $26 million in the period to $57 million

· Strong financial capacity maintained with the redetermination of Reserves Based Lending facility ('RBL') completed in June, with the Borrowing Base set at $490 million, of which $231 million is drawn down

- Liquidity of $433 million as at 1 July 2025

· Interim dividend of 6p declared today (2024 interim dividend: 9p), in line with the previously announced rebalancing of the final dividend

- The interim dividend is payable on 20 November 2025 to shareholders registered on 24 October 2025, with an ex-dividend date of 23 October 2025

Organic growth potential, actively exploring value-accretive M&A

· Serica's low net debt and robust liquidity position underpins the Company's continued ability to make targeted organic growth investments and to remain both competitive and opportunistic in M&A

· Serica continues to progress plans to convert material 2C resources into reserves, should the appropriate fiscal and regulatory environment allow

- Following the identification of over 20 potential infill targets around the Bruce Hub, considerable further work and planning has been undertaken with a high-graded list of optimal targets being matured for a possible future drilling campaign

- The Company continues to aim for FID of the Kyle redevelopment (Serica 100%) in H1 2026 Front-end design work tenders have been issued and the procurement of long lead items is underway

- A Request for Information has been sent out for a semi-submersible rig to carry out a potential drilling campaign across Bruce and Kyle

· Serica continues to analyse multiple M&A opportunities, largely focused on the UK North Sea

Outlook and guidance - material cash generation expected

· Production in the second half of 2025 is expected to be materially higher than H1, due to significantly increased Triton FPSO uptime, contribution from new wells at Triton, and the continuation of the production increase following the reinstatement of low-pressure wells at the Bruce Hub

· Production guidance for FY 2025 of 33,000-35,000 boepd

· Capital expenditure expected to be around the top end of the $220-250 million range given the relative strength of Sterling against the US Dollar, and work to progress Belinda towards production at the start of 2026 moving forward at pace, accelerating spend from 2026 into 2025

· Opex guidance unchanged at c.$330 million

· Work is progressing well regarding the move from the AIM to the Main Market of the London Stock Exchange early in Q4 2025

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. 

CHIEF EXECUTIVE OFFICER'S REVIEW

Having now been at Serica for just over a year, there remains a lot of hard work ahead to position the Company where I want it to be, but work done in the first half of the year will help the business to start delivering at its true potential.

I have said a number of times since joining that there were two things that surprised me, the first being the quality of our subsurface opportunities and the team to exploit them, and the second being the potential upside available from running our operations more efficiently. Both areas have been highlighted by events during the first half of 2025.

Our run of exceptional subsurface results continued to the end of the five-well drilling campaign on the fields around the Triton FPSO. This has been a tremendous success, both in terms of the operational delivery - almost a month ahead of schedule and $31 million under budget - and in the subsurface results. Credit is due to both the Serica team and our key contractors engaged in this activity. All five wells are set to add to production. Two, at Bittern and Gannet E, have already done so at a combined rate of over 10,000 boepd net to Serica prior to the FPSO going offline, and wells on Guillemot and Evelyn will be brought online shortly. The final well drilled, on Belinda, flowed c.7,500 boepd on a constrained test, and will be on stream at the start of 2026.

Of course, for Serica to truly benefit from these wells, the Triton FPSO has to deliver a far better performance. It has not been good enough. The lack of adequate historical maintenance led to a backlog of work that resulted in the necessity for five months of downtime, with only 27 days of production in the first half of the year. The good news is that the lengthy outage has allowed work to be done that should enhance uptime going forward.

There is still hard work ahead though. The Triton FPSO is now in a state of repair consistent with an FPSO of its age, and requires ongoing maintenance with better planning and delivery. The good news is that this is something recognised by the operator, Dana, who has made significant changes to its personnel and processes at Triton. We will continue to work closely with Dana to identify ways of improving operational performance at Triton so that the subsurface potential is translated into production and cash.

A fully functioning Triton FPSO will deliver material production and significant, largely tax-sheltered, cash generation for Serica. The resumption of Triton operations is expected to return us to aggregate production of over 50,000 boepd once all fields are returned to production, with more to come as new wells are brought onstream.

The Bruce Hub produces very reliably, but it can produce more. The first steps to do this have taken place with the resumption of bull-heading work, taking production back up to over 21,000 boepd in July. This level can be maintained through future well work, ahead of resuming drilling around the asset. Plans for this are progressing well - the Triton drilling campaign is the clear blueprint, and we are in the process of whittling down the 20 potential prospects to a handful of drill ready opportunities.

To help achieve our production objectives, we are being proactive in strengthening our organisation. I am delighted, therefore, to have recently appointed a Chief People Officer and shortly to be adding a new Chief Technical Officer as well as other key roles having been filled recently in production optimisation and IT. There is plenty for us to aim at.

The opportunities described above together with the potential, very attractive, redevelopment of the Kyle field as a new tie-back to Triton, can support annual production at around 40,000 boepd into the next decade. While we are taking steps to ensure that we deliver our organic growth opportunities as quickly as possible, they cannot proceed without the right external environment.

All credible forecasts show the UK consuming substantially more oil and gas than it produces over the foreseeable future. To support UK jobs, communities and public finances, the country is better off producing its own oil and gas than importing it. Whether in relation to tax, licensing or regulation, UK government policies should be designed with that objective at the forefront. The retention of capital allowances in last year's Autumn Budget helped preserve the viability of relatively small, short-cycle return investments, but taking fuller advantage of the UK's domestic oil and gas resources requires a change in government policy towards pragmatic and realistic fiscal and regulatory policies.

The results of the first of three consultations launched by the government were finally released on 19 June. This confirmed the details of the new requirement to include end use (Scope 3) emissions in field development submissions. Including this information is in itself not difficult to do, and we are in fact already publishing these data at Company level, but we hope that when the government takes decisions on new fields, they properly reflect that, quite apart from the obvious economic, jobs and tax arguments, UK developments (especially for gas) have total emissions very materially below those of imported hydrocarbons.

The industry is still waiting for an outcome to the consultations relating to future licensing and the successor to the Energy Profits Levy ('EPL'). Clarity on these issues is urgently required. In order for companies to sanction the large ticket long-term investments in the UK North Sea that will benefit the UK, a more appropriate tax regime that reflects reality is required. For example, due to the anomalous design of the Energy Security Investment Mechanism linking oil and gas prices, oil production continues to be taxed at 78% despite the average Brent price in the first half of the year at $71.9/bbl being below the threshold price of $74.2/bbl for termination of the EPL. As has been stated consistently by the industry over many months, we are not in windfall conditions.

Notwithstanding the current circumstances of an excessive tax rate combined with fiscal and regulatory uncertainty, we are confident that Serica can make smart investment decisions. This includes proactively seeking value-accretive acquisitions in the UK North Sea that will grow the business and deliver synergy potential.

As we have demonstrated previously, having a strong balance sheet and a robust financial outlook allows us to invest in our assets and maintain meaningful cash distributions to shareholders, while also being able to take advantage of M&A opportunities.

Serica expects to generate material free cash flow in the coming years, cash flow that we would like to reinvest in projects that promise rapid payback and support material shareholder returns. We have today announced an interim dividend of 6p per share, at a level in line with the rebasing of the dividend that we announced with our full-year results. We see this rebased level of dividend as being sustainable in the medium-term, delivering a competitive level of shareholder returns as well as allowing us to invest in the exciting growth opportunities we see in our portfolio and in the M&A market, all while maintaining a resilient financial frame.

Production is set to resume the 50,000 boepd achieved earlier in the year, with more to come - on which we look forward to updating you in due course. With our organic portfolio set to deliver, and hard work ongoing to add to our asset base, I am confident that Serica is well positioned heading into the second half of 2025.

REVIEW OF OPERATIONS

Serica's assets contain 118.5 mmboe of 2P reserves net to the Company as of 31 December 2024, evenly split between oil and gas. The current producing portfolio has the capacity for daily production exceeding 50,000 boepd, with the subsurface potential to convert a material portion of the 88.7 mmboe of 2C resources into producing reserves. This can then maintain annualised production of over 40,000 boepd into the next decade, given the right fiscal and regulatory environment.

Production (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 from the Bruce Hub averaged 16,700 boepd (H1 2024: 23,400 boepd) net to the Company in the first half of the year. This figure was impacted by the previously noted operational work required on the productive R3 well, which reduced production in January from Rhum, and unscheduled downtime of the facility in May due to required maintenance work taking place on the export pipeline.

Production was also constrained due to the main oil line ('MOL') booster pump being offline for the majority of the period. This impacted the volume throughput at BKR, resulting in production being slightly below the potential of the fields. Following the replacement of the MOL booster pump in June, the restoration of capacity on the export line allowed bull-heading operations (in which gas is pumped into a well to reduce back pressure and enhance production) to resume. With three wells now successfully bull-headed at Bruce, production at the hub has recently increased markedly, averaging 21,600 boepd net to Serica in July.

Following the work done at Bruce, the K1 well at Keith was also brought back onto production towards the end of July for the first time since 2021.

Serica has recently hired a production optimisation manager to coordinate the overall focus on delivering further resilience and efficiency improvements, aimed at optimising production from the Bruce Hub going forward. The annual maintenance outage for 2025 will align with the scheduled Forties pipeline downtime, and is set to begin on 16 August for around 12 days.

As well as improving production through boosting the operational efficiency of the Bruce platform, Serica continues to work towards the first drilling on the Bruce field since 2012. Subsurface work has identified over 20 possible opportunities around BKR, and the process is ongoing to high-grade these and define the optimal future drilling programme. Work is expected to proceed in two phases, the first focused in the vicinity of the Western Area Development, allowing rapid tie back to existing infrastructure, and phase two targeting opportunities to the North East of the Bruce platform, where subsurface studies suggest large untapped potential.

As Serica prepares for a drilling campaign on BKR and the Kyle redevelopment, a Request for Information has been issued relating to a semi-submersible rig to undertake a two-year campaign starting around the end of 2026/early 2027.

Triton Hub

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

Due to necessary maintenance work that took place on the Triton FPSO from the end of January 2025 until July, the Triton Hub produced severely reduced rates of 2,500 boepd net (H1 2024: 14,200 boepd) in the first half of 2025.

Extensive remediation work and modifications have been carried out. Repairs to the inert gas marine system were completed, with over 100 components on the system either replaced or refurbished. Topside modifications were made in readiness to accept the start of production from the Belinda field, significant safety critical work was also undertaken on the firewater system, and valves and sections of pipework across the FPSO were replaced.

In order to reduce overall downtime this year, following discussions with Dana, the scheduled summer maintenance programme was carried out concurrently. This was completed at the end of June, with work to then resume production ongoing.

Following the initial resumption of production from the Bittern field, a problem with the gas lift system prevented other Triton fields being restarted. Additionally, other minor work was identified, which required a short cessation of production to repair. This remedial work now being complete, the restart of the Triton fields is progressing.

Production from the Bittern field (Serica 64.6%) will be followed by the Evelyn (Serica 100%) and Gannet E (Serica 100%) fields. Once existing wells resume production, the new wells drilled on the Guillemot North West (Serica: 10%) and Evelyn (Serica: 100%) fields will be brought onstream for the first time, promising an increase to the 25,000 boepd the Triton FPSO was producing net to Serica in January.

The BE01 well on the Belinda field (Serica 100%), which flow tested at constrained rates of 7,500 boepd, is now expected to enter production at the start of 2026 following work to tie the well into the Triton FPSO. This is the key focus of our capital expenditure in H2, with spend expected in 2026 brought forward into 2025.

Other Production Assets

Production from our Other Producing Assets averaged 5,500 boepd in the first half of the year, and generated $35 million in operational free cash flow.

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

The Erskine field continues to produce consistently, delivering a rate of over 2,100 boepd net to Serica in H1 2025 (H1 2024: 500 boepd). 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)

Production at Columbus has been steady in the first half of 2025, averaging 1,500 boepd (H1 2024: 1,800 boepd) net to Serica. Annual maintenance on the host Shearwater platform began on 12 July 2025 and is scheduled to take 45 days.

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

Average Orlando field production in H1 2025 was 1,900 boepd (H1 2024: 3,800 boepd) net to Serica, due to a scheduled shut-in of 28 days for annual maintenance taking place during the period, aligned with maintenance on the Ninian platform. An issue with the Ninian export system also prevented production from the end of April through the majority of May.

Development

Kyle Redevelopment - (P2616) Serica 100% and operator

The Kyle Redevelopment, located in Block 29/2c, is a previously producing oilfield, 20 km southeast of Triton, shut-in in 2020 solely due to the decommissioning of the Banff FPSO host facility. With the appropriate fiscal and licensing environment, there is the potential for first oil in 2028 on a project that carries over 11 mmboe of 2C resources, via a single horizontal well tied-back to Triton via Bittern, similar to other Triton tie-backs.

Subsurface work has matured and front-end design work tenders have been issued. The procurement of long lead items, such as the subsea wellhead system, is also underway, as Serica works towards a potential FID in H1 2026.

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

Buchan Horst is one of the largest remaining undeveloped fields on the UKCS, with an estimated 22.7 mmboe of 2C resources net to Serica, and the potential for 10,000 boepd peak net production. The development project would support an estimated 1,000 jobs in the UK and includes the possibility of powering the facilities from offshore wind to achieve UKCS leading low carbon emissions.

The viability of the project continues to depend in large part on the future UKCS fiscal and regulatory regimes, which are currently subject to government consultations. Serica continues to work closely with the joint venture partners to retain optionality over future development scenarios.

Mansell - (P2448) Serica 100% and operator

The Mansell discovery is located in licence P.2448 in UKCS Block 3/8g south and east of the Ninian and Columba fields. Production from the field commenced in 1992 and ceased in 1995. Serica undertook work to determine the feasibility and timing of a redevelopment, however it has not been possible to identify a viable host facility in this area of the Northern North Sea and hence Serica expects to relinquish this licence by the end of Q3 2025. The Mansell field comprises 8.3 mmboe of Serica's stated 2C resources.

Exploration

Skerryvore - Blocks 30/12c (part), 30/13c (split), 30/17h, 30/18c and 30/19c (part), Serica: 70% working interest

The P2400 Licence is located in the Central North Sea, 60 km south of the Erskine field. The commitment work programme included drilling an exploration well on the Skerryvore prospect by the end of September 2025. Given the lack of clarity regarding the future fiscal and licensing regime, the joint venture applied for an extension to the period, and the NSTA has agreed to extend the P2400 licence to 31 March 2027.

Fynn Beauly - (P2634) Serica 50%

A 50% interest in P2634 licence, containing the Fynn Beauly heavy oil discovery, was acquired when completing the acquisition of Parkmead (E&P) Limited in April 2025. The current licence commitment is limited to technical studies to assess potential development options. 

FINANCIAL REVIEW

Financial results in the first half of 2025 were unavoidably impacted by the prolonged outage of the Triton FPSO. However, considering the material reduction in production and revenues that resulted from this outage, our financial performance - continuing to deliver a pre-tax profit and with cash increasing from the year-end - was creditable. Production is expected to increase materially in H2, with commensurate increases in H2 revenues, albeit we anticipate lower gas prices than seen in H1.

The key difference is expected from our Triton Hub, where profits continue to be shielded from Corporation Tax and Supplementary Corporation Tax by our carried forward loss position, and benefit from the application of capital allowances against EPL from our Triton investment programme. However, the impact on H2 net cash generation will also factor in (as normal) that both the final and interim dividends are payable in the period, and that we project the resumption of cash tax payments, as well as some working capital effects.

Our robust financial position, and the expectation of material free cash flows in 2026 and beyond, gives us continued confidence in our capital allocation policy. We are keen to carry on investing in our portfolio, with Kyle and infill drilling around the Bruce Hub having the opportunity to deliver rapid payback, while also being very tax efficient. Should the result of the outstanding consultations on licensing and the EPL successor regime provide an appropriate investment environment, spend on these projects could be sanctioned in early 2026, but with material expenditure unlikely before 2027.

We see the aggregate rebased dividend level, consistent with the 6p per share interim announced today and the 10p announced with our full-year results, as being sustainable in the medium-term. We believe this will deliver a competitive level of shareholder returns at the same time as allowing us to invest in the exciting growth opportunities we see in our portfolio and from M&A, all while maintaining a resilient financial frame.

Summary of H1 2025 unaudited financial results

An 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 H1 2025 was 24.7 kboepd, compared to 43.7 kboepd for H1 2024 with the sharply reduced level impacted largely by the loss of production from Triton from late January, but also some unscheduled downtime at BKR. Realised sales prices for gas for the period were materially higher than for H1 2024 with NBP gas prices (net of NTS system charges) averaging 96p/th (H1 2024: 67p/th) as more typical winter pricing patterns prevailed, while Brent crude pricing was volatile and averaged slightly lower compared to H1 2024, at $70/bbl (H1 2024: $78/bbl). The combination of these volume and price impacts saw revenues of $305 million (H1 2024: $462 million), down by approximately a third year-on-year despite production volumes down by 43%.

With a largely fixed operating costs base, the revenue impacts were amplified at the profit level, with EBITDAX of $118.5 million compared to $279.2 million for H1 2024 and a profit before taxation of $100.8 million for H1 2025 compared to $188.5 million for H1 2024. After book tax of $143.9 million (H1 2024: $106.0 million) which included a one off non-cash deferred tax expense of $65.2 million as a result of the extension of the EPL to 31 March 2030 being substantively enacted on 3 March 2025, the after tax position resulted in a loss for the period of $43.1million compared to a profit after tax of $82.5 million for H1 2024.

Sales revenues

Total H1 2025 revenue was $304.9 million, compared to H1 2024 revenue of $461.6 million. The reduction in revenue is largely driven by the impact of the Triton unplanned outage for the majority of H1 2025. The revenue fall was partially offset by slightly higher gas revenue during the period, driven by higher gas prices.

Sales comprised gas revenue of $207.4 million (H1 2024: $194.5 million), oil revenue of $86.4 million (H1 2024: $251.7 million) and NGL revenue of $11.1 million (H1 2024: $15.4 million). The increase in gas revenue was driven by higher realised whilst the oil revenue in the period was significantly lower than H1 2024, reflecting approximately 2 million bbls lower lifted volumes due to the Triton outage as well as slightly lower realised oil prices in the period ($70 per barrel as compared to $78 per barrel H1 2024). Like for like NGL revenues were also lower as a result of the Triton shutdown, with the lower sales volumes partially offset by higher realised prices for NGLs ($490 per metric tonne as compared to H1 2024: $432 per metric tonne).

Total product sales volumes for the period comprised approximately 167 million therms of gas (H1 2024: 229 million therms), 1.2 million lifted barrels of oil (H1 2024: 3.2 million barrels) and 22,600 metric tonnes of NGLs (H1 2024: 35,600 metric tonnes). This amounted to product sales in the period of 4.6 million boe (H1 2024: 7.9 million boe).

Gross profit

The gross profit for H1 2025 was $76.4 million compared to $206.8 million for H1 2024. Overall cost of sales of $228.5 million compared to $254.7 million for H1 2024. This comprised essentially unchanged field operating and lifting costs of $158.5 million (H1 2024: $156.4 million), movements in oil over/underlift charge of $15.0 million (H1 2024: charge of $11.2 million), and $54.9 million of non-cash depletion charges (H1 2024: $87.1 million).

The largely unchanged field operating costs, despite markedly reduced production volumes, reflects that a significant proportion of such costs are fixed in nature, particularly in the Triton Area. The reported level of costs was also impacted by the weaker USD to GBP exchange rate on the Group's operating costs which are predominantly in GBP. Operating costs as reported per boe were approximately $34 per boe, increased from $19 per boe for H1 2024, with the increased unit rate mainly due to the reduced production from the unplanned Triton outage during H1 2025.

The reduced H1 2025 production volumes did however directly impact non-cash depletion charges calculated on a unit of production basis, which fell by $32.2 million from the comparative period.

EBITDAX, operating profit before net finance costs and tax

EBITDAX for H1 2025 was $118 million, less than half the $279 million for H1 2024.

The operating profit for H1 2025 was $118.1 million compared to $201.8 million for H1 2024. 

Net hedging income of $51.8 million (H1 2024: net expense of $18.4 million) reflected a strong performance of the Group's hedge book, delivering unrealised hedging gains of $53.1 million (H1 2024: $14.9 million) and only very modest realised hedging losses of $1.4 million (H1 2024: $3.5 million losses). Unrealised hedging gains arose from the movement in valuation of Serica's H1 2025 period-end commodity hedge positions, primarily following a decrease in the Group's gas derivatives valuation prices (compared to hedged prices) from 31 December 2024 to 30 June 2025 resulting in a net mark to market asset of $15.7 million in H1 2025 compared to a net mark to market liability of $37.2 million in H1 2024. Realised hedging expense in both periods related to oil and gas commodity derivatives settling during the period.

Contract revenue of $5.4 million (H1 2024: $28.6 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 has been progressively released to the Income Statement across 2023, 2024 and H1 2025 as the underlying contract unwound, with the final unwind impact of $5.4 million included in H1 2025.

Administrative expenses for H1 2025 of $12.0 million was largely in line with H1 2024 expense of $11.7 million.

Profit before taxation and loss after taxation for the period

Profit before taxation for H1 2025 of $100.8 million (H1 2024: $188.5 million) included a $3.6 million charge arising from an increase in the fair value of financial liabilities (H1 2024: $2.9 million charge), $2.5 million of finance revenue (H1 2024: $6.9 million) and $16.2 million of finance costs (H1 2024: $17.3 million).

Finance revenue of $2.5 million (H1 2024: $6.9 million) primarily represented interest income earned on cash deposits and decreased as a result of lower cash balances held and lower interest rates achievable in the period compared to H1 2024. Finance costs of $16.9 million (H1 2024: $17.3 million) included interest payable and other charges on the RBL facility, the discount unwind on decommissioning provisions and other minor finance costs.

The H1 2025 taxation charge of $143.9 million (H1 2024: $106.0 million) comprised current tax charges of nil (H1 2024: $72.7 million) and a sharply increased deferred tax charge of $143.9 million (H1 2024: $33.3 million). The current tax charge for the Group was nil as a result of the application of group relief from tax losses which arose following the Triton field shutdown and ongoing significant capital expenditure on the Belinda and Evelyn fields during H1 2025. The deferred tax charge was significantly higher in H1 2025 due to deferred tax charges arising from capital expenditure on the Triton fields and a material one off deferred tax charge of $65.2 million in respect of the extension of the EPL from 31 March 2028 to 31 March 2030. The EPL extension was substantively enacted on 3 March 2025 and hence recognised for accounting purposes for the first time in H1 2025.

The combined effect of the lost production largely from the Triton Area in the period and the one-off non-cash tax charge, meant that the Group generated a loss after taxation for H1 2025 of $43.1 million compared to a profit after taxation of $82.5 million for H1 2024. This corresponded to a loss per share of 11 cents (H1 2024: earnings per share of 21 cents) after taking into account the weighted average number of ordinary shares in issue.

GROUP BALANCE SHEET

Serica retains a strong balance sheet with a conservative adjusted net debt to LTM EBITDAX ratio of 0.3x as at 30 June 2025 notwithstanding an LTM period reflecting the very significant impact of Triton outages. The continued position of balance sheet strength and ample liquidity gives the group flexibility in capital allocation including the ability to fund its ongoing and planned capital investment programmes while continuing to support distributions to shareholders despite a period of material production interruption.

Total property, plant and equipment increased from $991.6 million at year end 2024 to $1,100.2 million at 30 June 2025.

PP&E additions comprised book capital expenditure including accruals during H1 2025 of $142.5 million, with the vast majority in the Triton Area ($130.8 million) reflecting the impact of our drilling programme and a smaller amount at BKR ($11.7 million). The Triton Area expenditure included $72.7 million on the Belinda well and development, $46.2 million on the Evelyn EV02 well, and other life extension work on the Triton FPSO. The overall increase also included a $21.7 million currency translation adjustment, and these were partly offset by depletion charges for H1 2025 of $54.9 million.

The UK corporation tax receivable of $71.0 million at 31 December 2024 reflected a recovery of overpayments of corporation tax, supplementary charge, and EPL in respect of 2024, resulting primarily from the application of group relief. This balance was substantially received in June 2025.

The net deferred tax liability of $101.1 million at 30 June 2025 compares to a net deferred tax asset of $55.1 million at year end 2024. This comprised deferred tax liabilities arising on PP&E balances partially offset by the recognition of deferred tax assets in relation to tax losses and future relief available on decommissioning. The change from a net deferred tax asset position at 31 December 2024 to a net deferred tax liability at the end of H1 2025 is largely a result of additional deferred tax liabilities of $76.2 million created from the significant capital expenditure incurred in the period, and an increased deferred tax liability of $65.2 million arising following the enactment during H1 2025 of the extension of the EPL from 31 March 2028 to 31 March 2030. Deferred tax liabilities arising upon the Group's PP&E balances will be released in future periods as those balances are depleted.

The net derivative financial asset of $15.7 million at 30 June 2025 represents the mark to market valuation of gas ($5.4 million) and oil ($10.3 million) commodity swap and collar products in place at the period end. The 31 December 2024 net liability of $37.2 million comprised a derivative liability of $42.4 million arising from valuation of gas collars and swaps in place at the year-end based on higher mark to market gas prices as at that date, offset by $5.2 million of derivative asset from the valuation of oil collars and swaps. The change from the net derivative liability position in 2024 to a net derivative asset position in H1 2025 is primarily due to a decrease in the mark to market gas prices in H1 2025.

The increase in cash balances from $148.5 million at 31 December 2024 to $174.4 million at 30 June 2025 reflected net cash inflow from operating activities of $172.4 million (including tax recovery receipts of $70.6 million) mainly offset by capital expenditures paid of $137.8 million.

Current trade and other payables decreased to $159.8 million at 30 June 2025 from $168.3 million at the end of 2024.

The dividend payable of $53.8 million at 30 June 2025 (31 December 2024: $nil) represents the final cash dividend in respect of FY2024 of 10 pence (13 cents) per share approved at the annual general meeting on 22 May 2025 and paid after the period end in July 2025.

Non-current financial liabilities of $90.3 million (31 December 2024: $81.9million) comprise remaining deferred consideration projected to be paid under the BKR acquisition agreements of $56.7 million (31 December 2024: $49.7 million) and royalty liabilities of $33.6 million (31 December 2024: $32.2 million) for amounts payable to third parties under the terms of Triton asset acquisitions previously made by Tailwind. The increase in the non-current financial liabilities is due to unwinding of discount and the impact of higher currency translation adjustments.

Provisions of $152.4 million (31 December 2024: $146.0 million) predominantly relate to future decommissioning obligations. The increase from the prior year balance of $146.0 million was mainly due to unwinding of the discount applied as well as currency translation effects.

Interest bearing loans of $220.2 million at 30 June 2025 represent drawn amounts of $231.0 million net of unamortised facility fees of $10.8 million under the Group's $525 million RBL facility (31 December 2024: $219.1 million).

CASH BALANCES AND FUTURE COMMITMENTS

Current cash position and price hedging

At 30 June 2025 the Group held adjusted net debt of $57 million as compared to adjusted net debt of $83 million at 31 December 2024.

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 July 2025:

Oil hedges

Gas hedges

Field and other capital commitments

Following the completion of its 2024-25 drilling campaign in the Triton Area, Serica's remaining 2025 investment programme includes continued work on the Belinda development, and further capital work on the Bruce facilities including resilience upgrades as well as the early stages of a flare gas recovery project being implemented during the planned turnaround in August.

At 30 June 2025, the Group had commitments for future capital expenditure relating to its oil and gas properties which relate primarily to the ongoing Belinda development, Triton area work (including Bittern and FPSO life extension work), and certain other capital works on Bruce.

The Group's only significant exploration commitment work programme includes drilling an exploration well on Licence P2400 (Skerryvore prospect). Given the lack of clarity regarding the future fiscal and licensing regime, the joint venture applied for an extension to the period, and the NSTA has agreed to extend the P2400 licence to 31 March 2027.

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.

Additional Information

Additional information relating to Serica, can be found on the Company's website at www.serica-energy.com and on SEDAR at www.sedar.com.

Approved on behalf of the Board

Chris Cox

Chief Executive Officer

4 August 2025

Forward Looking Statements

This disclosure contains certain forward looking statements that involve substantial known and unknown risks and uncertainties, some of which are beyond Serica Energy plc's control, including: the impact of general economic conditions where Serica Energy plc operates, industry conditions, changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced, increased competition, the lack of availability of qualified personnel or management, fluctuations in foreign exchange or interest rates, stock market volatility and market valuations of companies with respect to announced transactions and the final valuations thereof, and obtaining required approvals of regulatory authorities. Serica Energy plc's actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward looking statements and, accordingly, no assurances can be given that any of the events anticipated by the forward looking statements will transpire or occur, or if any of them do so, what benefits, including the amount of proceeds, that Serica Energy plc will derive therefrom.

Serica Energy plc

Condensed Consolidated Income Statement

Serica Energy plc

Condensed Consolidated Statement of Comprehensive Income

Serica Energy plc

Condensed Consolidated Balance Sheet

Serica Energy plc

Condensed Consolidated Statement of Changes in Equity

Serica Energy plc

Condensed Consolidated Cash Flow Statement

Serica Energy plc

Notes to the Condensed Consolidated Financial Statements

1. Corporate information

The interim condensed consolidated financial statements of the Group for the six months ended 30 June 2025 were authorised for issue in accordance with a resolution of the directors on 4 August 2025.

Serica Energy plc ('the Company') is a public limited company incorporated and domiciled in England & Wales. The Company's ordinary shares are traded on the AIM in London. The principal activity of the Company is to identify, acquire and exploit oil and gas reserves.

2. Basis of preparation and accounting policies

Basis of preparation

The interim condensed consolidated financial statements for the six months ended 30 June 2025 have been prepared in accordance with International Accounting Standard 34 "Interim Financial Reporting".

These unaudited financial statements of the Group have been prepared following the same accounting policies and methods of computation as the consolidated financial statements for the year ended 31 December 2024. These financial statements do not include all the information and footnotes required by generally accepted accounting principles for annual financial statements and therefore should be read in conjunction with the consolidated financial statements and the notes thereto in the Serica Energy plc annual report for the year ended 31 December 2024.

The financial information contained in this announcement does not constitute statutory financial statements within the meaning of section 435 of the Companies Act 2006.

Going concern

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

As at 30 June 2025 the Group held cash and term deposits of $174.4 million. Separate RBL liquidity headroom of $259 million existed at 30 June 2025 ($231 million drawn versus $490 million available). See note 11 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 80 pence/therm for gas and US$70/bbl for oil for the whole period. 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 full six month period shut-in of Triton hub production for Q4 2025 and Q1 2026 and 25% reduced production volumes from the base case across the full portfolio of producing assets for Q2 and Q3 2026. Base case commodity pricing is retained for 2025 and Q1 2026 but lower commodity pricing of 50 pence/therm gas and US$60/bbl oil are assumed for the Q2 2026 and Q3 2026 periods 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 these 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.

Significant accounting policies

A number of new standards, amendments to existing standards and interpretations were applicable from 1 January 2025. The adoption of these amendments did not have a material impact on the Group's interim condensed consolidated financial statements for the period ended 30 June 2025.

The accounting policies adopted in the preparation of the interim condensed consolidated financial statements are consistent with those followed in the preparation of the Group's annual financial statements for the year ended 31 December 2024. The impact of seasonality or cyclicality on operations is not considered significant on the interim consolidated financial statements.

The Group financial statements are presented in $ and all values are rounded to the nearest thousand except when otherwise indicated.

Basis of consolidation

The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries Serica Holdings UK Limited, Serica Energy Holdings BV, Serica Energy Corporation, Petroleum Development Associates (Asia) Limited, Serica Energy (UK) Limited, Serica Energy Norte Limited, Serica GBA Limited, Serica Energy Investments Limited, Serica Energy Meltemi Limited, Serica Energy Mistral Limited, Serica Energy Sirocco Limited and Serica Energy Chinook Limited. Together, these comprise the 'Group'.

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.

All inter-company balances and transactions have been eliminated upon consolidation.

3. Segmental 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

5. Cost of sales

6. Group operating profit

Derivative financial instruments

The Group enters into derivative financial instruments with various counterparties. Commodity and foreign currency derivative contracts are designated as at fair value through profit and loss (FVTPL), and gains and losses on these contracts are recognised in the income statement. Derivative financial instruments held at 30 June 2025 and 31 December 2024 comprised swaps and collars for both oil and gas volumes. These were valued by counterparties, with the valuations reviewed internally and corroborated with readily available market data of forward pricing (level 2). Details of the Group's derivative financial instruments currently held are provided in the financial review above.

The mark-to-market of the Group's open contracts as at 30 June 2025 was a net asset of $15.7 million (31 December 2024: net liability of $37.2 million).

7. Finance costs

8. Dividends payable

A final cash dividend for 2024 of 10.0 pence per share was proposed in April 2025 and approved at the annual general meeting on 22 May 2025. Following the approval in the H1 2025 period, the dividend payable of £39.3 million ($53.9 million) is recognised as a liability in the Balance Sheet at 30 June 2025. The dividend was paid in July 2025.

Dividends on ordinary shares paid in 2024

A final cash dividend for 2023 of 14.0 pence per share was proposed in April 2024 and approved at the annual general meeting on 27 June 2024. Following the approval in the H1 2024 period, the dividend payable of £54.4 million ($68.8 million) was recognised as a liability in the Balance Sheet at 30 June 2024. The dividend was paid in July 2024.

An interim cash dividend for 2024 of 9.0 pence per share was announced in September 2024 and £35.0 million ($44.6 million) was paid in November 2024.

9. Exploration and evaluation assets

10. Property, plant and equipment