2025 Preliminary Results
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Pharos Energy plc
("Pharos" or the "Company" or, together with its subsidiaries, the "Group")
2025 Preliminary Results
A year of delivery and strength
Pharos Energy plc, an independent energy company with assets in Vietnam and Egypt, announces its preliminary results for the year ended 31 December 2025. An analyst presentation will take place at 09.00 GMT today by invitation only. If you would like to register to attend, please contact Camarco at pharosenergy@camarco.co.uk.
Katherine Roe, Chief Executive Officer, commented:
"Pharos made significant strides in 2025 to enter 2026 with strong momentum across our portfolio. In Vietnam, we commenced the six-well drilling campaign on TGT and CNV to support current production and unlock incremental volumes from these assets. On Blocks 125 & 126, approval of the two-year extension in June 2025 enabled a renewed and structured process to progress discussions with potential farm-in partners, which continues with active discussions. In Egypt, we were pleased to receive approval from EGPC for the consolidation of our two existing concessions, delivering an immediate uplift in value with 20-year lease extensions and improved fiscal terms. I am delighted that our receivable balance is now at its lowest level since December 2021 at $6.1m, due to the $20 million payment received from EGPC in December, doubling our year end cash balance.
"This stronger balance sheet provides the foundation to continue our track record of delivering tangible shareholder returns, with $6.5m of dividend payments in 2025. Today, the Board has recommended a final dividend for the 2025 financial year of $5.2m, 0.9317 pence per share, subject to shareholders' approval at the Company's 2026 AGM, taking the 2025 full year dividend to 1.331 pence per share, an increase of 10% on the prior year.
"Going into 2026, Pharos is well positioned for continued growth and delivery. With a geographically stable asset base, solid financial performance, and well-protected cash flows, we are well placed to weather challenging macroeconomic conditions. Our majority unhedged position enables us to take advantage of the high oil price environment while pursuing a balanced mix of growth opportunities. We continue to progress our Vietnam drilling programme, which is on track to complete by mid-2026, and look forward to updating the market on the results of these wells in April or early May. In Egypt, the first well on the agreed six-well work programme is expected to commence shortly. On our high impact exploration asset in Vietnam, we look forward to continuing current discussions with a view to securing a partner for Blocks 125 & 126. Additionally, we are progressing a number of opportunities to add scale and materiality to our business, enhancing the existing portfolio. With a strengthened balance sheet, Pharos is well positioned to continue delivering shareholder returns while investing in the next phase of growth.
"I would like to thank all of our stakeholders for their continued support, and I look forward to another year of progress and delivery."
2025 Operational Highlights
· Group working interest 2025 production totalled 5,398 boepd net, in line with guidance of 5,200 - 6,000 boepd:
o Vietnam 4,095 boepd
o Egypt 1,303 bopd
· Strong safety record maintained with zero LTIs
· Vietnam:
o On TGT & CNV: six-well offshore drilling programme commenced operations on 18 October 2025 consisting of two commitment appraisal wells and four infill wells:
§ TGT infill wells: two infill wells on the H1 and H5 fault blocks completed by year end. The wells were drilled on time, under budget, and are producing as expected. The final infill well on the H4 fault block reached total depth (TD) on 21 March 2026, and is expected to be brought into production in April
§ TGT-18X appraisal well: drilling completed on time and budget with testing underway; update to the market on the results of the testing expected in April or early May
§ CNV infill well: drilling of the CNV-8P infill well completed in mid-March
§ CNV-5X appraisal well: drilling commenced in mid-March and is expected to finish mid-2026
o On Blocks 125 & 126: two-year extension to the Exploration Period to November 2027 granted in June 2025. Discussions continue with potential farm-in partners
· Egypt:
o Approval received in September from EGPC Executive Board for the consolidated Concession Agreement, with improved fiscal terms effective from 5 October 2025, the date of full EGPC Board approval
o North Beni Suef (NBS) 3D seismic data processing and interpretation is complete, with a number of targets identified and two wells included in the committed work programme under the consolidated Concession Agreement
2025 Financial Highlights
· Group revenue of $114.6m 1,2 (2024: $136.1m 1,2)
· Cash generated from operations $85.5m (2024: $89.3m)
· Operating cash flow $55.6m 3 (2024: $54.0m)
· Cash operating costs 4 of $19.39/bbl (2024: $17.80/bbl)
· Net cash 4 as at 31 December 2025 of $40.2m, the Group is debt free (2024: $16.5m net cash 4)
· Receivables balance in Egypt at 31 December 2025 of $7.4m following total payments received of $37.7m
· Loss for the year of $6.6m (2024: profit $23.6m including net post-tax impairment reversals of $19.9m)
2025 Corporate Highlights
· Commitment to shareholder returns continue:
o Sustainable dividend policy delivered with an interim dividend of 0.363 pence per share for the 2024 financial year, totalling $1.8m, being paid on 22 January 2025. The final dividend for the year ended 31 December 2024 of 0.847 pence per share, totalling a further $4.7m, was approved by the shareholders at the Company's AGM in May 2025 and subsequently paid on 18 July 2025
o Returns to shareholders maintained with an interim dividend for the 2025 financial year of $2.2m, 0.3993 pence per share, paid on 21 January 2026
2026 Outlook
· Group working interest production guidance increased from 2025 to 5,200 - 6,400 boepd net:
o Vietnam 4,000 - 4,950 boepd
o Egypt 1,200 - 1,450 bopd
· Vietnam production:
o TGT & CNV: continuation of six-well drilling programme which is expected to finish by mid-2026
o The four infill wells in the programme are planned to maintain production at 2025 levels. Successes at both appraisal wells, TGT-18X and CNV-5X, could deliver up to a 20% increase in Vietnam production volumes and de-risk additional development opportunities
· Vietnam exploration:
o Blocks 125 & 126 formal farm-out process ongoing with discussions continuing; further updates expected by mid-2026
· Egypt:
o Drilling rig for El Fayum now secured, with second rig being contracted for North Beni Suef. Preparations underway for the approved budget and work programme of six wells; first well expected to commence drilling shortly
o Parliamentary ratification of the consolidated Concession Agreement expected later in 2026; 5 October 2025 retroactive date applies
· Final dividend of $5.2 million, equating to 0.9317 pence per share, to be paid in July 2026, to be proposed for shareholders' approval at the 2026 AGM; total dividend for the year of $7.4 million
· With the current volatility in commodity prices, modest hedging has been put in place to protect downside whilst also facilitating taking advantage of the upside
· Group cash capex for 2026 is expected to be $50m, of which $11m is for Egypt, and $39m is for Vietnam
· On track to achieve our Net Zero interim three-year target (2024-2026) of 5% emissions reduction compared to 2021 baseline
1 Egyptian revenues are stated post government take
2 No realised hedge gains or losses in 2025 (2024: realised hedged loss of $0.1m)
3 Operating cash flow = Net cash from operating activities, as set out in the Cash Flow Statement
4 See Non-IFRS measures on page 36
Enquiries
Pharos Energy plc Tel: 020 7747 2000
Katherine Roe, Chief Executive Officer
Sue Rivett, Chief Financial Officer
Camarco Tel: 020 3757 4980
Billy Clegg | Georgia Edmonds | Violet Wilson | Tamsin Howard
Notes to editors
Pharos Energy plc is an independent energy company focused on delivering sustainable growth and returns to stakeholders, with a portfolio of stable production, development and exploration assets in Vietnam and Egypt. Led by an experienced team, Pharos is a cash generative business with a robust balance sheet and an established platform to deliver both organic growth and inorganic opportunities.
Pharos is listed on the Main Market of the London Stock Exchange. For further information, please visit www.pharos.energy.
Chair's Statement
Strengthened business positioned for growth
I am pleased to present my first statement as Non-Executive Chair of Pharos Energy, having been appointed in June 2025 following John Martin's resignation from the Board at the 2025 AGM. I would like to thank John for his years of dedication and hard work in guiding Pharos through challenging times, and wish him well in his retirement.
A year of achievements
Since joining Pharos, I have been consistently impressed by the strength of the underlying business - a high-quality asset base delivering stable production and robust cash flows, a dedicated and highly motivated workforce, and a healthy balance sheet.
The operational and financial milestones achieved during 2025 are a testament to the Company's culture of capital discipline and commitment to shareholder value. In Vietnam, we are pleased to have commenced the six-well drilling campaign on TGT and CNV, the most significant investment into these assets since their original development, designed to drive production growth from both fields in 2026 and beyond. On Blocks 125 & 126, approval of the two-year extension to the PSC Exploration Period in June is very welcome progress as we continue discussions with potential farm-in partners in a structured process. In Egypt, we were pleased to receive approval from EGPC for the consolidation of our two existing concessions, with development lease extensions for up to 20 years and improved fiscal terms providing an attractive investment framework for both Pharos and our partner IPR. Most notably, I am delighted we ended the year with a $20 million payment from EGPC, doubling our year end balance sheet cash and reducing our outstanding receivable balance to $7.4m, its lowest level since December 2021.
Open dialogues and effective governance
I would like to thank our shareholders for their continued support and trust in Pharos. The Board maintains a strong commitment to high standards of governance through transparent, collaborative, and constructive dialogues with all our stakeholders. During the year, I met with our joint operating partners and government stakeholders, including EGPC, IPR, the Egyptian Minister of Petroleum and Natural Resources, and have been greatly encouraged by the open and receptive discussions. Their continued engagement and support were instrumental in delivering our key achievements this year, including approval of the consolidation of our concessions in Egypt, material reduction in our receivable balance with EGPC, the two-year licence extension on Blocks 125 & 126 and the commencement of the significant appraisal and infill drilling programme on TGT and CNV. Their support and confidence in Pharos underscore the strength of our relationships and reflect the shared recognition of Pharos' long-term commitment to the regions.
Sustainability at Pharos
Sustainability is embedded within our culture and remains integral to how Pharos operates our business. During the year, we continued to reduce our emissions by improving the efficiency of our operations and ensuring we have robust GHG and HSE monitoring systems and processes across all assets. We are on track to achieve our Net Zero interim target of 5% emission reduction at year end 2026 compared to the 2021 baseline, and we look forward to updating the market in due course.
Equally important is our commitment to the communities in which we work. Our aim is to be a positive presence and add value in everything we do, and charitable initiatives have been a part of the Company's culture since its inception. Throughout the year, Pharos contributed to the local communities through donations to support community development, social welfare, healthcare, and infrastructure programmes in areas where we operate. We believe these efforts will not only deliver meaningful social impact to our host communities, but also reinforce a strong sense of purpose and motivation among our global workforce.
Outlook
We entered 2026 as a strengthened business, with a resilient balance sheet, a quality asset base underpinned by safe and responsible operations, and a portfolio of exciting catalysts to pursue growth. We look forward to concluding our Vietnam drilling programme safely in mid-2026, and preparation with partners for the agreed work programme under the new consolidated concession in Egypt is underway, further strengthening our operational base. In parallel, we are progressing our discussions with potential farm-in partners on Blocks 125 & 126 and stepping up our efforts to identify opportunities beyond our existing portfolio, dedicating resources to ensure we are active participants in the market.
Our focus on both organic and inorganic growth will continue to be guided by capital discipline. The Board maintains a clear commitment to our capital allocation goals: to balance returns to shareholders with investment in our assets to generate growth, while preserving the resilience of the balance sheet.
On behalf of the Board, I would like to thank the Pharos team for their commitment and delivery throughout the year. I am also grateful to our shareholders for their trust, and our partners, suppliers, and advisors for their support. The Board looks to the future with great confidence in our ability to deliver growth and value in 2026 and beyond.
João Saraiva e Silva
Non-Executive Chair
Chief Executive Officer's Statement
A year of operational momentum, financial strength, and strategic growth
I am pleased to report that 2025 was another year of strength for Pharos Energy. During the year, the Company achieved both financial and operational successes delivering against expectations and achieving pivotal milestones in both Vietnam and Egypt, while maintaining our exceptional record of safety and operational reliability. Activity throughout the year has enhanced the quality of our assets, established operational momentum, and delivered a robust financial base for further organic and inorganic growth.
Operational achievements underpinning financial strength
The Company had an operationally active year in 2025. We are excited to be drilling offshore in Vietnam again, and our debt-free balance sheet has supported the commencement of a six-well infill and appraisal drilling programme on TGT and CNV in the second half of the year, the most significant investment into these assets since their original development. We are proud that our successes to date on these operationally challenging wells were achieved on time and on budget, with no safety incidents during the year, maintaining our zero lost-time injury rate since operational inception. This excellent health and safety record is thanks to the JOCs' consistent effort to promote and champion workers' health and safety, and a culture at Pharos that puts safety at the heart of the business.
In Egypt, we were pleased to announce at the end of the financial year a $20 million payment from EGPC for oil sales, doubling our year end cash balance and reducing our outstanding receivable balance to $7.4m, its lowest level since December 2021. This very welcome progress towards the recovery of our receivables, coupled with improvements in the macro environment in Egypt, have provided us with comfort that outstanding receivables will continue to be paid and that typical payment terms will be applied to future oil sales. Most importantly, a key milestone in unlocking further value in our Egyptian asset was the approval by EGPC of the consolidation of our two concessions, El Fayum and North Beni Suef, into a single new concession agreement. We expect the new agreement, incorporating an extension of up to 20 years to the development leases to be signed later in 2026, following ratification by the Egyptian Parliament. The improved fiscal terms under the consolidated concession agreement will have retrospective effect from 5 October 2025, and set an attractive investment environment for both Pharos and our partners to pursue additional production volumes and reserves. We will nonetheless continue our cautious approach to capital allocation whilst we continue the recovery of our outstanding receivables.
Protected balance sheet to pursue opportunities and deliver returns
Oil prices decreased substantially during 2025 due to challenging supply-demand imbalance and persistent geopolitical risks. This underpins the need to ensure independent E&Ps like Pharos maintain a resilient business model to weather unpredictable oil price cycles. Throughout the years, our operations in Vietnam have remained robust even in low oil price environments thanks to high premiums and low break-even prices. In Egypt, the flexibility that our onshore operations offer means we remain agile in changing economic landscapes and can adjust the pace of investment into the assets based on the receivable recovery rate. Pharos is protected on the downside, and we have a portfolio of upside potential to pursue across the assets.
We believe the oil price outlook will remain challenging in 2026 due to volatility initiated by the US, Israel, Iran conflict. Therefore, a diversified portfolio with robust operational and financial strength is crucial for Pharos' next phase of growth. Our financial discipline and debt-free position not only give us the optionality to identify and pursue the right opportunities, both within the current portfolio and externally, but also take a pragmatic and balanced approach to shareholder returns. Today, the Board have recommended a final dividend for the 2025 financial year which, subject to shareholders' approval at the Company's 2026 AGM, would take the 2025 full year dividend to 1.331 pence per share. The Board will continue to consider an appropriate level of returns to shareholders given the strength of the balance sheet whilst managing capital allocation for growth.
Blocks 125 & 126 - Unique frontier exploration in South East Asia
We are proud to have a basin-opening frontier play with world-class potential in our current portfolio. Thanks to the diligent efforts and technical capability of our in-country team, we now have a well-understood, drillable prospect with detailed engineering studies, 2D and 3D seismic data, long lead items, mature leads and prospects, and an independent reserves report supporting Pharos' internal assessment. All our work to date has highlighted the scale and potential of these basin-opening exploration blocks, and we are motivated to pursue this incredible opportunity whilst still preserving the resilience of the business and stability of the balance sheet. Last year we initiated a formal, structured process to identify a farm-in partner and complete all necessary preparatory and planning work to drill the first exploration well. Additionally, the two-year licence extension, granted by the Vietnamese Government in June last year, has strengthened our position and provided optionality as we progress discussions with rig contractors and third-party buyers. We are intentional in our testing of the market at a time when exploration has moved up the agenda for many majors, and discussions with potential partners are in advanced stages. We strive to deliver the best value for our shareholders and will look to monetise the asset at the right terms and the right time. We look forward to updating the market with more news in mid-2026.
Scale and business resilience
We recognise that the operating environment for independent E&Ps remains challenging. While Pharos has consistently delivered strong results, the Board understands that scale, strategic relevance and efficiencies remain a key priority. Further growth will give us the scale that is increasingly important in our industry, creating resilience against adverse macro changes, providing access to additional investment capital, thus allowing us to compete more effectively in the energy market and create long-term value. In recognition of this, the Board regularly evaluates strategic priorities, ensuring that we direct resources to opportunities that can drive growth and returns for shareholders. As a result, in evaluating prospects outside the existing portfolio, we are return-driven rather than jurisdiction-driven. Nevertheless, we continue to leverage our technical expertise, long-standing presence in South East Asia, and positive relationships with our host government partners to identify the right assets that can deliver the best returns for us.
Our role in the energy transition
Pharos is fortunate to operate in jurisdictions with thriving economic and investment landscapes. Oil and gas demand in Asia-MENA is expected to remain robust, driven by population expansion and a move away from more GHG emissions-intensive fuel sources, such as coal, for power generation. The Egyptian Government recognises the industry's need to encourage more upstream investment, and Egypt's Minister of Petroleum and Mineral Resources has outlined his intent to improve the investment environment to boost oil and gas production in the country, satisfying domestic demand and reducing the country's reliance on imports. In Vietnam, since our entry into the country in 1996, our producing fields TGT and CNV have contributed to the replacement of coal as a cleaner energy source. We are proud that 100% of Pharos' oil and gas production is sold and consumed domestically, providing low cost and reliable energy access to alleviate energy poverty and promote sustainable economic development across the region.
Our goal is to be a positive presence in the regions where we operate by providing responsible and sustainable development, creating value for host countries and local communities as well as for our own shareholders and employees. In our view, oil and gas will remain an important component of the global energy mix for many years to come. We recognise and actively consider the impact of climate change and energy transition as immediate challenges facing Pharos and will continue to operate our business in a safe, environmentally sustainable, and socially responsible way.
Mutually beneficial partnerships to deliver shared prosperity
We announced in June 2025 the appointment of João Saraiva e Silva as Non-Executive Chair, succeeding John Martin who announced his retirement from the Board at the Company's 2025 AGM in May. We are delighted to welcome João to the Board and believe we now have a stable, refreshed Board with a balanced mix of skills and experience to guide Pharos through its next phase.
The Board is committed to maintaining a high standard of governance. We are once again pleased to report full compliance with the UK Corporate Governance Code for the financial year, including as it relates to regular engagement with major shareholders. Our team continued the regular and proactive dialogue with key shareholders and wider stakeholders throughout the year, and we appreciate and understand the importance of their views as owners and partners of the business. The successes the Company has had over the years would not have been possible if not for the supportive relationships we have with our valued partners and stakeholders, and we are grateful for their ongoing support.
Outlook
Pharos made significant strides in 2025 to strengthen the underlying business, being one with a stable asset base, solid financial performance, well-protected cash flows, and an exciting mix of opportunities to pursue in 2026 and beyond.
We have near-term upside in both jurisdictions to grow our production, as well as stemming natural production decline. In Vietnam, we continue our fully funded six-well infill and appraisal drilling programme which is expected to conclude by mid-2026. The four infill wells are intended to maintain existing production levels, whilst success at both appraisal wells, TGT-18X and CNV-8P, could deliver up to a 20% increase in Vietnam production volumes and also de-risk additional development opportunities. We expect to update the market on the results of the testing in April or early May. In Egypt, following EGPC's approval of the consolidation of our two existing concessions in October 2025 and a $20 million payment from EGPC towards the receivable balance at year end, we enter the year with a much-improved investment environment to unlock further value from these assets. Preparation for the agreed six-well work programme on El Fayum and North Beni Suef is well underway, and we expect to be more operationally active in Egypt in 2026. On the exploration side, we are in advanced discussions with potential farm-in partners on Blocks 125 & 126 and look forward to updating the market in mid-2026.
We are pleased to start 2026 from a position of strength. Our investment proposition remains compelling, with significant operational momentum, a healthy balance sheet, a portfolio of quality assets with growth catalysts, and a sharp focus on developing the scale and relevance of the business with inorganic opportunities, all with the right team in place to deliver on our strategic goals.
I would like to thank my colleagues and stakeholders for their continued support and look forward to another year of strength and delivery in 2026.
Katherine Roe
Chief Executive Officer
Operational Review
Operations
The Group's working interest 2025 production was 5,398 boepd net, in line with the Group's production guidance of 5,200 to 6,000 boepd.
Vietnam
Vietnam Production
Production in 2025 from the TGT and CNV Fields net to the Group's working interest averaged 4,095 boepd. This is in line with the 2025 production guidance for Vietnam of 3,600 - 4,600 boepd net.
TGT production averaged 10,792 boepd gross and 3,202 boepd net to the Group. CNV production averaged 3,572 boepd gross and 893 boepd net to the Group.
Vietnam Development and Operations
TGT & CNV Fields
In 2025, Pharos commenced its six-well infill and appraisal drilling programme, the most significant investment into its Vietnamese assets since the initial development, that is designed to drive material production growth from both fields. The programme, which comprises four TGT wells and two CNV wells, employs two drilling rigs running in parallel. Drilling operations on TGT will be completed using the GunnLod Drilling Rig, and CNV using the Thor Drilling Rig.
On TGT, the first two infill wells, targeting the H1 and H5 fault blocks, were completed by the year end with encouraging results in line with pre-drill expectations. Both wells have already been brought into production. We reached total depth (TD) on the final infill well on the H4 fault block on 21 March 2026, and we expect to bring this well into production in April.
Drilling of the TGT-18X appraisal well, targeting the field's untapped south-western area, completed on time and budget in February, and testing is currently ongoing. We expect to update the market on the results of the testing in April or early May.
On CNV, drilling of the CNV-8P infill well commenced in December and completed in mid-March. The well is expected to be on production in a couple of weeks. The rig has now moved and is drilling the CNV appraisal well, CNV-5X, and is expected to finish mid-2026.
Vietnam Exploration
Blocks 125 & 126
The Company continued to optimise its prospects and leads portfolio with detailed drilling engineering studies for the well on Prospect A. Most notably, the application for a two-year extension of the Blocks 125 & 126 PSC Exploration Period was granted by the Vietnamese Government in June 2025, extending the Exploration Period to 8 November 2027. This extension reflects the Government's continued support for Pharos and underlines our commitment to the region.
Additionally, in 2025, Pharos engaged an independent third-party adviser to support a formal process intended to identify a potential farm-in partner before exploration drilling commences with very encouraging engagement. In parallel, discussions continue with rig contractors to retain optionality for the prospect to be drilled.
2026 Vietnam Work Programme
TGT & CNV Fields
The six-well programme on the TGT and CNV Fields will continue and is expected to finish by mid-2026.
The four infill wells in the programme, once completed and brought on to production, are planned to maintain production at 2025 levels. Successes at both appraisal wells, TGT-18X and CNV-5X, could deliver up to a 20% increase in Vietnam production volumes and de-risk additional development opportunities.
Vietnam production guidance for 2026 is 4,000 - 4,950 boepd net.
Egypt
Egypt Production
Production in 2025 from the El Fayum and NBS concessions net to the Group's working interest averaged 1,303 bopd. This is slightly lower than 2025 production guidance for Egypt of 1,400 - 1,600 bopd net. This reflects natural decline in production from the existing wells without investment while awaiting approval from EGPC of the consolidation of the two concessions and the associated commitment work programme.
El Fayum production averaged 2,768 bopd gross and 1,246 bopd net to the Group. NBS production averaged 127 bopd gross and 57 bopd net to the Group.
Egypt Development and Operations
El Fayum
Following its commercial discovery in February 2025 and the subsequent award of the Development Lease, the East Saad-1X well was put on production from 1 July.
Egypt Exploration
North Beni Suef
The processing and interpretation of c.130 km2 of 3D seismic data on NBS is complete, with a number of targets identified and two wells included in the 2026 work programme.
Egypt Commercial
On 23 September, Pharos announced that it had received approval from the Executive Board of EGPC for the consolidation of the El Fayum and North Beni Suef Concession Agreements into a new consolidated concession agreement (the "Consolidated Concession"). Pharos will retain a 45% working interest in the Consolidated Concession, with IPR continuing as operator with a 55% working interest. In addition to the 12 development leases of the EF and NBS Concessions, the Consolidated Concession will include three new exploration areas.
The Consolidated Concession unlocks significant value in the Western Desert by improving certain fiscal terms, extending the duration of the licenses, and committing the Contractor parties (Pharos Group and IPR) to additional work programmes to deliver production growth. Based on Pharos' Competent Person's Reports as at 31 December 2024, the Consolidated Concession could result in moving approximately 3.1 MMstb from contingent resources to 2P reserves, or a 25% increase from year end 2024, net to Pharos working interest.
The Consolidated Concession is subject to customary approvals and to Egyptian Parliamentary ratification, which is expected to take place in 2026. Once ratified, the improved fiscal terms will have retrospective effect from 5 October 2025, the date of full EGPC Board approval.
2026 Egypt Work Programme
El Fayum & North Beni Suef
Egypt production guidance for 2026 is 1,200 - 1,450 bopd net.
Preparations for the agreed work programme in El Fayum and North Beni Suef are underway, with one drilling rig now secured for El Fayum, and another being contracted for North Beni Suef. The programme, which includes four wells on El Fayum and two on North Beni Suef, is expected to commence shortly. The two rigs will run simultaneously and are expected to finish drilling operations by the end of 3Q. Once completed, the full programme is expected to increase production from Egypt by c.20% by 2027 compared to year end 2025 level.
Health, Safety and Environment (HSE)
On health and safety, we are pleased to report that in Egypt and Vietnam, we have worked with our partners to maintain our record of zero Lost Time Injury (LTI) in 2025. The health and safety of our workforce remain our highest priority, and we are committed to operating safely and responsibly at all times to provide a safe and healthy working environment for staff and contractors.
On environmental matters, during 2025, while Pharos had no recordable spills in Vietnam, we recorded one spill in Egypt due to an overturned road tanker truck on the Cairo-Suez desert road. The concerted efforts from the Suez Civil Protection Authority, SOPC, Petrosilah, Al Nasr Petroleum Company (NPC) and White Eagle Company helped to completely clear the accident site, clean up remaining hydrocarbon spill and reopen the road to traffic. The incident was investigated and lessons learned as appropriate and actions to prevent recurrence were implemented.
On emissions, while operational activities in 2025 have increased compared to 2024, our total emissions have continued to decrease year-on-year. This is driven by the JOCs' continued careful management of gas flaring by monitoring and optimising the processing facilities in the TGT FPSO in Vietnam. In Egypt, we have continued to deploy gas generators at the well sites, connected the camp and mess hall in Silah base to the electricity grid and successfully installed the first hybrid fuel (solar photovoltaics and diesel) pump system in Silah. These actions have reduced diesel consumption and associated emissions from our operations in Egypt and keep us on track to achieve our Net Zero interim short-term three-year target (2024-2026) of 5% emissions reduction. Pharos will continue to work closely with our operating partners to identify opportunities to reduce emissions to ensure we achieve our climate targets.
Group Reserves and Contingent Resources
The Group Reserves Statistics table below summarises our reserves and contingent resources based on the Group's unitised net working interest in each field.
Group Reserves Statistics
|
Net working interest, mmboe |
Vietnam |
Egypt |
Group |
|
Oil and Gas 2P Commercial Reserves1,2 |
|
|
|
|
As at 1 January 2025 |
8.9 |
12.4 |
21.3 |
|
Production |
(1.5) |
(0.5) |
(2.0) |
|
Revision |
(0.2) |
(0.7) |
(0.9) |
|
2P Commercial Reserves as at 31 December 2025 |
7.2 |
11.2 |
18.4 |
|
|
|
|
|
|
Oil and Gas 2C Contingent Resources1,2 |
|
|
|
|
As at 1 January 2025 |
7.8 |
8.3 |
16.1 |
|
Revision |
- |
0.7 |
0.7 |
|
2C Contingent Resources as at 31 December 2025 |
7.8 |
9.0 |
16.8 |
|
|
|
|
|
|
Total of 2P Reserves and 2C Contingent Resources as at 31 December 2025 |
15.0 |
20.2 |
35.2 |
1) Reserves and Contingent Resources are categorised in line with 2018 SPE/WPC/AAPG/SPEE /SWLA Petroleum Resource Management System.
2) Assumes an oil equivalent conversion factor of 6,000 standard cubic feet per barrel of oil equivalent.
Group's Net Working Interest Reserves and Contingent Resources
Vietnam at 31 December 2025 (mmboe) (net to Group's working interest)
|
Reserves2 |
1P |
2P |
3P |
|
Oil |
5.1 |
6.0 |
6.7 |
|
Gas1 |
0.9 |
1.2 |
1.3 |
|
Total |
6.0 |
7.2 |
8.0 |
|
|
|
|
|
|
Contingent Resources2 |
1C |
2C |
3C |
|
Oil |
4.1 |
6.5 |
8.9 |
|
Gas1 |
0.8 |
1.3 |
1.9 |
|
Total |
4.9 |
7.8 |
10.8 |
|
|
|
|
|
|
Sum of Reserves and Contingent Resources3 |
1P & 1C |
2P & 2C |
3P & 3C |
|
Oil |
9.2 |
12.5 |
15.6 |
|
Gas1 |
1.7 |
2.5 |
3.2 |
|
Total |
10.9 |
15.0 |
18.8 |
1) Assumes oil equivalent conversion factor of 6,000 standard cubic feet per barrel of oil equivalent.
2) Reserves and Contingent Resources have been prepared by the Company.
3) The summation of Reserves and Contingent Resources has been prepared by the Company.
Egypt at 31 December 2025 (mmboe) (net to Group's working interest)
|
Reserves1 |
1P |
2P |
3P |
|
Oil |
5.8 |
11.2 |
13.1 |
|
|
|
|
|
|
Contingent Resources1 |
1C |
2C |
3C |
|
Oil |
3.3 |
9.0 |
17.7 |
|
|
|
|
|
|
Sum of Reserves and Contingent Resources2 |
1P & 1C |
2P & 2C |
3P & 3C |
|
Total |
9.1 |
20.2 |
30.8 |
1) Reserves and Contingent Resources have been prepared by the Company.
2) The summation of Reserves and Contingent Resources has been prepared by the Company.
Chief Financial Officer's Statement
Strong financial performance and cash growth
Our operations delivered a solid financial performance and cash generation in 2025, further strengthening our liquidity position despite the challenges of lower commodity prices. We remain debt free following the full and voluntary repayment of the RBL facility in the prior year and our net cash position has grown to $40.2m compared to $16.5m reported at the end of December 2024. This was partially achieved through the successful recovery of a bullet payment of $20 million from EGPC on 31 December 2025. This reduced our outstanding Egypt receivable balance to $7.4m, our lowest receivable balance since December 2021.
Returns to shareholders have been delivered through the completion in January 2025 of the third $3m share buyback programme and the payment of an interim dividend for 2024 of 0.363 pence per share, $1.8m equivalent, in January 2025. A final dividend for 2024 of 0.847 pence per share, $4.7m equivalent, following approval at the AGM in May 2025, was paid to shareholders in July 2025. In addition, an interim dividend of 0.3993 pence per share, $2.2m equivalent, in respect of the year ended 31 December 2025 was paid to shareholders in January 2026, and a final dividend to be paid in July 2026 of 0.9317 pence per share, $5.2m equivalent, will be proposed to shareholders at this year's AGM.
Operating performance
Revenues
Group revenues of $114.6m, with no hedging gain or loss realised during the year (2024: $136.1m prior to realised hedging loss of $0.1m), were adversely affected by a 13% fall in realised commodity prices and a 1% decrease in sales volumes.
Revenues for Vietnam of $99.8m (2024: $115.4m) decreased as a result of lower realised prices, as sales volumes were comparable year on year at 4,156 boepd (2024: 4,161 boepd). The average realised crude oil price was $74.29/bbl (2024: $85.52/bbl), a 13% decrease year on year, and the premium to Brent was over $5/bbl on average which was comparable to prior year. Production was lower at 4,095 boepd (2024: 4,361 boepd) and, combined with lower commodity prices, this has led to an inventory reduction of $3.1m for the Vietnam producing fields compared to an inventory build of $6.0m during 2024, following the maintenance shutdown at the BSR-owned Dung Quat refinery during the first part of 2024. As inventories are valued at net realisable value, this has led to $9.1m adjustment in cost of sales as a result of changes in inventory year on year.
The revenue for Egypt of $14.8m (2024: $20.7m) decreased year on year, inclusive of $0.4m (2024: $1.9m) gross-up for corporate income taxes to be paid by EGPC on behalf of Pharos El Fayum. The average realised crude oil price, after discounts, was $63.73/bbl (2024: $74.83/bbl), a decrease of 15%. There are two discounts applied to the Egypt crude production - a general Western Desert discount and one related specifically to El Fayum. Both are set by EGPC (the in-country regulator) and combined were just under $6/bbl for the year (2024: just under $6/bbl). Production from Egypt was lower at 1,303 bopd (2024: 1,440 bopd).
Hedging
During 2025, the Group entered into zero cost collar hedges to protect the Brent component of forecast oil sales and to provide downside protection to cash flows in the event of commodity prices falling. At 31 December 2025, the commodity hedges run until March 2026 and are settled monthly. Our hedging positions for the year resulted in no realised gain or loss (2024: realised loss of $0.1m). Additionally, the fair value as at 31 December 2025 was an unrealised loss of $0.2m (31 December 2024: unrealised gain of $0.1m).
For full year 2025, 29% of the Group's total oil entitlement production was hedged, securing average floor and ceiling prices for the hedged volumes at $62.6/bbl and $87.1/bbl, respectively.
Operating costs
Group cash operating costs, defined in the Non-IFRS measures section on page 36, were $38.2m (2024: $37.8m). Vietnam decreased by 5% from $29.1m to $27.7m in 2025. The decrease is partly due to costs relating to the FPSO as a result of higher 3rd party production throughput from the TLJOC, which decreased the HLJOC's share of the costs (TLJOC had 26.4% cost share in 2025 compared to 23.4% in 2024).
Cash operating costs in Egypt increased by 21% from $8.7m to $10.5m in 2025. The increase was mainly due to higher well workover costs during 2025 and a higher proportion of cost allocations to operating expenditure, due to a reduced capital drilling programme.
|
Cash operating cost per barrel 1 |
2025 $m |
2024 $m |
|
Cost of sales 2 |
96.4 |
87.3 |
|
(Less)/add |
|
|
|
Depreciation, depletion and amortisation |
(46.4) |
(47.1) |
|
Production based taxes |
(7.3) |
(9.2) |
|
Change in inventories |
(3.2) |
6.0 |
|
Trade receivables expected credit loss |
1.3 |
2.5 |
|
Other cost of sales |
(2.6) |
(1.7) |
|
Cash operating costs |
38.2 |
37.8 |
|
Production (BOEPD) |
5,398 |
5,801 |
|
Cash operating cost per BOE ($) |
19.39 |
17.80 |
1 Cash operating cost per barrel and DD&A per barrel are alternative performance measures. See pages 36 and 37
2 Includes impairment reversal of financial asset
DD&A
Group DD&A associated with the producing assets decreased to $46.4m (2024: $47.1m). DD&A charges from Vietnam decreased marginally to $41.4m (2024: $42.1m) and this was driven by 6% fall in production year on year, partially offset by the impact of higher book values of TGT and CNV assets following the impairment reversals recorded in December 2024. The combination of these factors meant that DD&A per barrel for Vietnam increased 5% to $27.70/boe (2024: $26.38/boe).
DD&A charges from Egypt stayed the same year on year at $5.0m, as the decrease in production was offset by the impact of the impairment reversal recorded in 2024. DD&A per bbl for Egypt is $10.51/boe (2024: $9.49/boe).
Administrative expenses
Administrative expenses in 2025 of $8.8m (2024: $9.1m) were lower than prior year. After adjusting for non-cash IFRS2 Share Based Payments of $1.6m (2024: $0.9m), the underlying administrative expenses were lower by 12% at $7.2m (2024: $8.2m).
Other operating expenses
Other operating expenses in 2025 were $0.3m (2024: $0.8m). In 2024, other operating expenses included $0.6m in relation to the posthumous vesting of share scheme awards to the former CEO of the Company, which was formally approved by the Remuneration Committee, settled in cash and paid to his estate with the agreement of the executor. A further $0.2m in the prior year related to closure costs in respect of the US office, where the former CEO of the Company was based.
Operating profit
Operating profit from continuing operations for the year was $8.7m (2024: $38.0m) excluding the net impairment reversal of $26.3m in 2024, reflecting the combined impact of a decrease in production volumes and a lower commodity price environment during the year. In 2025, after considering the existence of any internal and external indicators of impairment, the Group determined that no impairments or impairment reversal indicators were identified on any of the Group's oil and gas producing properties and no impairment tests were considered necessary as at 31 December 2025.
(Loss)/gain on fair value movement of financial asset
As part of the 2022 farm-down of 55% of the Egypt concessions, Pharos is entitled to contingent consideration depending on the average Brent price each year from 2022 to the end of 2025 (with floor and cap at $62/bbl and c.$90/bbl respectively). The contingent consideration is calculated yearly and is capped at a maximum total payment of $20.0m. The change in contingent consideration is booked under gain/(loss) on fair value movement of financial asset. During 2025, contingent consideration of $2.9m in respect of the average Brent price during 2024 was received from IPR and a further $0.3m will be received in 2026. At 31 December 2025, $1.7m of contingent consideration was included in current trade and other receivables (2024: $5.1m, $3.3m in current trade and other receivables and $1.8m in other non-current assets).
The loss on fair value movement of financial asset for the year of $0.5m (2024: $0.3m gain) is due to downwards revision of the contingent consideration, which reflected a reduction in the forward Brent price estimation.
Finance costs
Finance costs significantly decreased to $2.2m (2024: $3.9m), following full voluntary repayment of the Group's RBL facility during September 2024. In 2024, interest expense and similar fees of $1.1m were incurred in relation to the RBL facility and National Bank of Egypt (NBE) credit facility. The unwinding of discount on Vietnam decommissioning provisions for 2025 was $2.3m (2024: $2.2m). There was also net foreign exchange gains of $0.1m (2024: foreign exchange losses of $0.6m).
Taxation
The overall net tax charge of $13.1m (2024: $37.1m) principally relates to tax charges in Vietnam of $12.7m (2024: Vietnam tax charges of $26.8m and the deferred tax charge on impairment reversals of $8.4m).
The Group's effective tax rate approximates to the statutory tax rate in Vietnam of 50%, after adjusting for non-deductible expenditure and tax losses not recognised.
The Egypt concessions are subject to corporate income tax at the standard rate of 40.55%, however responsibility for payment of corporate income taxes falls upon EGPC on behalf of PEF and the other contractor parties. The Group records a tax charge, with a corresponding increase in revenue, for the tax paid by EGPC on its behalf. As the historic tax loss position since first production had reversed in full during 2024, this led to a $0.4m tax charge being recorded (2024: $1.9m).
One of the Group's companies entered into commodity zero cost collars designated as cash flow hedges. In accordance with IAS 12, a deferred tax asset has not been recognised in relation to hedging losses of $0.1m recorded in 2024 as it is unlikely that the UK tax group will generate sufficient taxable profit in the future, against which the deductible temporary differences can be utilised.
(Loss)/profit post-tax
The post-tax loss for the year was $6.6m (2024: $23.6m post-tax profit).
Cash flow
Operating cash flow (before movements in working capital) was $56.5m (2024: $84.3m), which is consistent with the reduction in realised commodity prices. After tax charges of $30.3m (2024: $35.3m), restructuring and exceptional expenses of $nil (2024: $0.4m), working capital inflow of $29.0m (2024: $5.0m) and net interest received of $0.4m (2024: $0.4m), the cash generated from operations was $55.6m (2024: $54.0m).
Cash generated from operations, after tax charges, exceptional expenses and working capital movements, is the basis of our dividend framework.
The decrease in receivables was $26.2m (2024: $11.3m). The movement in 2025 is primarily driven by $20.6m decrease from Egypt (2024: $4.8m) following a $20m bullet payment from EGPC on the last day of the year, which reduced the outstanding receivable balance to $7.4m; its lowest level since December 2021.
There was a further $5.5m decrease from Vietnam (2024: $6.4m) due to 22% lower volume of cargoes lifted in December 2025 compared to prior year, combined with the reduction in commodity prices. Payments for the December 2024 cargoes were received in January 2025 and December 2025 cargoes were received in January 2026.
Capital expenditure for the year was 6% higher at $27.6m (2024: $26.1m). In Vietnam, a fully funded six-well offshore drilling programme commenced operations on 18 October 2025. On TGT, there was the completion of two infill wells on the H1 and H5 fault blocks and both wells were brought into production by the end of the year. The TGT-18X appraisal well, targeting the block's untapped south-western area, and the CNV-8P infill well, also commenced in December 2025 and operations on both wells are ongoing.
Net cash outflows from financing activities of $7.0m (2024: $51.6m outflow) included $0.3m in relation to completion of the final $3.0m tranche of the company's share buyback programme in January 2025 (2024: $2.9m) and $6.5m outflow (2024: $5.9m) following payment of the interim and final dividends of $1.8m and $4.7m respectively for the 2024 financial year. The final dividend for the 2024 financial year was approved by shareholders at the AGM in May 2025.
Financing activities for 2024 also included outflows in relation to the Group's Reserve Based Lending (RBL) facility of $30.0m. The RBL facility, which was secured only over the Group's interest in the Vietnam producing assets, matured in July 2025. In addition, there was a net outflow of $9.2m from the National Bank of Egypt (NBE) revolving credit facility. This facility allows Pharos El Fayum Limited to draw down 60% of the value of each El Fayum invoice in USD. The amount drawn under the NBE facility as at 31 December 2025 and 31 December 2024 was $nil and the Group remains debt free.
Tax strategy and total tax contribution
Tax is managed proactively and responsibly with the goal of ensuring that the Group is compliant in all countries in which it holds interests. Any tax planning undertaken is commercially driven and within the spirit as well as the letter of the law.
This approach forms an integral part of the Group's sustainable business model.
The Group's Code of Business Conduct and Ethics seeks to build open, cooperative and constructive relationships with tax authorities and governmental bodies in all territories in which it operates. Our Tax Strategy statement can be found on our website at www.pharosenergy/responsibility/policy-statements/. The Group supports greater transparency in tax reporting to build and maintain stakeholder trust. We have a number of overseas subsidiaries which were set up some time ago and the Group is now proactively planning to bring these into the UK tax net to ensure greater transparency and comparability. No additional taxes are expected to be due as a result of this exercise.
During 2025, the total payments to governments for the Group amounted to $133.6m (2024: $160.3m), of which $116.5m or 87% (2024: $138.7m or 87%) was related to the Vietnam producing licence areas, of which $77.8m (2024: $92.9m) was for indirect taxes based on production entitlement. In Egypt, payments to government totalled $14.6m (2024: $19.1m), of which $14.2m (2024: $18.5m) related to indirect taxes based on production entitlement.
Balance sheet
Intangible assets increased during the year to $26.5m (2024: $21.8m). Additions for the year related to charges for Blocks 125 & 126 in Vietnam of $6.9m, including $3.7m of drill casings and long-lead items ahead of drilling the first commitment well, and Egypt of $0.7m.
In Egypt, as part of the planned work programme for 2024, an exploration well, the East Saad-1X well, was drilled on El Fayum in August 2024. Testing of the well was carried out at the beginning of February 2025. Following testing, IPR, the operator of the El Fayum Concession, applied to EGPC for declaration of a commercial discovery and early production permission in February 2025. The East Saad Development Lease was awarded and first production commenced in July 2025. As a result, exploration costs of $2.9m were reclassified to property, plant and equipment in 1H 2025.
Impairments and Impairment Reversals
We have evaluated each of our oil and gas producing properties for impairment or impairment reversal triggers. For each producing property with such triggers, the recoverable amount held on the books would be determined using the value in use method. The recoverable amount is calculated using a discounted cash flow valuation of the 2P production profile.
The average Brent price forecast as at Dec 2025 fell by 9% for 2026 to 2030 and 7% in the longer-term compared to the forecast at the end of 2024 and does not indicate a significant change in the underlying value of oil and gas assets. Furthermore, there were no significant changes to macroeconomic factors such as risk-free rate, equity market risk premium and country risk premiums, plus the overall market outlook remains stable. Forecast production volumes for Vietnam remain comparable to year end 2024 forecast, and the Group is currently in the process of a drilling campaign in Vietnam, with two infill wells that completed before year end and were brought into production. For Egypt assets, there were some delays in the execution of the El Fayum development plan, but not significant enough to adversely impact the asset valuation.
As a result, after examining both internal and external indicators of impairment, the Group determined that no impairment or impairment reversal indicators were identified on any of the Group's oil and gas producing properties and no impairment tests were considered necessary as at 31 December 2025.
As at 31 December 2025, the carrying amount of the TGT oil and gas producing property, after additions of $10.8m, increase in decommissioning asset of $2.0m and DD&A of $32.9m, is $133.5m (2024: $153.6m). As at 31 December 2025, the carrying amount of the CNV oil and gas producing property, after additions of $4.8m, increase in decommissioning asset of $1.1m and DD&A of $8.5m, is $57.6m (2024: $60.2m).
As at 31 December 2025, the carrying amount of the El Fayum oil and gas producing property, after additions of $1.4m, transfer from intangibles of $2.9m and DD&A of $4.8m, is $58.0m (2024: $58.5m). As at 31 December 2025, the carrying amount of the NBS oil and gas producing property, after additions of $0.1m and DD&A of $0.2m, is $1.0m (Dec 2024: $1.1m).
Other assets and liabilities
Cash is set aside into abandonment funds for both TGT and CNV. These abandonment funds are controlled by PetroVietnam and, as the Group retains the legal rights to the funds pending commencement of abandonment operations, they are treated as other non-current assets in the Financial Statements. As at 31 December 2025, the Group's total contribution to the funds was $59.9m (2024: $56.0m).
Oil inventory was $6.1m at 31 December 2025 (2024: $9.3m), of which $6.0m related to Vietnam and $0.1m to Egypt. Trade and other receivables decreased to $19.4m (2024: $47.9m) of which $8.6m (2024: $14.5m) relates to Vietnam and $10.4m (2024: $32.7m) relates to Egypt. Egypt trade receivables include $7.3m from EGPC, after expected credit loss provision of $0.1m recognised under IFRS 9, where collection has been delayed by EGPC as a result of macroeconomic factors highlighted in previous preliminary and interim results (2024: trade receivables from Egypt $28.1m after expected credit loss position of $1.4m).
Cash and cash equivalents at the end of the year were $40.2m (2024: $16.5m) and the increase was mainly driven by net $29.0m inflow from working capital, following $20m recovery of trade receivables from EGPC before the end of the year. During 2024, there was $39.2m net repayment of borrowings following settlement of the RBL facility.
Trade and other payables, inclusive of VAT payable and payroll taxes, were marginally higher at $14.5m (2024: $14.3m), of which $4.1m (2024: $5.4m) predominantly relates to Egypt net JV payables in relation to operations and Stratton royalty obligation. $7.2m (2024: $5.1m) relates to Vietnam payables, mainly royalties and amounts owed to the JOCs in respect of TGT and CNV operations, and $3.2m (2024: $3.8m) Head Office payables. Tax payables decreased to $1.6m (2024: $3.2m) and relates to corporate income taxes on Vietnam oil and gas revenues.
Long-term provisions comprise the Group's decommissioning obligations for the Vietnam fields. The decommissioning provision increased from $51.1m at 2024 year end to $56.5m at 31 December 2025, as there was $2.3m unwind of the decommissioning provision, $1.0m impact of the new appraisal and infill wells on TGT and CNV respectively and $2.4m impact of a decrease in discount rate from 4.58% to 3.94%, partially offset by $0.3m revision to the TGT abandonment plan. The amounts set aside into the abandonment funds total $59.9m (2024: $56.0m). No decommissioning obligation exists under the El Fayum and NBS Concessions.
Own shares
The Pharos Employee Benefit Trust holds ordinary shares of the Company for the purposes of satisfying long-term incentive awards for senior management. At the end of 2025, the trust held 2,203,106 shares (2024: 3,784,406 shares), representing 0.53% (2024: 0.89%) of the issued share capital.
In addition, as at 31 December 2024, the Company held 9,122,268 treasury shares which represented 2.15% of the issued share capital. On 23 July 2025, pursuant to a resolution of the Board of Directors, the entire treasury holding of 9,122,268 ordinary shares of £0.05 each were cancelled in accordance with the provisions of section 729 of the Companies Act 2006. Following the cancellation, the Company holds no ordinary shares in treasury.
Share buyback and dividend framework
Following a period of relatively stable commodity prices and a strengthening of the Group's liquidity position, the Company committed to shareholder returns in the form of share buybacks and dividends.
On 6 December 2023, the Company announced the continuation of a further $3m share buyback programme in 2024, taking the total committed to share buybacks to $9 million since initiation of the programme in July 2022. The final stage of the programme completed in January 2025.
Pharos has a clear sustainable policy for regular dividend payments and this has been set at returning no less than 10% of Operating Cash Flow (OCF) each year in two tranches:
- An interim dividend of 33% of the previous year's total dividend, payable in January of the following year; and
- A final dividend payable in July of the following year.
In September 2024, the Board resolved to pay an interim dividend of 0.363 pence per share, $1.8m equivalent, in respect of the year ended 31 December 2024 and this was paid on 22 January 2025 to shareholders on the Company's register as at 20 December 2024.
A final dividend of 0.847 pence per share in respect of the year ended 31 December 2024, $4.7m equivalent, was approved by the shareholders at the Company's AGM in May 2025 and subsequently paid on 18 July 2025 to shareholders on the register at the close of business on 13 June 2025. This took the 2024 full year dividend to 1.21 pence per share, an increase of 10% on the prior year.
In accordance with dividend policy, the Board has resolved to pay an interim dividend of 0.3993 pence per share, $2.2m equivalent, in respect of the year ended 31 December 2025 and was paid on 21 January 2026 to shareholders on the Company's register as at 19 December 2025.
The Board have recommended a final dividend in respect of the year ended 31 December 2025 of 0.9317 pence per share subject to approval of the shareholders at the Company's 2026 AGM. Subject to this approval, the final dividend will be paid in full on 17 July 2026 in Pounds Sterling to ordinary shareholders on the register at the close of business on 12 June 2026, with an ex-dividend date of 11 June 2026. This would take the 2025 full year dividend to 1.331 pence per share, which is 10% higher than prior year.
Going concern
Pharos continuously monitors its business activities, financial position, cash flows and liquidity through detailed forecasts. Scenarios and sensitivities are also regularly presented to the Board, including changes in commodity prices and in production levels from the existing assets, plus other factors that could affect the Group's future performance and position.
A base case forecast has been considered for the going concern assessment that utilises oil prices of $62.4/bbl in 2026 and $66.0/bbl in 2027. The key assumptions and related sensitivities include a "Reasonable Worst Case" (RWC) scenario, where the Board has taken into account the risk of reduction in oil prices by 10% to $56.0/bbl in March 2026 for the next twelve months, concurrent with 5% reductions in Vietnam and Egypt production compared to our base case from March 2026. Additionally, CNV appraisal well 5X-L1 is assumed to be a dry hole and Egypt is based on 1P production in the RWC scenario. Both the base case and RWC take into account the effect of hedging that has already been put in place at 31 December 2025 and subsequent hedges placed in Q1 2026, now covering c.19% of total group entitlement production for 2026. These are a combination of zero cost collars, premium collars and put options. We have therefore secured an average floor price and ceiling price of c. $59.0/bbl and c. $74.7/bbl, respectively, for the entire hedged volumes in 2026. Under the RWC scenario, we have identified appropriate mitigating actions, including drawdown on the NBE credit facility in Q2 2026, reduction in head office administrative expenses and a decision not to pay dividends to shareholders from 2027.
In addition, we have conducted a reverse stress test sensitivity analysis that indicates the magnitude of oil price decline required to breach our financial headroom, assuming all other variables remain unchanged. The likelihood of Brent price dropping to such levels is considered to be remote.
Our business in Vietnam continues to be robust, with a low breakeven oil price. On TGT, appraisal well TGT-18X completed in February 2026 and is undergoing perforation testing. On CNV, infill well CNV-8P commenced in December 2025 and will complete in March 2026. The Group remains debt-free.
In Egypt, approval was received in September 2025 from the EGPC Executive Board for the consolidation of our two Concession Agreements in Egypt, subject to customary approvals and Egyptian Parliamentary ratification, expected during 2026. Once ratified, the improved fiscal terms within the consolidated Concession Agreement will be effective from 5 October 2025, the date of full EGPC Board approval.
On the basis of the forecasts provided above, the Group is expected to have sufficient financial headroom for the period up to 31 March 2027. Based on this analysis, the Directors have a reasonable expectation that the Group has adequate resources to continue its operations in the foreseeable future. Therefore, the Financial Statements have been prepared using the going concern basis of accounting.
Financial outlook
We are in a strong position as we move into 2026 with a number of value catalysts.
· Continuation of six-well drilling programme currently underway in Vietnam, with the final four wells expected to finish by mid-2026
· Look forward to Egyptian Parliamentary ratification of the consolidation of our concessions in Egypt with improved fiscal terms and increased longevity
· A strong and stable balance sheet, debt free and with improved liquidity position.
· Continued improvement in the economic situation in Egypt, following the bullet payment from EGPC of $20m on 31 December 2025, unlocking our remaining outstanding receivables.
Stable returns to shareholders are expected in 2026, with the dividend policy of no less than 10% of OCF.
Sue Rivett
Chief Financial Officer
|
Condensed consolidated income statement |
|
|
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||||||||||||
|
for the year ended 31 December 2025 |
|
|
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|||||||||||
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|
|
|
|
|
|
2025 |
2024 |
|
||||||
|
|
|
|
|
|
|
Notes |
$ million |
$ million |
|
||||||
|
|
|
|
|
|
|
|
|
||||||||
|
Revenue |
|
|
|
|
|
3 |
114.6 |
136.0 |
|
||||||
|
Cost of sales |
|
|
|
|
4 |
(97.7) |
(89.8) |
|
|||||||
|
Impairment reversal - Financial asset |
|
|
|
|
4 |
1.3 |
2.5 |
|
|||||||
|
Gross profit |
|
|
|
|
|
18.2 |
48.7 |
|
|||||||
|
|
|
|
|
|
|
|
|
|
|
||||||
|
Administrative expenses |
|
|
|
|
(8.8) |
(9.1) |
|
||||||||
|
Other operating costs |
|
|
|
5 |
(0.3) |
(0.8) |
|
||||||||
|
Pre-licence costs |
|
|
|
|
(0.4) |
(0.8) |
|
||||||||
|
Impairment charge - Intangibles assets |
3, 9 |
- |
(2.0) |
|
|||||||||||
|
Impairment reversal - Property, plant and equipment |
|
3, 10 |
- |
28.3 |
|
||||||||||
|
|
|
|
|
|
|
|
|
||||||||
|
Operating profit |
|
|
|
|
8.7 |
64.3 |
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
||||||
|
Other/restructuring expense |
|
|
|
|
5 |
- |
(0.4) |
|
|||||||
|
(Loss)/gain on fair value movement of financial asset |
|
(0.5) |
0.3 |
|
|||||||||||
|
Investment revenue |
|
|
|
|
|
0.5 |
0.4 |
|
|||||||
|
Finance costs |
|
|
|
|
6 |
(2.2) |
(3.9) |
|
|||||||
|
Profit before tax |
|
|
|
|
3 |
6.5 |
60.7 |
|
|||||||
|
Income tax charge |
|
|
|
|
7 |
(13.1) |
(37.1) |
|
|||||||
|
(Loss)/profit for the year |
|
(6.6) |
23.6 |
|
|
|
|||||||||
|
|
|
|
|
|
|
|
|
|
|
||||||
|
(Loss)/profit per share (cents) |
8 |
|
|
|
|||||||||||
|
Basic |
|
|
|
|
|
(1.6) |
5.7 |
|
|||||||
|
Diluted |
|
|
|
|
|
(1.6) |
5.4 |
|
|||||||
|
|
|
|
|
|
|
|
|
|
|
||||||
|
|
|
||||||||||||||
|
Condensed consolidated statement of comprehensive income |
|
||||||||||||||
|
for the year ended 31 December 2025 |
|
|
|
|
|
||||||||||
|
|
|
|
|
|
|
|
2025 |
2024 |
|
||||||
|
|
|
|
|
|
|
|
$ million |
$ million |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
||||||
|
(Loss)/profit for the year |
|
|
|
|
(6.6) |
23.6 |
|
||||||||
|
Other comprehensive (loss)/income that may be reclassified to profit or loss in subsequent periods (net of tax): |
|
|
|
||||||||||||
|
Fair value loss arising on hedging instruments during the year 11 |
(0.3) |
(0.1) |
|
||||||||||||
|
Less: Loss arising on hedging Instruments reclassified to profit or loss |
- |
0.1 |
|
||||||||||||
|
Total comprehensive (loss)/ income for the year (net of tax) |
|
(6.9) |
23.6 |
|
|||||||||||
The above condensed consolidated income statement and condensed consolidated statement of comprehensive income should be read in conjunction with the accompanying notes.
|
CONDENSED CONSOLIDATED Balance sheet |
|
|||||||||
|
|
|
|
|
|
|
|
Group |
|
|
Company |
|
|
|
|
|
|
|
2025
|
2024 Restated1 |
|
2025
|
2024
|
|
|
|
|
|
|
Notes |
$ million |
$ million |
|
$ million |
$ million |
|
Non-current assets |
|
|
|
|
|
|
|
|
|
|
|
Intangible assets |
|
|
|
9 |
26.5 |
21.8 |
|
- |
- |
|
|
Property, plant and equipment |
|
|
10 |
250.4 |
273.5 |
|
0.1 |
- |
||
|
Right of use asset |
|
|
10 |
- |
0.2 |
|
- |
- |
||
|
Investments |
|
|
|
|
- |
- |
|
290.0 |
287.0 |
|
|
Loan to subsidiaries |
|
- |
- |
|
13.2 |
18.4 |
||||
|
Other assets |
|
|
|
|
59.9 |
57.8 |
|
- |
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
336.8 |
353.3 |
|
303.3 |
305.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets |
|
|
|
|
|
|
|
|
|
|
|
Inventories |
|
|
|
|
|
6.1 |
9.3 |
|
- |
- |
|
Trade and other receivables |
|
|
|
19.4 |
47.9 |
|
0.4 |
0.5 |
||
|
Tax receivables |
|
|
|
|
0.5 |
0.3 |
|
0.2 |
0.2 |
|
|
Cash and cash equivalents |
|
|
|
40.2 |
16.5 |
|
10.9 |
0.8 |
||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
66.2 |
74.0 |
|
11.5 |
1.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
|
|
|
403.0 |
427.3 |
|
314.8 |
306.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
|
|
|
|
|
|
|
|
|
|
Trade and other payables |
|
|
|
(14.5) |
(14.3) |
|
(2.8) |
(3.8) |
||
|
Lease Liabilities |
|
|
|
- |
(0.2) |
|
- |
- |
||
|
Tax payable |
|
|
|
(1.6) |
(3.2) |
|
- |
- |
||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(16.1) |
(17.7) |
|
(2.8) |
(3.8) |
|
|
|
|
|
|
|
|
|
|
||
|
Non-current liabilities |
|
|
|
|
|
|
|
|
|
|
|
Other payables |
|
|
|
|
- |
(0.2) |
|
- |
- |
|
|
Deferred tax liabilities |
|
|
|
|
(46.5) |
(62.6) |
|
- |
- |
|
|
Long term provisions |
|
|
|
|
(56.5) |
(51.1) |
|
- |
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(103.0) |
(113.9) |
|
- |
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities |
|
|
|
|
(119.1) |
(131.6) |
|
(2.8) |
(3.8) |
|
|
Net assets |
|
|
|
|
283.9 |
295.7 |
|
312.0 |
303.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity |
|
|
|
|
|
|
|
|
|
|
|
Share capital |
|
|
|
|
32.4 |
33.1 |
|
32.4 |
33.1 |
|
|
Share premium |
|
|
|
|
58.0 |
58.0 |
|
58.0 |
58.0 |
|
|
Other reserves |
|
|
|
|
299.4 |
258.1 |
|
243.3 |
202.0 |
|
|
Retained (deficit) / earnings |
|
|
|
|
(105.9) |
(53.5) |
|
(21.7) |
10.0 |
|
|
Total equity |
|
|
|
|
283.9 |
295.7 |
|
312.0 |
303.1 |
|
1 See Note 2(d)
The above condensed consolidated and company balance sheets should be read in conjunction with the accompanying notes.
CONDENSED consolidated STATEMENT OF CHANGES IN EQUITY
|
|
Group |
||||
|
Notes |
Called up |
Share premium |
Other reserves |
Retained |
Total $ million |
|
As at 1 January 2024 (Restated1) |
33.7 |
58.0 |
255.4 |
(67.0) |
280.1 |
|
Profit for the year |
- |
- |
- |
23.6 |
23.6 |
|
Share buy back |
(0.6) |
- |
0.6 |
(2.9) |
(2.9) |
|
Shares purchased |
- |
- |
(0.9) |
- |
(0.9) |
|
Share-based payments |
- |
- |
1.7 |
- |
1.7 |
|
Distributions to shareholders |
- |
- |
- |
(5.9) |
(5.9) |
|
Transfer relating to share-based payments |
- |
- |
1.3 |
(1.3) |
- |
|
As at 1 January 2025 (Restated1) |
33.1 |
58.0 |
258.1 |
(53.5) |
295.7 |
|
Loss for the year |
- |
- |
- |
(6.6) |
(6.6) |
|
Other comprehensive income |
- |
- |
(0.3) |
- |
(0.3) |
|
Share buy back |
(0.1) |
- |
0.1 |
(0.3) |
(0.3) |
|
Share-based payments |
- |
- |
1.8 |
- |
1.8 |
|
Treasury shares cancelled |
(0.6) |
- |
39.7 |
(39.1) |
- |
|
Distributions to shareholders 12 |
- |
- |
- |
(6.5) |
(6.5) |
|
Transfer relating to share-based payments |
- |
- |
- |
0.1 |
0.1 |
|
As at 31 December 2025 |
32.4 |
58.0 |
299.4 |
(105.9) |
283.9 |
|
1 See Note 2(d) |
|||||
|
|
|||||
|
|
Company |
||||
|
|
Called up |
Share premium |
Other reserves1 |
Retained |
Total $ million |
|
As at 1 January 2024 |
33.7 |
58.0 |
200.6 |
(14.9) |
277.4 |
|
Profit for the year |
- |
- |
- |
35.0 |
35.0 |
|
Share buy back |
(0.6) |
- |
0.6 |
(2.9) |
(2.9) |
|
Share-based payments |
- |
- |
1.7 |
- |
1.7 |
|
Distributions to shareholders |
- |
- |
- |
(5.9) |
(5.9) |
|
Transfer relating to share-based payments |
- |
- |
(0.9) |
(1.3) |
(2.2) |
|
As at 1 January 2025 |
33.1 |
58.0 |
202.0 |
10.0 |
303.1 |
|
Profit for the year |
- |
- |
- |
14.1 |
14.1 |
|
Share buy back |
(0.1) |
- |
0.1 |
(0.3) |
(0.3) |
|
Share-based payments |
- |
- |
1.8 |
- |
1.8 |
|
Treasury shares cancelled |
(0.6) |
- |
39.7 |
(39.1) |
- |
|
Distributions to shareholders 12 |
- |
- |
- |
(6.5) |
(6.5) |
|
Transfer relating to share-based payments |
- |
- |
(0.3) |
0.1 |
(0.2) |
|
As at 31 December 2025 |
32.4 |
58.0 |
243.3 |
(21.7) |
312.0 |
1 Includes a Merger reserve of $137.1m (2024: $137.1m) which is distributable in accordance with the Companies Act 2006. Total distributable reserves at 31 December 2025 are $115.4m.
The above condensed statements of changes in equity should be read in conjunction with the accompanying notes.
CONDENSED CONSOLIDATED cash flow statements
for the year to 31 December 2025
|
|
|
|
Group |
|
|
Company |
|
|
Notes |
2025 $ million |
2024 $ million |
|
2025 $ million |
2024 $ million |
|
Net cash from (used in) operating activities |
13 |
55.6 |
54.0 |
|
(7.6) |
(11.2) |
|
Investing activities |
|
|
|
|
|
|
|
Purchase of intangible assets |
|
(7.6) |
(5.4) |
|
- |
- |
|
Purchase of property, plant and equipment |
|
(16.1) |
(18.4) |
|
(0.1) |
- |
|
Payment to abandonment fund |
|
(3.9) |
(2.3) |
|
- |
- |
|
Consideration in relation to farm out of Egyptian assets1 |
|
- |
5.0 |
|
- |
- |
|
Contingent consideration received in relation to farm out of Egyptian assets |
|
2.9 |
3.6 |
|
- |
- |
|
Assignment fee in relation to farm out of Egyptian assets |
|
- |
(0.4) |
|
- |
- |
|
Loans from subsidiaries |
|
- |
- |
|
6.0 |
4.7 |
|
Loans to subsidiaries |
|
- |
- |
|
(1.3) |
- |
|
Dividends received from subsidiary undertakings |
|
- |
- |
|
23.0 |
14.3 |
|
Investment in subsidiary undertakings |
|
- |
- |
|
(10.9) |
- |
|
Return of capital from subsidiary undertakings |
|
- |
- |
|
7.9 |
- |
|
Net cash (used in) from investing activities |
|
(24.7) |
(17.9) |
|
24.6 |
19.0 |
|
|
|
|
|
|
|
|
|
Financing activities |
|
|
|
|
|
|
|
Share purchase |
|
- |
(0.9) |
|
- |
- |
|
Repayment of borrowings |
|
- |
(41.4) |
|
- |
- |
|
Proceeds from borrowings |
|
- |
2.2 |
|
- |
- |
|
Interest paid on borrowings |
|
- |
(2.4) |
|
- |
- |
|
Lease payments |
|
(0.2) |
(0.3) |
|
- |
- |
|
Share buy back |
|
(0.3) |
(2.9) |
|
(0.3) |
(2.9) |
|
Dividends paid to shareholders |
|
(6.5) |
(5.9) |
|
(6.5) |
(5.9) |
|
Net cash used in financing activities |
|
(7.0) |
(51.6) |
|
(6.8) |
(8.8) |
|
|
|
|
|
|
|
|
|
Net increase/(decrease) in cash and cash equivalents |
|
23.9 |
(15.5) |
|
10.2 |
(1.0) |
|
Cash and cash equivalents at beginning of year |
|
16.5 |
32.6 |
|
0.8 |
1.7 |
|
Effect of foreign exchange rate changes |
|
(0.2) |
(0.6) |
|
(0.1) |
0.1 |
|
Cash and cash equivalents at end of year |
|
40.2 |
16.5 |
|
10.9 |
0.8 |
1 During 2024 IPR, acting as operator and agent, was authorised to settle its operating liabilities of $3.7m and investing liabilities of $1.3m against the consideration due from the associated carry debtor amounting to $5.0m. The Company has disclosed the underlying cash flows as operating, investing or financing according to their nature on the basis that, as a principal, the entity has the right to the cash inflows and/or the obligation to settle the liability and to ensure clarity of disclosure of the operating cash costs of the business. The total carry of $35.9m was utilised in full by April 2024, hence there are no cash inflows in 2025.
The above condensed consolidated and company cash flow statements should be read in conjunction with the accompanying notes.
Notes to the condensed consolidated financial statements
1. General information
The financial information set out above does not constitute the Company's statutory accounts for the years ended 31 December 2025 or 2024, but is derived from those accounts. A copy of the statutory accounts for 2024 has been delivered to the Registrar of Companies and those for 2025 will be delivered following the Company's annual general meeting. The auditors have reported on those accounts; their reports were unqualified, did not draw attention to any matters by way of emphasis without qualifying their report and did not contain statements under section 498(2) or (3) of the Companies Act 2006. Whilst the financial information included in this preliminary announcement has been computed in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standard Board (IASB), this announcement does not itself contain sufficient information to comply with IFRS. The financial statements are presented in US dollars which is the functional currency of each of the Company's subsidiary undertakings.
2. Material accounting policies
(a) Basis of preparation
The financial information has been prepared in accordance with UK-adopted international accounting standards in conformity with the requirements of the Companies Act 2006.
The financial information has also been prepared on a going concern basis of accounting.
(b) New and amended standards adopted by Pharos
The Group applied for the first time certain standards and amendments, which are effective for annual periods beginning on or after 1 January 2025 (unless otherwise stated). The Group has not early adopted any other standard, interpretation or amendment that has been issued but is not yet effective. Amendments that apply for the first time in 2025, but do not have an impact on the Group's financial statements are:
Lack of exchangeability - Amendments to IAS 21
The amendment to IAS 21 specifies how an entity should assess whether a currency is exchangeable and how it should determine a spot exchange rate when exchangeability is lacking.
A currency is considered to be exchangeable into another currency when an entity is able to obtain the other currency within a time frame that allows for a normal administrative delay and through a market or exchange mechanism in which an exchange transaction would create enforceable rights and obligations.
The Group has assessed the amendments to IAS 21 on Lack of Exchangeability and concluded that they are not applicable, as the currencies in which the Group operates (USD, EGP, VND and GBP) are considered exchangeable.
(c) New standards and interpretations not yet adopted
Certain new accounting standards and interpretations have been published that are not mandatory for 31 December 2025 year end and have not been early adopted by the Group.
IFRS 18 Presentation and Disclosure in Financial Statements
In April 2024, the IASB issued IFRS 18, replacing IAS 1 Presentation of Financial Statements. IFRS 18 introduces new presentation requirements for the statement of profit or loss, including specified totals and subtotals, and requires entities to classify income and expenses into five categories: operating, investing, financing, income taxes, and discontinued operations. It also adds disclosure requirements for management-defined performance measures and sets new rules for aggregation and disaggregation in financial statements and notes.
Additionally, amendments to IAS 7 Statement of Cash Flows change the indirect method's starting point to operating profit or loss and remove options for classifying dividends and interest. Consequential amendments were also made to other standards.
The Group is currently working to identify all impacts the amendments will have on the primary financial statements and notes to the financial statements.
IFRS 18 and 'Classification and Measurement of Financial Instruments - Amendments to IFRS 9 and IFRS 7' are being assessed for the impact and other standards are not expected to have a material impact on the primary financial statements and notes to the financial statements.
(d) Restatement of deferred tax liability
Comparative information in respect of the deferred tax liability has been restated in relation to an adjustment made to correct excess cost recovery considered in the deferred tax calculations in respect of years prior to 2024. The deferred tax liability as at 31 December 2024 was overstated by $4.9m. As a result of the correction, the deferred tax liability decreased from $67.5m to $62.6m as at 31 December 2024. As the error related to years prior to 2024, the opening retained deficit has been restated, resulting in a decrease from $(71.9)m to $(67.0)m as at 1 January 2024 and from $(58.4)m to $(53.5)m as at 31 December 2024.
3. Segment information
The Group has one principal business activity being oil and gas exploration and production. The Group's operations are located in South East Asia and Egypt (the Group's operating segments). There are no inter-segment sales. South East Asia and Egypt form the basis on which the Group reports its segment information.
|
|
|
|
||||
|
|
|
|
|
2025 |
||
|
|
SE Asia |
Egypt $ million |
Unallocated1 |
Group |
||
|
Oil and gas sales |
99.8 |
14.8 |
- |
114.6 |
||
|
Realised loss on commodity hedges |
- |
- |
- |
- |
||
|
Total revenue |
99.8 |
14.8 |
- |
114.6 |
||
|
Cost of sales |
(81.0) |
(16.7) |
- |
(97.7) |
||
|
Impairment reversal - Financial asset |
- |
1.3 |
- |
1.3 |
||
|
Administrative expenses |
- |
- |
(8.8) |
(8.8) |
||
|
Depreciation, depletion and amortisation - Oil and gas |
(41.4) |
(5.0) |
- |
(46.4) |
||
|
Depreciation, depletion and amortisation - Other |
- |
(0.2) |
- |
(0.2) |
||
|
Other operating costs |
- |
- |
(0.3) |
(0.3) |
||
|
Pre-licence costs |
- |
- |
(0.4) |
(0.4) |
||
|
Loss on fair value movement of financial asset2 |
- |
(0.5) |
- |
(0.5) |
||
|
Profit/(loss) before tax |
16.5 |
(1.3) |
(8.7) |
6.5 |
||
|
Tax charge on operations |
(12.7) |
(0.4) |
- |
(13.1) |
||
|
|
|
|
|
|
||
|
|
|
|||||
|
|
|
|
|
2024 |
||
|
|
SE Asia |
Egypt $ million |
Unallocated1 |
Group |
||
|
Oil and gas sales |
115.4 |
20.7 |
- |
136.1 |
||
|
Realised loss on commodity hedges |
- |
- |
(0.1) |
(0.1) |
||
|
Total revenue |
115.4 |
20.7 |
(0.1) |
136.0 |
||
|
Cost of sales |
(75.6) |
(14.2) |
- |
(89.8) |
||
|
Impairment charge - Financial asset |
- |
2.5 |
- |
2.5 |
||
|
Administrative expenses |
- |
- |
(9.1) |
(9.1) |
||
|
Depreciation, depletion and amortisation - Oil and gas |
(42.1) |
(5.0) |
- |
(47.1) |
||
|
Depreciation, depletion and amortisation - Other |
- |
(0.2) |
- |
(0.2) |
||
|
Other operating costs |
- |
- |
(0.8) |
(0.8) |
||
|
Pre-licence costs |
- |
- |
(0.8) |
(0.8) |
||
|
Impairment charge - Intangible assets |
- |
(2.0) |
- |
(2.0) |
||
|
Impairment reversal - PP&E |
23.4 |
4.9 |
- |
28.3 |
||
|
Gain on fair value movement of financial asset2 |
- |
0.3 |
- |
0.3 |
||
|
Profit/(loss) before tax1 |
60.9 |
11.3 |
(11.5) |
60.7 |
||
|
Tax charge on operations |
(26.8) |
(1.9) |
- |
(28.7) |
||
|
Tax charge on impairment reversal |
(8.4) |
- |
- |
(8.4) |
||
1 Unallocated amounts included in profit/(loss) before tax comprise corporate costs not attributable to an operating segment, investment revenue, other gains and losses and finance costs.
2 Relates to the revision of contingent consideration due from the farm-out of the Egyptian concessions with IPR, partially offset by the movement in contingent liability (assignment fee) owed to EGPC.
The accounting policies of the reportable segments are the same as the Group's accounting policies.
Included in revenues arising from South East Asia and Egypt are revenues of $99.8m and $14.8m which arose from the Group's two customers, who contributed more than 10% to the Group's oil and gas revenue (2024: $115.4m and $20.7m in South East Asia and Egypt from the Group's two customers).
Geographical information
The Group's oil and gas revenue and non-current assets (excluding other assets) by geographical location are separately detailed below where they exceed 10% of total revenue or non-current assets, respectively:
Revenue
All of the Group's oil and gas revenue is derived from foreign countries. The Group's oil and gas revenue by geographical location is determined by reference to the final destination of oil or gas sold.
|
|
2025 |
2024 |
||
|
Vietnam |
99.8 |
115.4 |
||
|
Egypt |
14.8 |
20.7 |
||
|
|
114.6 |
136.1 |
||
|
Non-current assets1
|
2025 |
2024 |
||
|
Vietnam |
217.6 |
233.5 |
||
|
Egypt |
59.1 |
62.0 |
||
|
United Kingdom |
0.2 |
- |
||
|
|
276.9 |
295.5 |
||
1Excludes other assets.
4. Cost of sales
|
|
|
|
|
|
|
|
|
|
2025 |
|
|
2024 |
|
|
|
|
|
|
|
$ million |
|
|
$ million |
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortisation (see Note 10) |
46.4 |
|
|
47.1 |
|||||||||
|
Production operating costs |
|
|
|
|
|
40.8 |
|
|
39.5 |
||||
|
Production based taxes |
|
|
|
|
|
7.3 |
|
|
9.2 |
||||
|
Change in inventories |
|
|
|
|
|
3.2 |
|
|
(6.0) |
||||
|
|
|
|
|
|
97.7 |
|
|
89.8 |
|||||
|
Impairment reversal - financial asset |
|
|
|
|
(1.3) |
|
|
(2.5) |
|||||
|
|
|
|
|
|
96.4 |
|
|
87.3 |
|||||
5. Other operating costs and Other/restructuring expense
|
|
|
|
|
|
|
|
|
|
2025 |
|
|
2024 |
|
|
Other operating costs |
|
|
|
|
$ million |
|
|
$ million |
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Share based payments |
|
|
|
|
|
- |
|
|
0.6 |
||||
|
Other |
|
|
|
|
|
0.3 |
|
|
0.2 |
||||
|
|
|
|
|
|
0.3 |
|
|
0.8 |
|||||
In 2024, share based payments of $0.6m relate to the posthumous vesting of share scheme awards to the former CEO of the Company, settled in cash and paid to his estate with the agreement of the executor. This cash settlement was provided for in the relevant share scheme rules and formally approved by the Remuneration Committee.
|
|
|
|
|
|
|
|
|
|
2025 |
|
|
2024 |
|
|
Other/restructuring expense |
|
|
|
|
$ million |
|
|
$ million |
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Redundancy costs |
|
|
|
|
|
- |
|
|
0.4 |
||||
|
|
|
|
|
|
- |
|
|
0.4 |
|||||
In 2024, Other/restructuring expenses included $0.4m of redundancy costs relating to the Egypt office in Cairo.
6. Finance costs
|
|
2025 |
2024 |
|
Unwinding of discount on provisions |
2.3 |
2.2 |
|
Interest expense and similar fees |
- |
1.1 |
|
Net foreign exchange (gains)/losses |
(0.1) |
0.6 |
|
|
2.2 |
3.9 |
In 2025, $2.3m relates to the unwinding of discount on the provisions for decommissioning (2024: $2.2m). The provisions are based on the net present value of the Group's share of the expenditure which will be incurred at the end of the producing life of TGT and CNV (currently estimated to be 7-8 years) in the removal and decommissioning of the facilities currently in place.
Interest expense and similar fees for 2024 relates to interest paid on the Group's reserve based lending facility and an uncommitted revolving credit facility with the National Bank of Egypt (UK) Limited (NBE UK). The RBL loan facility was voluntarily repaid early and in full on 17 September 2024 and the NBE UK facility was repaid in full in August 2024.
7. Income tax charge
|
|
2025 |
2024 |
|
Current tax |
|
|
|
Current income tax charge |
29.4 |
36.0 |
|
Adjustments to tax charge in respect of prior years |
(0.2) |
1.8 |
|
|
29.2 |
37.8 |
|
Deferred tax |
|
|
|
Deferred tax credit on operations |
(16.1) |
(9.1) |
|
Deferred tax charge on net impairment reversal |
- |
8.4 |
|
|
(16.1) |
(0.7) |
|
|
|
|
|
Income tax charge reported in the consolidated income statement |
13.1 |
37.1 |
|
|
|
|
The Group's corporation tax is calculated at 50% (2024: 50%) of the estimated assessable profit for the year in Vietnam. In Egypt, under the terms of the concession, any local taxes arising are settled by EGPC on behalf of the Group. During 2025 and 2024, both current and deferred taxation have arisen in overseas jurisdictions only.
The charge for the year can be reconciled to the profit/(loss) per the income statement as follows:
|
|
2025 |
2024 |
|
Profit before tax |
6.5 |
60.7 |
|
Tax at 50% (2024: 50%) |
3.3 |
30.4 |
|
|
|
|
|
Effects of: |
|
|
|
Non-taxable income |
- |
(5.8) |
|
Non-deductible expenses |
6.5 |
8.1 |
|
Egypt taxation at different rate to Vietnam effective tax rate |
(0.1) |
(2.0) |
|
Tax losses not recognised |
3.6 |
4.9 |
|
Utilisation of tax losses |
- |
(0.3) |
|
Adjustments to tax charge in respect of prior periods |
(0.2) |
1.8 |
|
Tax charge for the year |
13.1 |
37.1 |
The prevailing tax rate in Vietnam, where the Group produces oil and gas, is 50%. The tax charge in future periods may also be affected by the factors in the reconciliation above.
In 2024, non-taxable income relates to the tax impact of Vietnam impairment reversals of $(3.3)m in relation to the non-cost recovery pool and Egypt impairment reversal of $(2.5)m. Non-deductible expenses primarily relate to Vietnam DD&A charges for costs previously capitalised, which are non-deductible for Vietnamese tax purposes of $4.5m (2024: $6.2m). 2025 also includes $1.2m of non-deductible expenses for Egypt operations. A further $0.8m (2024: $0.9m) relates to non-deductible corporate costs including share scheme incentives. In 2024, non-deductible expenses also included the tax impact of Egypt intangible impairment charges of $1.0m.
The Egypt concessions are subject to corporate income tax at the standard rate of 40.55%, however responsibility for payment of corporate income taxes falls upon EGPC on behalf of Pharos El Fayum (PEF). The Group records a tax charge, with a corresponding increase in revenue, for the tax paid by EGPC on its behalf. As PEF became profitable in 2024, reversing the historic tax loss position since first production, this led to a $0.4m (2024: $1.9m) tax charge being recorded.
The effect from tax losses not recognised in 2025 and 2024 relates to costs, primarily of the Company, deductible for tax in the UK but not expected to be utilised in the foreseeable future.
8. Earnings per share
The calculation of the basic and diluted earnings per share is based on the following data:
|
|
Group |
|
|
2025 |
2024 |
|
|
(Loss)/gain for the purposes of basic earnings per share |
(6.6) |
23.6 |
|
Effect of dilutive potential ordinary shares - Cash settled share awards and options |
- |
(0.9) |
|
(Loss)/gain for the purposes of diluted earnings per share |
(6.6) |
22.7 |
|
|
Number of shares (million) |
|
|
2025 |
2024 |
|
|
Weighted average number of ordinary shares |
413.1 |
417.0 |
|
Effect of dilutive potential ordinary shares - Share awards and options |
- |
2.7 |
|
Weighted average number of ordinary shares for the purpose of diluted profit/(loss) per share |
413.1 |
419.7 |
In accordance with IAS 33 "Earnings per Share", the effects of 13.0m antidilutive potential shares have not been included when calculating dilutive earnings per share for the year ended 31 December 2025, as the Group was loss making.
9. Intangible assets
Intangible assets at 2025 year-end comprise the Group's exploration and evaluation projects which are pending determination. Included in the additions is Blocks 125 & 126 in Vietnam $6.9m (2024: $2.8m), including $3.7m of drill casings and long-lead items ahead of drilling the first commitment well, and Egypt $0.7m (2024: $2.8m).
During 2023, approval was received from the Vietnamese Government in June for the two-year extension to Phase One of the Exploration Period under Blocks 125 & 126 PSC to 8 November 2025. In June 2025, approval was received from the Vietnamese Government for a further two-year extension of the Exploration Period (from 9 November 2025 to 8 November 2027). In July 2023, the Company published an independent report prepared by ERCE on Blocks 125 & 126 in Vietnam which makes estimates of prospective oil resources with an aggregated gross unrisked Mean of 13,328 MMstb, covering those Prospects and Leads already identified. The report supports the Company's internal assessments and paves the way for further work to develop new Leads and mature Leads to Prospects. Detailed drilling engineering studies for the proposed well on Prospect A commenced in third quarter of 2024, with long lead items ordered to progress the opportunity on Blocks 125. The Company is continuing its discussions with potential farm-in partners and rig contractors to complete all necessary work to drill the first exploration well on this basin-opening play. Whilst ongoing costs for exploration are therefore forecasted and funds are available for future exploration, there is insufficient certainty of full recovery to justify the reversal of the previous impairment charges in 2020. The accumulated impairment charges against Vietnam exploration and evaluation expenditure at 31 December 2025 therefore remains at $17.9m (2024: $17.9m).
In Egypt, as part of the planned work programme for 2024, an exploration well was drilled on El Fayum in August 2024. Testing of the well was carried out at the beginning of February 2025. IPR, the operator of the El Fayum Concession, applied to EGPC for commercial discovery declaration and early production permission in February 2025. The development lease was approved and first production commenced at the end of June 2025. As a result, exploration costs of $2.9m were reclassified to property, plant and equipment in 1H 2025 and the net book value of Egypt exploration and evaluation expenditure at 31 December 2025 stood at $nil (2024: $2.2m).
10. Property, plant and equipment and right of use assets
|
2025 |
Oil and gas |
Other |
Total |
|
|
Property, plant and equipment |
250.1 |
0.3 |
250.4 |
|
Right of use asset |
- |
- |
- |
|
As at 31 December 2025 |
250.1 |
0.3 |
250.4 |
|
2024 |
Oil and gas |
Other |
Total |
|
|
Property, plant and equipment |
273.2 |
0.3 |
273.5 |
|
Right of use asset |
0.2 |
- |
0.2 |
|
As at 31 December 2024 |
273.4 |
0.3 |
273.7 |
We have evaluated each of our oil and gas producing properties for impairment or impairment reversal triggers. For each producing property where triggers are identified, the recoverable amount held would be determined using the value in use method and is calculated using a discounted cash flow valuation of the 2P production profile.
The average Brent price forecast as at Dec 2025 fell by 9% for 2026 to 2030 and 7% in the longer-term compared to the forecast at the end of 2024 and does not indicate a significant change in the underlying value of oil and gas assets. Furthermore, there were no significant changes to macroeconomic factors such as risk-free rate, equity market risk premium and country risk premiums, plus the overall market outlook remains stable. Forecast production volumes for Vietnam remain comparable to year end 2024 forecast, and the Group is currently in the process of a drilling campaign in Vietnam, with two infill wells that completed before year end and were brought into production. For Egypt assets, there were some delays in the execution of the El Fayum development plan, but not significant enough to adversely impact the asset valuation. As a result, after examining both internal and external indicators of impairment, the Group determined that no impairments or impairment reversal indicators were identified on any of the Group's oil and gas producing properties and no impairment tests were performed as at 31 December 2025.
|
Summary of Impairments - Oil and Gas Properties |
|
|
|
|
2025 |
|
2025 |
TGT |
CNV $ million |
El Fayum |
NBS |
Total |
|
Pre-tax impairment reversal |
- |
- |
- |
- |
- |
|
Deferred tax charge |
- |
- |
- |
- |
|
|
Post-tax impairment reversal |
- |
- |
- |
- |
- |
|
|
|
|
|
|
|
|
Reconciliation of carrying amount: |
|
|
|
|
|
|
As at 1 January 2025 |
153.6 |
60.2 |
58.5 |
1.1 |
273.4 |
|
Additions |
10.8 |
4.8 |
1.4 |
0.1 |
17.1 |
|
Transfer from intangible assets |
- |
- |
2.9 |
- |
2.9 |
|
Revision to decommissioning 1 |
2.0 |
1.1 |
- |
- |
3.1 |
|
DD&A |
(32.9) |
(8.5) |
(4.8) |
(0.2) |
(46.4) |
|
As at 31 December 2025 |
133.5 |
57.6 |
58.0 |
1.0 |
250.1 |
|
|
|
|
|
|
2024 |
|
2024 |
TGT |
CNV $ million |
El Fayum |
NBS |
Total |
|
Pre-tax impairment reversal |
19.8 |
3.6 |
4.9 |
- |
28.3 |
|
Deferred tax charge |
(7.1) |
(1.3) |
- |
- |
(8.4) |
|
Post-tax impairment reversal |
12.7 |
2.3 |
4.9 |
- |
19.9 |
|
|
|
|
|
|
|
|
Reconciliation of carrying amount: |
|
|
|
|
|
|
As at 1 January 2024 |
158.6 |
65.0 |
54.7 |
1.0 |
279.3 |
|
Additions |
12.8 |
1.0 |
3.5 |
0.5 |
17.8 |
|
Revision to decommissioning 1 |
(4.9) |
- |
- |
- |
(4.9) |
|
DD&A |
(32.7) |
(9.4) |
(4.6) |
(0.4) |
(47.1) |
|
Impairment reversal |
19.8 |
3.6 |
4.9 |
- |
28.3 |
|
As at 31 December 2024 |
153.6 |
60.2 |
58.5 |
1.1 |
273.4 |
1 Revision to decommissioning for TGT is due to a change in discount rate and field abandonment plan, including one appraisal well that commenced drilling in December 2025. CNV reflects a change in discount rate and field abandonment plan, including one new infill well that commenced drilling in December 2025 (2024: change in discount rate and field abandonment plan, including two new infill wells completed in October 2024 for TGT; change in discount rate, offset by a revision to the field abandonment plan for CNV)
2024 impairment considerations
Vietnam
The key assumptions to which the recoverable amount is most sensitive are oil price, discount rate and 2P reserves. In 2024, for both TGT and CNV, there was an upwards technical revision of 2P reserves following the granting of five-year extensions to the Petroleum contracts and a decrease in discount rate, which led to impairment reversals for both fields. As at 31 December 2024, the recoverable value of the assets was estimated based on a post-tax nominal discount rate of 10.7% and a Brent oil price of $74.2/bbl in 2025, $72.9/bbl in 2026, $74.0/bbl in 2027, $75.8/bbl in 2028 plus inflation of 2.0% thereafter
Testing of sensitivity cases indicated that a $5/bbl reduction in long-term oil price used when determining the value in use method would result in post-tax impairment charges (compared to new NBV, post-impairment reversal) of $13.7m on TGT and $3.1m on CNV. A 1% increase in discount rate would result in post-tax impairments of $2.5m on TGT and $0.9m on CNV (compared to new NBV, post-impairment reversal).
Sensitivities were also run utilising the IEA (International Energy Agency) scenarios described as being consistent with achieving the COP26 agreement goal to reach net zero by 2050 (the "Net Zero price scenario"). The nominal Brent prices used in this scenario were as follows; $74.2/bbl in 2025, $72.9/bbl in 2026, $74.0/bbl in 2027, $65.8/bbl in 2028, $57.2/bbl in 2029, $48.2/bbl in 2030, $48.2/ bbl in 2031, $48.2/bbl in 2032 and $48.1/bbl in 2033. Using these prices and a 10.7% discount rate would result in additional post-tax impairment charges (compared to new NBV, post-impairment reversal) of $20.5m on TGT and $5.2m on CNV.
Egypt
The key assumptions to which the recoverable amount is most sensitive are oil price, discount rate, capital spend and 2P reserves. In 2024, there was a decrease in the discount factor which has led to an impairment reversal for El Fayum, partially offset by a downwards technical revision of El Fayum 2P reserves due to change in the development plan. As at 31 December 2024, the recoverable value of El Fayum was estimated based on a post-tax nominal discount rate of 14.9% and a Brent oil price of $74.2/bbl in 2025, $72.9/bbl in 2026, $74.0/bbl in 2027, $75.8/bbl in 2028 plus inflation of 2.0% thereafter. For NBS, no material impairment arose as a result of the above impairment considerations.
Testing of sensitivity cases indicated that a $5/bbl reduction in long term oil price used when determining the value in use method would result in an impairment charge (compared to new NBV, post-impairment reversal) of $6.6m for El Fayum. A 1% increase in discount rate would result in impairment charges of $2.2m on El Fayum (compared to new NBV, post-impairment reversal). We also ran a sensitivity using 14.9% discount rate and the Net Zero price scenario would result in an additional impairment of $30.2m on El Fayum (compared to new NBV, post-impairment reversal).
Other considerations
It is not considered possible to provide meaningful sensitivities in relation to 2P reserves for any of the Group's oil and gas producing properties, as the impact of any changes in 2P reserves on recoverable amount would depend on a variety of factors, including the timing of changes in production profile and the consequential effect on the expenditure required to both develop and extract the reserves.
Other fixed assets comprise office fixtures and fittings and computer equipment.
11. Hedge transactions
During 2025, Pharos entered into zero cost collar hedges to protect the Brent component of forecast oil sales and to provide downside protection to cash flows in the event of commodity prices falling.
At 31 December 2025, the commodity hedges run until March 2026 and are settled monthly. For full year 2025, 29% of the Group's total production was hedged, securing average floor and ceiling prices for the hedged volumes at $62.6/bbl and $87.1/bbl, respectively, leaving 71% of 2025 Group production unhedged as at 31 December 2025 (2024: 31% of the Group's total production was hedged, securing average floor and ceiling prices for the hedged volumes at $63.4/bbl and $89.2/bbl). Following the termination of the RBL agreement effective July 2025, the Group has decided to continue hedging to mitigate the risk of a sharp decline in Brent price. As a result, the company placed further hedges in January 2026 through which the company has hedged c.19% of total forecast group entitlement production for 2026. These are a combination of zero cost collars, premium collars and put options.
A summary of hedges outstanding as at 31 December 2025 is presented below, which is a put option.
|
|
|
|
1Q26 |
|
|
Production hedge per quarter - 000/bbls |
|
|
60 |
|
|
Min. Average value of hedge - $/bbl |
|
|
58.00 |
|
Pharos has designated the zero cost collars as cash flow hedges. This means that the effective portion of unrealised gains or losses on open positions will be reflected in other comprehensive income. Every month, the realised gain or loss will be reflected in the revenue line of the income statement. For the year end 31 December 2025, there were no realised gains or losses (2024: loss of $0.1m). The outstanding unrealised loss on open positions as at 31 December 2025 amounts to $0.2m (2024: unrealised gain of $0.1m).
The carrying amount of the zero cost collars is based on the fair value determined by a financial institution. As all material inputs are observable, they are categorised within Level 2 in the fair value hierarchy. It is presented in "Trade and other receivables" or "Trade and other payables" in the consolidated statement of financial position. The payable position as of December 2025 was $0.1m (2024: $0.1m receivable).
12. Distribution to Shareholders
|
|
|
|
|
|
|
|
Amounts recognised as distributions to equity holders in the year: |
2025 $ million |
2025 Pence per ordinary share |
2024 $ million |
2024 Pence per ordinary share |
|
|
Prior year interim dividend, paid in the year |
1.8 |
0.363 |
1.7 |
0.330 |
|
|
Prior year final dividend, paid in the year |
4.7 |
0.847 |
4.2 |
0.770 |
|
|
Total dividend, paid in year |
6.5 |
1.210 |
5.9 |
1.100 |
|
|
|
|
|
|
|
|
|
Interim dividend for the year ended 31 December 2025 |
2.2 |
0.3993 |
|
|
|
|
Proposed final dividend for the year ended 31 December 2025 |
5.2 |
0.9317 |
|
|
|
The proposed final dividend for the year ended 31 December 2025 of 0.9317 pence per share takes the 2025 full-year dividend to 1.331 pence per share, in excess of the minimum 10% of Operating Cash Flow (OCF) per the Company's dividend policy and 10% higher than prior year.
The interim dividend for the year ended 31 December 2024 of 0.363 pence per share ($1.8m) was paid on 22 January 2025. The final dividend for the year ended 31 December 2024 of 0.847 pence per share ($4.7m) was approved by the shareholders at the Company's AGM in May 2025 and subsequently paid on 18 July 2025.
The interim dividend for the year ended 31 December 2025 of 0.3993 pence per share ($2.2m) was paid on 21 January 2026 to shareholders on the register as at 19 December 2025. The proposed final dividend of 0.9317 pence per share ($5.2m) in respect of the year ended 31 December 2025 is payable on 17 July 2026 to all shareholders on the register at the close of business on 12 June 2026, subject to approval at the Company's AGM in May 2026.
13. Reconciliation of operating profit/(loss) to operating cash flows
|
|
|
|
Group |
|
|
Company |
|
|
|
2025 $ million |
2024 $ million |
|
2025 $ million |
2024 $ million |
|
Operating profit/(loss) |
|
8.7 |
64.3 |
|
(9.3) |
20.6 |
|
Share-based payments |
|
1.6 |
0.9 |
|
1.6 |
0.9 |
|
Depletion, depreciation and amortisation |
|
46.6 |
47.3 |
|
- |
- |
|
Impairment (reversal)/charge |
|
- |
(26.3) |
|
0.4 |
(31.2) |
|
Taxes paid-in-kind |
|
(0.4) |
(1.9) |
|
- |
- |
|
Operating cash flows before movements in working capital |
|
56.5 |
84.3 |
|
(7.3) |
(9.7) |
|
|
|
|
|
|
|
|
|
Decrease/(increase) in inventories |
|
3.2 |
(6.0) |
|
- |
- |
|
Decrease/(increase) in receivables 1 |
|
26.2 |
11.3 |
|
- |
(1.7) |
|
Decrease in payables |
|
(0.4) |
(0.3) |
|
(0.6) |
(0.1) |
|
Cash generated by (used in) operations |
|
85.5 |
89.3 |
|
(7.9) |
(11.5) |
|
|
|
|
|
|
|
|
|
Interest received |
|
0.5 |
0.4 |
|
0.3 |
0.3 |
|
Interest paid |
|
(0.1) |
- |
|
- |
- |
|
Other/restructuring expense outflow |
|
- |
(0.4) |
|
- |
- |
|
Income taxes paid |
|
(30.3) |
(35.3) |
|
- |
- |
|
Net cash from (used in) operating activities |
|
55.6 |
54.0 |
|
(7.6) |
(11.2) |
1 Includes $1.3m decrease (2024: $2.5m) in expected credit losses in respect of Egypt trade receivables.
During the year, a total of $2.0m of trade receivables due from EGPC in Egypt were settled by way of non-cash offset, of which $0.9m relates to preliminary bond for SWER concession, $0.3m relates to training and development lease bonuses/commitment paid to EGPC, $0.3m participation in a bid round process and $0.5m solidification of shortfall on El Fayum licence commitment.
During 2024, a total of $0.5m of trade receivables due from EGPC in Egypt were settled by way of non-cash offset, of which $0.4m relates to the assignment bonus settled upon receipt of contingent consideration in relation to IPR Farm out and $0.1m to the training bonuses settled with EGPC.
14. Subsequent events
Further regional instability in the Middle East, with global economic and political implications, was introduced by the joint US and Israel military action that began on 26 February 2026 with surprise airstrikes on multiple sites and cities across Iran. These strikes and subsequent military action by the US and Israel, and the retaliatory actions taken by Iran in response, have resulted in surges in oil and gas prices, widespread disruption in aviation, travel and tourism and heightened volatility in financial markets. The conflict has also disrupted international trade, particularly through closure of the Strait of Hormuz and other key shipping routes and strikes on gas and oil facilities. The Group recognises that the conflict, if it continues for an extended period, could result in longer term regional and global inflationary pressure and an increased risk of recession.
The Group continues to carefully monitor the wider geopolitical impact and perception in Egypt of the conflicts in the Middle East, in connection with its assets and operations in the region.
15. Preliminary results announced
Copies of the announcement will be available to download from www.pharos.energy. The Annual Report and Accounts, together with notice of the 2026 AGM, will be posted to shareholders in due course.
Non-IFRS measures
The Group uses certain measures of performance that are not specifically defined under IFRS or other generally accepted accounting principles. These non-IFRS measures include cash operating costs per barrel, DD&A per barrel, EBITDAX, free cash flow, operating cash per share and return on capital employed.
Cash operating costs per barrel
Cash operating costs are defined as cost of sales less DD&A, production based taxes, movement in inventories and certain other immaterial cost of sales.
Cash operating costs for the period are then divided by barrels of oil equivalent produced. This is a useful indicator of cash operating costs incurred to produce oil and gas from the Group's producing assets.
|
|
|
|
|
|
|
|
|
|
2025 |
|
|
2024 |
|
|
|
|
|
|
$ million |
|
|
$ million |
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of sales |
96.4 |
|
|
87.3 |
||||||||
|
(Less)/add: |
|
|
|
|
||||||||
|
Depreciation, depletion and amortisation |
(46.4) |
|
|
(47.1) |
||||||||
|
Production based taxes |
(7.3) |
|
|
(9.2) |
||||||||
|
Change in inventories |
(3.2) |
|
|
6.0 |
||||||||
|
Trade receivables expected credit loss |
1.3 |
|
|
2.5 |
||||||||
|
Other cost of sales |
|
|
|
|
(2.6) |
|
|
(1.7) |
||||
|
Cash operating costs |
|
|
|
|
38.2 |
|
|
37.8 |
||||
|
Production (BOEPD) |
|
|
|
|
5,398 |
|
|
5,801 |
||||
|
Cash operating cost per BOE ($) |
|
|
|
|
19.39 |
|
|
17.80 |
||||
Cash-operating costs per barrel by Segment (2025)
|
|
|
|
|
|
|
|
|
|
|
Vietnam |
|
Egypt |
|
Total |
||||
|
|
|
|
|
|
|
|
|
|
|
$ million |
|
$ million |
|
$ million |
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Cost of sales |
|
|
|
|
|
|
81.0 |
|
15.4 |
|
96.4 |
|||||||
|
|
(Less)/add: Depreciation, depletion and amortisation |
(41.4) |
|
(5.0) |
|
(46.4) |
||||||||||||
|
|
Production based taxes |
(7.2) |
|
(0.1) |
|
(7.3) |
||||||||||||
|
|
Change in inventories |
(3.1) |
|
(0.1) |
|
(3.2) |
||||||||||||
|
|
Trade receivables expected credit loss |
- |
|
1.3 |
|
1.3 |
||||||||||||
|
|
Other cost of sales |
(1.6) |
|
(1.0) |
|
(2.6) |
||||||||||||
|
Cash operating costs |
|
|
|
|
|
27.7 |
|
10.5 |
|
38.2 |
||||||||
|
Production (BOEPD) |
|
|
|
|
|
4,095 |
|
1,303 |
|
5,398 |
||||||||
|
Cash operating cost per BOE ($) |
|
|
|
|
|
18.53 |
|
22.08 |
|
19.39 |
||||||||
Cash-operating costs per barrel by Segment (2024)
|
|
|
|
|
|
|
|
|
|
|
Vietnam |
|
Egypt |
|
Total |
||||
|
|
|
|
|
|
|
|
|
|
|
$ million |
|
$ million |
|
$ million |
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Cost of sales |
|
|
|
|
|
|
75.6 |
|
11.7 |
|
87.3 |
|||||||
|
|
(Less)/add: Depreciation, depletion and amortisation |
(42.1) |
|
(5.0) |
|
(47.1) |
||||||||||||
|
|
Production based taxes |
(9.1) |
|
(0.1) |
|
(9.2) |
||||||||||||
|
|
Change in inventories |
6.0 |
|
- |
|
6.0 |
||||||||||||
|
|
Trade receivables expected credit loss |
- |
|
2.5 |
|
2.5 |
||||||||||||
|
|
Other cost of sales |
(1.3) |
|
(0.4) |
|
(1.7) |
||||||||||||
|
Cash operating costs |
|
|
|
|
|
29.1 |
|
8.7 |
|
37.8 |
||||||||
|
Production (BOEPD) |
|
|
|
|
|
4,361 |
|
1,440 |
|
5,801 |
||||||||
|
Cash operating cost per BOE ($) |
|
|
|
|
|
18.23 |
|
16.51 |
|
17.80 |
||||||||
Depreciation, depletion and amortisation costs per barrel
DD&A per barrel is calculated as net book value of oil and gas assets in production, together with estimated future development costs over the remaining 2P reserves. This is a useful indicator of ongoing rates of depreciation and amortisation of the Group's producing assets.
|
|
|
|
|
|
|
|
|
|
2025 |
|
|
2024 |
|
|
|
|
|
|
$ million |
|
|
$ million |
||||
|
Depreciation, depletion and amortisation |
46.4 |
|
|
47.1 |
||||||||
|
Production (BOEPD) |
|
|
|
|
5,398 |
|
|
5,801 |
||||
|
DD&A per BOE ($) |
|
|
|
|
23.55 |
|
|
22.18 |
||||
DD&A per barrel by segment (2025)
|
|
|
|
|
|
|
|
|
|
Vietnam |
|
Egypt |
|
Total |
|
|
|
|
|
|
|
|
|
|
|
$ million |
|
$ million |
|
$ million |
|
|
Depreciation, depletion and amortisation |
41.4 |
|
5.0 |
|
46.4 |
|
||||||||
|
Production (BOEPD) |
|
|
|
|
4,095 |
|
1,303 |
|
5,398 |
|||||
|
DD&A per BOE ($) |
|
|
|
|
27.70 |
|
10.51 |
|
23.55 |
|||||
EBITDAX
EBITDAX is earnings from continuing activities before interest, tax, DD&A, impairment (reversal)/charge of PP&E and intangibles, exploration expenditure, pre-licence costs and Other/restructuring expense items in the current year.
|
|
|
|
|
|
|
|
|
|
2025 |
2024 |
|
|
|
|
|
|
|
|
|
|
|
$ million |
$ million |
|
|
Operating profit |
8.7 |
64.3 |
|||||||||
|
Depreciation, depletion and amortisation |
46.6 |
47.3 |
|||||||||
|
Pre-licence costs |
0.4 |
0.8 |
|||||||||
|
Impairment reversal |
- |
(26.3) |
|||||||||
|
EBITDAX |
|
|
|
|
55.7 |
86.1 |
|||||
Free cash flow
Free cash flow is calculated by subtracting capital cash expenditure from net cash from operating activities.
|
|
|
|
|
|
|
|
|
|
2025 |
2024 |
|
|
|
|
|
|
|
|
|
|
|
$ million |
$ million |
|
|
Net cash from operating activities |
55.6 |
54.0 |
|||||||||
|
Capital cash expenditure |
(27.6) |
(26.1) |
|||||||||
|
Free cash flow |
|
|
|
|
28.0 |
27.9 |
|||||
Operating cash per share
Operating cash per share is calculated by dividing net cash from (used in) continuing operations by number of shares in the year.
|
|
|
|
|
|
|
|
|
|
2025 |
2024 |
|
|
|
|
|
|
|
|
|
|
|
$ million |
$ million |
|
|
Net cash from operating activities |
55.6 |
54.0 |
|||||||||
|
Weighted number of shares in the year |
416,910,030 |
417,019,506 |
|||||||||
|
Operating cash per share |
|
|
|
|
0.13 |
0.13 |
|||||
Return on capital employed (ROCE)
ROCE is calculated by dividing operating profit by total assets less current liabilities. ROCE measures a company's profitability and the efficiency with which its capital is employed.
|
|
|
|
|
|
|
|
|
|
2025 |
2024 |
|
|
|
|
|
|
|
|
|
|
|
$ million |
$ million |
|
|
Operating profit |
8.7 |
64.3 |
|||||||||
|
Total assets less current liabilities |
386.1 |
409.6 |
|||||||||
|
ROCE |
|
|
|
|
2.3% |
15.7% |
|||||
Glossary of Terms
AGM
Annual general meeting
bbl
Barrel
boe or BOE
Barrels of oil equivalent
boepd or BOEPD
Barrels of oil equivalent per day
bopd
Barrels of oil per day
BSR
Binh Son Refining and Petrochemical JSC, the operator of the Dung Quất refinery, Quảng Ngãi Province, Vietnam
cash
Cash, cash equivalent and liquid investments
capex
Capital expenditure
CEO
Chief Executive Officer
CNV
Ca Ngu Vang field located in Block 9-2, Vietnam
Company or Pharos
Pharos Energy plc
Contingent Resources, contingent resources or CR
Those quantities of petroleum to be potentially recoverable from known accumulations by application of development projects but which are not currently considered to be commercially recoverable due to one or more contingencies
Contractor
The party or parties identified as being, or forming part of, the "CONTRACTOR" as defined in the El Fayum Concession or, as the case may be, the North Beni Suef Concession
DD&A
Depreciation, depletion and amortisation
EBITDAX
Earnings before interest, tax, DD&A, impairment of PP&E and intangibles, exploration expenditure and other/restructuring items in the current year
EGP
Egyptian Pounds, the lawful currency of the Arab Republic of Egypt
EGPC
Egyptian General Petroleum Corporation, an Egyptian state oil and gas company and the industry regulator
El Fayum or the El Fayum Concession
The concession agreement for petroleum exploration and exploitation entered into on 15 July 2004 between the Arab Republic of Egypt, EGPC and Pharos El Fayum in respect of the El Fayum area, Western Desert, as amended from time to time
Financial Statements
The preliminary financial statements of the Company and the Group for the year ended 31 December 2025
FPSO
Floating, production, storage and offloading Vessel
GHG
Greenhouse gas
Group
Pharos and its direct and indirect subsidiary undertakings
1H
The first half of a calendar year
2H
The second half of a calendar year
HLJOC
Hoang Long Joint Operating Company, the operator of the TGT field on Block 16-1, Vietnam
HVJOC
Hoan Vu Joint Operating Company, the operator of the CNV field on Block 9-2, Vietnam
IFRS
International Financial Reporting Standards
IMF
The International Monetary Fund
IPR or IPR Energy Group
The IPR Energy group of companies, including IPR Lake Qarun and IPR Energy AG, or such of them as the context may require
IPR Lake Qarun
IPR Lake Qarun Petroleum Co, an exempted company with limited liability organised and existing under the laws of the Cayman Islands (registration number 379306), a wholly owned subsidiary of IPR Energy AG
JOC
Joint operating company
JV
Joint venture
km
Kilometre
km2
Square kilometre
LTI
Lost Time Injury
LTIP
Long Term Incentive Plan
m
Million (where used to describe a monetary amount)
McDaniel
McDaniel & Associates Consultants Ltd
mmboe
Million barrels of oil equivalent
MMstb
Millions of stock tank barrels
NAV
Net asset value
NBE
The National Bank of Egypt, the largest Egyptian commercial bank and owned by the state of Egypt
NBS, North Beni Suef or the North Beni Suef Concession
The concession agreement for petroleum exploration and exploitation entered into on 24 December 2019 between the Arab Republic of Egypt, EGPC and Pharos El Fayum in respect of the North Beni Suef area, Nile Valley
OCF
Operating cash flow
opex
Operational expenditure
PEF
Pharos El Fayum, a wholly owned subsidiary of the Company holding the Group's participating interest in El Fayum and North Beni Suef
Petrosilah
An Egyptian joint stock company held 50/50 between EGPC and the Contractor parties under the El Fayum Concession (being IPR Lake Qarun and PEF)
Petrovietnam
Vietnam Oil and Gas Group, the Vietnamese state-owned integrated oil and gas company
PP&E
Property, plant and equipment
Prospect
An identified trap that may contain hydrocarbons. A potential hydrocarbon accumulation may be described as a lead or prospect depending on the degree of certainty in that accumulation. A prospect generally is mature enough to be considered for drilling
PSC
Production sharing contract or production sharing agreement
Reserves or reserves
Reserves are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. Reserves must further satisfy four criteria: they must be discovered, recoverable, commercial and remaining based on the development projects applied
RBL
Reserve-based lending facility
TGT
Te Giac Trang field located in Block 16-1, Vietnam
TLJOC
Thang Long Joint Operating Company, the operator of Block 15-2/01, Vietnam, with which the HLJOC shares access to the FPSO used for TGT production
UK
United Kingdom
USD, US dollars or $
United States dollars, the lawful currency of the United States of America
£
UK Pound Sterling
1C
Low estimate scenario of Contingent Resources
1P
Equivalent to proved Reserves; denotes low estimate scenario of Reserves
2C or 2C Contingent Resources
Best estimate scenario of Contingent Resources
2P Reserves or 2P Commercial Reserves
Equivalent to the sum of proved plus probable Reserves; denotes best estimate scenario of Reserves
3C
High estimate scenario of Contingent Resources
3P
Equivalent to the sum of proved, probable and possible Reserves; denotes high estimate scenario of Reserves
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