2023 Preliminary Results

RNS Number : 4838I

Pharos Energy PLC

27 March 2024

Pharos Energy plc

("Pharos" or the "Company" or, together with its subsidiaries, the "Group")

2023 Preliminary Results

Pharos Energy plc, an independent energy company, announces its preliminary results for the year ended 31 December 2023. A conference call for analysts will take place at 11.00 GMT today.

Jann Brown, Chief Executive Officer, commented:

"Pharos delivered on several fronts in 2023, laying the groundwork for significant momentum going into 2024. The Group had drilling success both in Vietnam, with the CNV production well coming in strongly, and in Egypt, with two discoveries from exploration wells on NBS and El Fayum. On Block 125, parallel discussions with several potential farm-in partners are ongoing and we are actively working with another operator in the region to enhance our efforts in securing a suitable rig.

"We have managed the challenges of payment delays in Egypt, thanks in part to our carry, but also by careful cost control and capital discipline. We ended the year in a strong financial position with net debt down to $6.6m and cash balances of $32.6m, from revenues of $168.1m. We are also delighted that we have now received $10m from EGPC, as they resume payments to foreign oil companies on the back of the substantial support packages committed to Egypt, putting us into a net cash position today. A strong balance sheet provides us with the foundation to continue our track record of delivering shareholder returns, adding $8.4m through a combination of share buyback programmes ($2.8m of which was completed in 2023) and dividend payments in 2023.

"Today, the Board have recommended a final dividend for the 2023 financial year of 0.77 pence per share, subject to shareholders' approval at the Company's 2024 AGM. This would take the 2023 full year dividend to 1.10 pence per share, an increase of 10% on the prior year.

"Looking ahead, we are advancing plans to drill the potentially transformational Block 125 in Vietnam, and we look forward to updating shareholders on progress. In the meantime, we continue to execute on our strategy, including continuing on our recently published roadmap to net zero, of delivering value for all stakeholders in 2024 and beyond."

2023 Operational Highlights

· Group working interest 2023 production was 6,508 boepd net (2022: 7,166 boepd net), in line with 2023 guidance:

- Vietnam 5,127 boepd (2022: 5,418 boepd)

- Egypt 1,381 bopd (2022: 1,748 bopd)

· In Vietnam:

- Strong performance from first new CNV lateral well, put on production in 1Q 2023

- CNV Revised Field Development Plan (RFDP) submitted to partners for approval, with discussions ongoing

- Continuing positive feedback received from PetroVietnam and the Ministry of Industry and Trade (MOIT) on five-year extension proposals to the TGT & CNV licences

- On Blocks 125 & 126, two-year PSC extension granted to 8 November 2025

- Competent Person's Report (CPR) for Block 125 published in July 2023, confirming a range of gross unrisked prospective oil resources of between 1,178 MMstb (1U) and 29,785 MMstb (3U) with a Mean value of 13,328 MMstb

· In Egypt:

- Three new wells (2 producers and 1 injector) put on production and injection in 2023, in line with pre-drill expectations

- On El Fayum, exploration success with the first commitment well in the Abu Roash G and Upper Bahariya formations in July 2023. The well is set up for re-entry and testing in 2024

- On North Beni Suef (NBS), first exploration commitment well (NBS-SW1X) declared a commercial discovery and put on production in December 2023, opening up a new area for production and development

- Approval received from EGPC in September 2023 for the grant of a 20-year development lease for NBS-SW1X

- 3D seismic survey acquired on time and on budget in 2H 2023

2023 Financial Highlights

· Group revenue of $168.1m ^1,2 (2022: $221.6m ^1,2)

· Cash generated from operations $88.8m (2022: $110.7m)

· Operating cash flow $44.9m ³ (2022: $53.4m)

· Cash operating costs of $15.70/bbl ⁴ (2022: $16.36/bbl ⁴)

· Cash balances as at 31 December 2023 of $32.6m (2022: $45.3m)

· Net debt as at 31 December 2023 of $6.6m ^4,5 (2022: $28.9m ^4,5)

· Loss for the year of $48.8m (2022: profit $24.4m)

· Net debt to EBITDAX of 0.06x ⁴ (2022: 0.23x ⁴)

2024 Outlook and Highlights

· Group working interest production guidance of 5,200 - 6,500 boepd net:

- Vietnam 3,900 - 5,000 boepd

- Egypt 1,300 - 1,500 bopd

· In Vietnam:

- TGT RFDP approved by MOIT on 9 January 2024

- Planning underway for a two-well TGT drilling programme, expected to commence 2H 2024

- On Block 125, ongoing discussions with another operator to secure a well drilling slot during their multi-well drilling programme in the region

- Parallel discussions with several potential farm-in partners for Block 125 in progress

· In Egypt:

- Continuation of modest and measured approach to capital allocation and drilling in El Fayum and NBS, with potential to ramp up activity this year and beyond in response to the improving economic environment

- Focus for this year's work programme in El Fayum is low-cost recompletions and waterflood

- Processing and interpretation of c.130km² of 3D seismic data on NBS is underway and expected to be completed in 2H 2024

- Development drilling in the NBS SW field planned to start in 2H 2024

- Ongoing engagement with EGPC regarding payment of receivables, and more favourable outlook following $57 billion support packages

- Concession terms in Egypt being reviewed following award of 20-year development lease over NBS

· Forecast Group cash capex in the year is expected to be $32m ($27.1m after Egyptian carry by IPR)

· Egypt cash opex and capex expected to be substantially funded in EGP from historical receivables

· Notification of $10m to be received today from EGPC in USD against receivable balance following payment delays through 2023

· Continuation of share buyback programme, with a further $3m committed for 2024

· Interim dividend in relation to the financial year ending 31 December 2023 of 0.33 pence per share, amounting to $1.7m, paid out on 24 January 2024. Final dividend of 0.77 pence per share for the year to be paid on 19 July 2024, subject to shareholder approval

· Appointment of Dr Bill Higgs as a new independent Non-Executive Director

· Jann Brown to retire and step down from the Board, effective 30 April 2024

· Appointment of Shore Capital Stockbrokers Limited (Shore Capital) as the Company's joint broker

¹ Egyptian revenues are stated post government take including corporate taxes

² Stated prior to realised hedging loss of $0.2m (2022: loss of $22.5m)

³ Operating cash flow = Net cash from operating activities, as set out in the Cash Flow Statement

⁴ See Non-IFRS measures on page 39

⁵ Includes RBL and National Bank of Egypt working capital drawdown

Enquiries

Pharos Energy plc Tel: 020 7747 2000

Jann Brown, Chief Executive Officer

Sue Rivett, Chief Financial Officer

Camarco Tel: 020 3757 4980

Billy Clegg | Andrew Turner | Rebecca Waterworth | Kirsty Duff

Notes to editors

Pharos Energy plc is an independent energy company with a focus on sustainable growth and returns to stakeholders, which is listed on the premium segment of the London Stock Exchange. Pharos has production, development and/or exploration interests in Egypt and Vietnam. In Egypt, Pharos holds a 45% working interest share in the El Fayum Concession in the Western Desert, with IPR Lake Qarun, part of the international integrated energy business IPR Energy Group, holding the remaining 55% working interest. The El Fayum Concession produces oil from 10 fields and is located 80 km southwest of Cairo. It is operated by Petrosilah, a 50/50 joint stock company between the contractor parties (being IPR Lake Qarun and Pharos) and the Egyptian General Petroleum Corporation (EGPC). Pharos also holds a 45% working interest share in the North Beni Suef (NBS) Concession in Egypt, which is located immediately south of the El Fayum Concession. The first development lease on the NBS Concession was awarded in September 2023 and production started in December 2023. IPR Lake Qarun holds the remaining 55% working interest in the NBS Concession, with development operations on the Concession currently undertaken by Petrosilah on behalf of the newly formed joint operating company, Petro Beni Suef. The first exploration phase under the NBS Concession expired in March 2024 with all work programme commitments completed. In Vietnam, Pharos has a 30.5% working interest in Block 16-1 which contains 97% of the Te Giac Trang (TGT) field and is operated by the Hoang Long Joint Operating Company. Pharos' unitised interest in the TGT field is 29.7%. Pharos also has a 25% working interest in the Ca Ngu Vang (CNV) field located in Block 9-2, which is operated by the Hoan Vu Joint Operating Company. Blocks 16-1 and 9-2 are located in the shallow water Cuu Long Basin, offshore southern Vietnam. Pharos also holds a 70% interest in, and is designated operator of, exploration Blocks 125 & 126, located in moderate to deep water in the Phu Khanh Basin, north east of the Cuu Long Basin, offshore central Vietnam.

Chair's Statement

A year of good performance

2023 has been a year characterised by good operational and financial performance across the Group.

Throughout the portfolio, the team's focus on operational delivery was evidenced by good drilling performance in both Vietnam, with the CNV well coming in strongly, and in Egypt, with discoveries on both the El Fayum and NBS exploration wells. We have continued to build on a culture of capital discipline to deliver material improvement to the Group's balance sheet despite ongoing payment lags in Egypt. This performance has allowed the Board to continue our commitment to sustainable shareholder returns in 2023, a core component of the Company's strategy since its listing in 1997.

These achievements are a testament to the hard work, dedication, and commitment of the entire Pharos team. I would like to congratulate all of my colleagues on a year of good performance which has positioned Pharos for a positive and sustainable future, with strong operational momentum, a robust capital structure, and exciting growth opportunities.

Board changes

Over the past year, I have greatly appreciated the support of my fellow Board members and the diverse skillsets that they bring to the table. Since joining Pharos in 2019, I have overseen the reshaping of the Board to ensure we meet stakeholders' expectations to ensure an independent Board that provides high standards of governance and oversight to support our long-term strategic framework. As such, I am delighted that Bill Higgs has joined the Pharos Board as an Independent Non-Executive Director. Bill is a very high calibre appointment, bringing a wealth of technical and commercial experience. His initial focus will be to maximise value from our exciting exploration prospects in Vietnam Blocks 125 & 126.

It is with great sadness that I note the death of Ed Story in December 2023. Ed founded the Company in 1991 and had been pivotal to the Company and its business from inception, specifically its listing in London in 1997 and its subsequent foray into a dozen different countries. Since retiring as CEO in March 2022, Ed had remained active as part of the Company's team in Vietnam. His responsibilities will now pass to Vincent Duignan, the Group Exploration Manager & General Manager South East Asia.

Jann Brown has informed the Board of her intention to retire and step down from the Board effective 30 April 2024, in a separate announcement today. The search for a replacement CEO will commence shortly and Jann has agreed to stay in her position as CEO to effect a managed and smooth transition. I would like to take this opportunity to thank Jann for her significant contribution to Pharos over the years. Jann will be leaving the Company in a strong position, both financially and operationally. We wish Jann well in her retirement.

A diverse and inclusive culture

Pharos is proud of our small yet diverse workforce, whose broad range of backgrounds, ethnicities, skills and experience help strengthen the Company for the future. As at year end, I am pleased to report that the Company has four female Directors, representing two thirds of the Board. Most notably, our UK-based staff comprises 17 people from 10 different nationalities, of which women accounted for c.65%. We operate in a global industry, and it is important to ensure that we benefit from the diverse perspectives that our people bring.

The Board and Management team are dedicated to creating a safe workplace for all, in which people are confident to engage and contribute. The opening up of the world post COVID-19 has allowed the Board to meet in person and engage meaningfully with our colleagues across the world. In June 2023, the Company organised an off-site day where colleagues from Egypt, Vietnam and the UK met in London to exchange business ideas, provide feedback and promote team-building. This is important not only for the effective functioning of the Board, but also to develop and empower all employees, underpinning our commitment to maintaining high standards of governance.

We recognise that 2023 has seen significant geopolitical instability, something that has had far-reaching impacts on communities and families, the global economy, and trade. Our thoughts remain with those who have been affected by the active conflicts in Ukraine and the Middle East. We continue to support our colleagues and contractors during this difficult time, as well as ensuring that our business can continue to function unaffected.

Ongoing dialogues with stakeholders

Pharos' operational success and long-standing partnerships, spanning over 25 years, are built on a culture of transparency and integrity. Since joining the Board, Jann and I have maintained regular dialogues with local governments, joint-operating partners, local communities, and shareholders to ensure the Board is well-informed as the Company develops its plans for growth.

In November 2023, the Board held a Strategy Day to focus on where and how we can offer value to our stakeholders, with inputs from a number of key parties, experts and shareholders. The results of our Strategy Day reinforced our commitment to pursue a combination of cash returns per share and reinvestment to enhance our asset base - a strategy regularly communicated back to our stakeholders. In November, Jann and I also met with the Vietnamese Minister of Industry and Trade to discuss the proposed licence extensions on our assets in country, highlighting the important benefits that these bring, not just to Pharos but also to Vietnam.

The Board and its management team will continue to engage in a personal and meaningful way with our various stakeholders in 2024 and beyond. We are grateful to our shareholders whose support during times of uncertainty have been crucial to our growth and transformation throughout the years.

Making a positive difference

Recent events in 2023 have shown a need for better and more balanced energy systems worldwide, delivering energy that is not only lower carbon, but also reliable and affordable for developed and emerging nations alike. The outcomes of COP28 in December 2023 highlighted the importance of energy and climate security, and I firmly believe that responsible production and development of oil and gas resources, especially in economies transitioning from heavy reliance on coal such as Egypt and Vietnam, can be a major driver for economic development and alleviating energy poverty. Our host governments understand and appreciate Pharos' in-country impact that goes beyond national revenues from oil and gas production. In light of our strong relationships, local governments have encouraged Pharos to look into opportunities across other branches of the energy sector in their countries. We recognise a diverse mix of energy resources is crucial for long-term energy security, and we appreciate our host nations' trust in us and the long-term role that we play in their countries' energy transition.

While it is clear that there are emerging opportunities across the energy sector, our first priority is improving our emissions footprint by enhancing our own operational efficiency. I am proud of the progress that we have made on our Net Zero journey. In December 2023, Pharos published a detailed Net Zero Roadmap to achieve net zero GHG emissions by 2050. The Net Zero Roadmap, which was researched and developed by the Company in close consultation with specialist advisors and consultants, models emission reduction pathways to achieve net zero Scope 1 (direct) and Scope 2 (indirect) GHG emissions from all existing and proposed future assets by 2050 or before. We look to reduce our emissions over the years and remain committed to transparency in our sustainability journey.

Social stewardship is at the heart of our sustainability journey. In 2023, we supported a record 22 community investment projects across Egypt, Vietnam, and the UK, investing a total of $247,373 in education, training, healthcare and infrastructure in our local communities. Pharos remains committed to deploying our expertise and capital to partner with host governments to develop local capacity, enhance energy security and unlock value from our host nations' natural resources in an environmentally sustainable and socially responsible manner.

Outlook

Jann and her team continued to deliver on the Company's strategy in 2023 and built on our track record of sustainable shareholder returns. Focusing on a clear growth strategy and disciplined capital management approach, we will continue to deliver regular returns to shareholders whilst growing the value of our company.

As Chair, I would like to thank the Pharos team for their commitment and delivery through the year. I am also grateful to our host nations and communities for their continued trust, our shareholders for their confidence, and our partners, suppliers and advisors for their support. We have created a portfolio of assets and set of capabilities which are unique within our sector, and the Board looks to the future with great confidence in our ability to deliver growth and value in 2024 and beyond.

John Martin

Non-Executive Chair

Chief Executive Officer's Statement

Commitment to adding value

Pharos delivered on several fronts in 2023. Throughout the year, the Board and senior management team maintained a clear focus on capital discipline to strengthen our financial position and enhance existing opportunities within our portfolio. We put the funding of our established dividend programme at the heart of our business model, and it is through this lens that we assess our capital allocation goals. We are determined to balance regular returns to shareholders with investment in our assets to generate sustainable growth, and value per share whilst preserving balance sheet resilience.

Our investment programme in 2023

We have managed the challenges of payment delays in Egypt, thanks in part to our carry, but also by strict cost control and capital discipline. We ended the year in a strong financial position with net debt down 77% to $6.6m and cash balances of $32.6m, from revenues of $168.1m. A stronger balance sheet provides the foundation to continue our track record to deliver shareholder returns, adding $8.4m this year through a combination of share buyback programmes and dividend payments. As at year end 2023, we are proud to have returned a total of $537.6m to shareholders.

Our assets are the foundation of our returns and during the year, we made progress on a number of opportunities within the portfolio. In Vietnam, we continued to deliver a high netback and stable production during the year. Production in 2023 from the TGT and CNV fields averaged 5,127 boepd, in line with guidance, with delivery from the first CNV lateral well coming in above expectations in the first half. The approval of the TGT RFDP from MOIT in January 2024 was the final step towards the commencement of a two-well TGT drilling programme, which is expected to start in the second half of this year. On the exploration side, the publication of the independent report prepared by ERCE on Blocks 125 & 126 further highlights the world-class scale and potential in these basin-opening exploration blocks, confirming 13,328 MMstb of mean gross unrisked prospective oil resources. With the exploration period of the PSC now extended to November 2025, Pharos is well placed to source a rig, bring in a farm-in partner and complete all necessary work to drill the first exploration well on this exciting opportunity.

In Egypt, discretionary investment has been modest, and focused on delivering a steady performance from El Fayum, averaging 1,381 bopd, in line with guidance. We also ensured that our commitments to host governments were fulfilled. Most notably, the Group drilled two exploration wells, one on each of the North Beni Suef and El Fayum Concessions, with drilling successes on each of these. The NBS-SW1X exploration commitment well was declared a commercial discovery and put on production only nine months after drilling, following the grant of a 20-year development lease in September 2023. This was a crucial first step towards proving up this new reserve base and adding further barrels to overall Group reserves and subsequently production. The reforms recently announced by the Egyptian government, plus the international funding packages totalling together $57 billion, set out the path for Egypt's economic recovery and the restoration of sustainable, inclusive growth. In the early stages of these reforms, the JV will maintain a measured approach to capital allocation and drilling in Egypt in 2024. However, we recognise that it is important to be fully prepared to increase our investment levels once payments for oil production reach a more regular pattern.

The health and safety of our workforce remains our highest priority. We are committed to operating safely and responsibly at all times. Pharos continued to have an excellent safety record during 2023, and I am pleased to highlight that the Company reported zero LTIs across the Group. In particular, in Vietnam, this is an achievement that we have maintained since 1997 thanks to the JOCs' consistent efforts to provide and champion workers' health, safety, and well-being. We are careful to maintain this achievement going into 2024.

Our stable operational performance in 2023 has laid a solid foundation for the 2024 work programme to further develop growth potential in our assets. Underpinned by a strong balance sheet and steady production base across the portfolio, Pharos is in a good position to execute our strategy of delivering sustainable value through a focus on organic and inorganic growth opportunities, coupled with our commitment to regular shareholder returns.

A clear focus on our strategic priorities

1. Regular shareholder returns

At Pharos, we have a firm commitment to add sustainable shareholder value, and both the means and discipline to do it. We established a sustainable shareholder return framework via share buybacks and dividends, as part of the return mix that we can control. Dividends have been a key part of the Company's equity story since its listing and, following approval at the 2023 AGM, we returned $5.6m to shareholders via a single dividend for the 2022 financial year of 1 pence per share. In December 2023, an interim dividend of 0.33 pence per share, or $1.7m equivalent, was paid in January 2024. Our dividend policy is set in a clear formula, returning no less than 10% of operating cash flow (OCF) and takes into account volatility in the market such as movements in commodity prices, tax, and working capital movements. Today, the Board have recommended a final dividend for the 2023 financial year of 0.77 pence per share which, subject to shareholders' approval at the Company's 2024 AGM, would take the 2023 full year dividend to 1.10 pence per share, an increase of 10% on the prior year. In addition, we announced in December 2023 the continuation of our share buyback programme, with a further $3m committed for 2024. This is another way for Pharos to return value to shareholders and to enhance NAV, earnings and dividends per share to shareholders over time.

2. Cash flow protections

Prudent financial management is a core part of our corporate DNA. Our focus on capital discipline through careful cost management and control has resulted in material net debt reduction in recent years. We maintain a balance of hedged and free-floating Group production, with less than 30% of the Group's 2024 production hedged at 31 December 2023, thus providing material exposure to the oil price. Pharos also operates in two very different jurisdictions which provides diversification and resilience in a volatile world. In particular, we are proud of our consistent payment record in Vietnam, with TGT & CNV crude commanding an impressive premium to Brent of just under $7/bbl in 2023, a significant improvement from the prior year's $4/bbl. This has been driven by improvements in oil prices and our three-year sales contract for all TGT crude oil cargoes with BSR, which provides benefits in delivering into the local economy and reducing logistical spend as well as output tax savings. Additionally, to mitigate the impact of payment issues in Egypt, we have a working capital facility with the National Bank of Egypt (UK) to smooth out payment cycles there. Our receivables balance has built up in part due to the benefit of the carry we have had over all JV expenditure in Egypt, leaving us with in-country corporate costs only, and partly due to our position of not drawing down the balance in local currency. With the carry expiring in 1Q 2024, we intend to use this receivables balance to fund the majority of the JV expenditure going forward. As our dividend policy is based on the resilience of our operating cash flow, we maintain a strict capital control framework to protect our cash flows.

3. Diverse opportunity sets

We have a portfolio of organic growth opportunities in both Vietnam and Egypt, with options continuously being explored and development work progressed to maximise the potential of these complementary assets. In Vietnam, a variety of interesting leads and prospects have been identified on Block 125, a unique deep-water frontier exploration opportunity. We are in active parallel discussions with several parties interested in farming-in to support the funding of a commitment well on this Block and engaging with another operator to secure a well drilling slot during their multi-well drilling programme in the region. In Egypt, the exploration successes in both the North Beni Suef and El Fayum Concessions, complemented by the 20-year development lease on NBS-SW1X, added significant value to our low-cost Egyptian asset base and bode well for future growth.

We keep our assets under review to ensure that they are delivering the expected value and will look to monetise if we can accelerate this. As we maintain a firm handle on our existing portfolio, we are also considering inorganic opportunities. We actively look for opportunities to generate additional value and cash flow for our shareholders. We have a highly competent and dedicated team with strong industry relations to assess these in a disciplined and systematic manner.

Net Zero and our role in the energy transition

As Pharos explores these opportunities, we remain focused on the role we play in the socio-economic development of our host countries. We believe that oil and gas companies like Pharos, with our commitment to producing safely and responsibly, a wealth of industry expertise, and a strong balance sheet, will continue to play an important part in the energy transition, especially in emerging economies. In our dialogues with our host governments, we note their recognition of the importance of our operations and investments to their energy security and prosperity. We are encouraged to keep investing in their countries to ensure that they benefit from their natural resources as have many other nations, particularly in the developed world. This is exactly what we have done in 2023, having committed to the domestic sale of 100% of oil and gas produced from our producing assets in both Egypt and Vietnam during the year.

The critical role of upstream producers in the energy supply chain also opens opportunities to add value through the integration of other alternative energy resources, both to improve upstream efficiency and for standalone cash generation.

Pharos strengthened our commitment to net zero in 2023. We took another step in maturing our net zero strategy by publishing our Net Zero Roadmap in December, which provided further clarity in our pathway towards our 2050 climate commitment. The Net Zero Roadmap, which was researched and developed by the Company in close consultation with specialist advisors, established decarbonisation levers and interim targets to reduce our 2030 emissions by 15% against baseline 2021 emission. Additional information about our decarbonisation strategy, Emission Management Fund, and climate governance structure are included in our Net Zero Roadmap, which is available to download on our website.

We recognise that the path to net zero will not be straightforward, as it will take time to implement certain decarbonisation technologies and require pragmatism from our local partners, governments, and other stakeholders. Nevertheless, we are committed to our climate goals and will navigate our net zero journey in an honest and transparent manner, true to our corporate values of the 'The Pharos Way': Safety & Care, Energy & Challenge, Openness & Integrity, Empowerment & Accountability, and Pragmatism & Focus.

Our relationships with stakeholders

'The Pharos Way' drives not only our attitude towards sustainability and net zero, but also the way we build and maintain our relationship with stakeholders. We were greatly encouraged by the open and receptive dialogues we had with key stakeholders during the year.

In January 2023, the Company held a lunch to engage with analysts, both those providing research on the Company and those that do not, to foster relationships with key figures in the industry. During the year, we have met key individuals representing Regulators and Government in both Egypt and in Vietnam. We also engage regularly and meaningfully with the investment community and debt providers through multiple roadshows, meetings, live presentations, and Q&A sessions. We remain actively engaged with our joint venture partners and regularly participate in budget reviews, work programme discussions, and Management Committee meetings throughout the year. The Board and management team work hard to ensure we meaningfully engage with the whole workforce at various points during the year, as previously discussed in the Chair's Statement.

The supportive relationship that exists between Pharos and its different groups of stakeholders is a key building block to the successful delivery of our strategy, and we will continue to build on these collaborative relationships in 2024 and beyond.

Outlook

Although 2023 brought continued uncertainties, Pharos rose to these challenges and delivered a stabilised asset base set for growth, a more resilient balance sheet, well-protected cash flows, and an exciting mix of opportunities to pursue in 2024.

Finally, the significant change in the outlook for the Egyptian economy means that the most turbulent years look to be behind us. I have therefore decided that this is the right time for me to step down and hand over the baton to someone who will lead that next phase.

With capital discipline in our DNA, a clear set of strategic objectives, a portfolio of complementary assets, a strong financial position, a dedicated and diverse workforce, a committed Board and bench strength across the management team, the company has started 2024 well positioned to deliver long-term sustainable value for all and my successor will be chosen to take that to the next level.

I would like to take this opportunity to thank all our stakeholders for their ongoing support and our employees for their hard work, commitment and tenacity. I am confident in our ability to execute our strategy and look forward to steering Pharos on a path towards a new phase of growth and shareholder returns.

Jann Brown

Chief Executive Officer

Chief Financial Officer's Statement

Financially strong

I am pleased to report strong financial performance from our operations and a strengthening of our liquidity position, with net debt down 77% to $6.6m at the end of the year. We have returned a 7% yield, or $8.4m, to shareholders in the form of dividends and share buybacks and invested $26.7m in our asset base, all while paying down $35m of debt. This is despite a backdrop of reduced commodity prices and delays in payment for our Egyptian sales. In Egypt, we generated $2.5m of free cash during the year from a combination of receipts from our sales, receipt of the contingent consideration and the carry from our prior year farm out to IPR.

Our finance strategy continues to support our commitment to building shareholder value through organic growth and sustainable returns to shareholders.

We are in a net cash position as of today and, as we move out of the carry period on our Egyptian concessions, we look forward to drawing down on our receivables balance with EGPC to support our ongoing operations and capital investment in El Fayum and our new 20-year development lease at North Beni Suef.

Today, I am delighted to confirm the receipt of $10m in USD of our outstanding receivables, which equates to 26.7% of the year end balance.

Operating performance

Revenues

Group revenues of $168.1m, prior to realised hedging loss of $0.2m (2022: $221.6m prior to realised hedging loss of $22.5m) were negatively impacted by a 17% decrease in realised commodity prices.

Revenues for Vietnam of $149.2m (2022: $184.8m) decreased year on year as a result of lower realised prices and a reduction in sales volumes due to timing of cargoes. The average realised crude oil price was $87.42/bbl (2022: $106.44/bbl), an 18% decrease year on year, and the premium to Brent was just under $7/bbl on average (2022: over $4/bbl). Production was lower at 5,127 boepd (2022: 5,418 boepd). In October 2023, the Company and its partners signed a three year sales contract for all TGT crude oil cargoes with BSR to cover the period 1 January 2024 to 7 December 2026. This agreement supports energy security in-country and eliminates export duty being paid on cargoes, plus enables the JOC to recover input VAT. The premium to Brent will continue to be agreed every six months, which provides the Group with significant downside price protection for production from our largest Vietnam field.

The revenue for Egypt of $18.9m (2022: $36.8m, which includes an additional $7m following the improvement in the fiscal terms with the Third Amendment to the El Fayum Concession, increasing cost recovery oil from 30% to 40% from November 2020) decreased largely due to lower average realised crude oil price, down 19% to $78.18/bbl (2022: $96.03/bbl). On an equivalent basis, 45% working interest for the full year and after excluding additional revenues from the Third Amendment, 2022 revenues were $24.0m. Production fell to 1,381 bopd (2022: 1,748 bopd, following the farm-down of 55% interest and transfer of operatorship of the Group's Egyptian assets to IPR completed on 21 March 2022). There are two discounts applied to the El Fayum crude production - a general Western Desert discount and one related specifically to El Fayum. Both are set by EGPC and combined stayed consistent at over $4/bbl for the year (2022: over $5/bbl).

Hedging

For 2023, Pharos entered into zero cost collar hedges to protect the Brent component of forecast oil sales and to ensure future compliance with its obligations under the RBL over the producing assets in Vietnam and to provide downside protection to cash flows in the event of commodity price falling. The commodity hedges run until June 2025 and are settled monthly. Our hedging positions for the year resulted in a small $0.2m realised loss (2022: loss of $22.5m).

During 2023, 36% of the Group's total oil entitlement production was hedged, securing average floor and ceiling prices for the hedged volumes at $64.5/bbl and $100.8/bbl, respectively. The Group's RBL requires the Company to hedge at least 35% of Vietnam RBL production volumes and the current hedging programme meets this requirement through to December 2024, leaving 72% of Group production unhedged as at 31 December 2023.

Please see below a summary of hedges outstanding as at 31 December 2023, which are all zero cost collar.

	1Q24	2Q24	3Q24	4Q24	1Q25	2Q25
Production hedge per quarter - 000/bbls	120	120	150	120	60	60
Min. Average value of hedge - $/bbl	63.00	63.00	64.40	63.00	64.00	64.00
Max. Average value of hedge - $/bbl	91.50	87.88	88.66	89.00	90.00	90.00

Operating costs

Group cash operating costs, defined in the Non-IFRS measures section on page 39, were $37.3m (2022: $42.8m). Vietnam decreased by 9% from $31.7m to $28.8m in 2023, the equivalent of $15.39/bbl (2022: $16.03/bbl). The decrease is due to lower costs relating to the FPSO as a result of higher 3^rd party production throughput from the TLJOC, which decreased the HLJOC's share of the costs (TLJOC had 23.2% cost share in 2023 compared to 14.5% in 2022). In addition, for 1H 2022, there was $3.2m of export duty paid on TGT oil cargoes, which in 2023, we were not required to pay due to the oil being sold into the local economy.

Cash operating costs in Egypt were $8.5m in 2023 (2022: $11.1m), which equates to $16.86/bbl (2022: $17.40/bbl). The 3% decrease in cash operating costs per barrel was mainly related to decreases in transportation and fuel costs per bbl together with decreases in the fixed costs due to the devaluation of EGP against the USD during the year. Cash operating costs from 1 January 2022 up to 20 March 2022 were 100% share and from 21 March 2022 included only the Group's remaining 45% share. On a 100% equivalent basis, the cash operating costs for 2023 were $19.2m (2022: $19.3m).

DD&A

Group DD&A associated with the producing assets increased marginally to $55.4m (2022: $55.1m) driven by a higher depreciating cost base following December 2022 impairment reversals taken on both Vietnam and Egypt, partially offset by the 9% decrease in production year on year and lower DD&A rates per barrel from July following the net impairment charges taken on Vietnam and Egypt assets in June 2023.

DD&A per bbl is currently $27.25/boe for Vietnam (2022: $25.79/boe). DD&A per bbl for Egypt is $8.73/boe for the full year production entitlement (2022: $6.43/boe).

Administrative expenses

Administrative expenses in 2023 of $9.0m (2022: $10.0m) were lower than prior year. After adjusting for the non-cash items under IFRS2 Share Based Payments of $0.9m (2022: $1.3m) and project costs associated with new commercial opportunities of $0.4m (2022: $nil), the underlying administrative expense is $7.7m (2022: $8.7m).

Operating (loss)/profit

Operating profit from continuing operations for the year was $47.3m (2022: $72.3m) excluding the net impairment charge of $65.4m (2022: $27.9m net impairment reversal), reflecting the combined impact of a lower commodity price environment throughout the year and a decrease in production volumes.

Other/restructuring expenses, loss on disposal and (loss)/gain on fair value movement of financial asset

Other/restructuring expenses for the year of $0.6m (2022: $0.8m) were due to changes in the best estimate of the adjustment relating to the interim period between the economic date of 1 July 2020 and the completion date of the disposal of 55% interest in the Egypt concessions. 2022 included restructuring costs for both the head office in London and the Egypt office in Cairo ($0.1m). In addition, for 2022, there was a $0.7m charge relating to the premium on the transfer of the lease on the London office.

Loss on disposal in 2022 of $6.6m is related to the farm-down transaction, where 55% of the Group's operated interest in each of our Egyptian Concessions, El Fayum and North Beni Suef, acquired by IPR on 21 March 2022.

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 (please refer to Note 14 for further details). From 2023, the variance of the contingent consideration is booked under (loss)/gain on fair value movement of financial asset.

The loss on fair value movement of financial assets for the year of $0.3m (2022: $0.3m gain) is due to $0.4m revision of the contingent consideration, partially offset by $0.1m reduction in contingent liability (assignment fee).

Finance costs

Finance costs decreased to $10.2m (2022: $12.7m), mainly related to a charge of $2.7m following a change in estimated future cash flows following the December 2023 RBL redetermination and amortisation of capitalised borrowing costs of $(1.4)m (2022: charge of $2.6m and amortisation of capitalised borrowing costs of $1.5m). There was interest expense payable and similar fees of $6.4m charged on the RBL and NBE (2022: $6.1m), unwinding of discount on Vietnam decommissioning provisions of $2.0m (2022: $1.3m) and foreign exchange losses of $0.5m (2022: $1.2m) primarily driven by devaluation of EGP against USD.

Cash operating cost per barrel*	2023 $m	2022 $m
Cost of sales	111.2	116.8
Less
Depreciation, depletion and amortisation	(55.4)	(55.1)
Production based taxes	(10.5)	(14.7)
Export duty	-	(3.2)
Inventories	(4.0)	1.8
Trade Receivable risk factor provision	(2.2)	(1.5)
Other cost of sales	(1.8)	(1.3)
Cash operating costs	37.3	42.8
Production (BOEPD)	6,508	7,166
Cash operating cost per BOE ($)	15.70	16.36

DD&A per barrel*	2023 $m	2022 $m
Depreciation, depletion and amortisation	55.4	55.1
Production (BOEPD)	6,508	7,166
DD&A per BOE ($)	23.32	21.07

* Cash operating cost per barrel and DD&A per barrel are alternative performance measures. See pages 39 and 40.

Cash operating cost per barrel by Segment	Vietnam $m	Egypt Total $m	Total $m
Cost of sales	95.6	15.6	111.2
Less
Depreciation, depletion and amortisation	(51.0)	(4.4)	(55.4)
Production based taxes	(10.4)	(0.1)	(10.5)
Inventories	(3.9)	(0.1)	(4.0)
Trade Receivable risk factor provision	-	(2.2)	(2.2)
Other cost of sales	(1.5)	(0.3)	(1.8)
Cash operating costs	28.8	8.5	37.3
Production (BOEPD)	5,127	1,381	6,508
Cash operating cost per BOE ($)	15.39	16.86	15.70

DD&A per barrel by Segment	Vietnam $m	Egypt $m	Total $m
Depreciation, depletion and amortisation	51.0	4.4	55.4
Production (BOEPD)	5,127	1,381	6,508
DD&A per BOE ($)	27.25	8.73	23.32

Movements in Property, Plant and Equipment	2023 $m	2022 $m
As at 1 January	381.8	399.8
Capital spend	12.1	23.2
Transfer from intangible assets	2.9	-
Revision in decommissioning assets	(2.5)	(13.9)
Recognition of right-of-use assets	-	0.8
DD&A - Oil and gas properties	(55.4)	(55.1)
DD&A - Other assets	(0.2)	(0.1)
Impairment (charge)/reversal - PP&E	(58.9)	27.1
As at 31 December	279.8	381.8
Property, Plant and Equipment	279.3	381.0
Right-to-use-Asset (IFRS 16 Impact)	0.5	0.8
As at 31 December	279.8	381.8

Taxation

The overall net tax charge of $19.8m (2022: $56.2m) relates to tax charges in Vietnam of $36.0m less the deferred tax credit on net impairment charges of $16.2m (2022: Vietnam tax charges of $47.9m plus the deferred tax charge on impairment reversal of $8.3m).

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. The Group records a tax charge, with a corresponding increase in revenue, for the tax paid by EGPC on its behalf. However, this is only valid if PEF is in a tax paying position and no such tax has been recorded this year.

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 the hedging losses of $0.2m (2022: $22.5m) recorded in the year 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 of $48.8m (2022: $24.4m post-tax profit) included $53.8m of disposals, re-measurements and impairments (2022: $14.9m). Business performance post-tax profit for the year was $5.0m (2022: $39.3m).

Disposals, re-measurements and impairments are comprised of the following:

Financial Statements Impact:	2023 $m	2022 $m
Revenue	(0.2)	(22.5)	Realised hedging losses
Cost of sales	(2.2)	(1.5)	Trade receivable risk factor provision
Impairment (charge)/reversal - Intangible assets	(6.5)	0.8
Impairment (charge)/reversal - Property, plant and equipment	(58.9)	27.1
Other/restructuring expenses	(0.6)	(0.1)	Revision of carry with IPR. In 2022, Egypt restructuring and release of end of service provision
Loss on disposal	-	(6.6)	Egypt farm-out
(Loss)/gain on fair value movement of financial asset	(0.3)	0.3	Revision of contingent consideration in relation to Egypt farm-out
Finance costs	(1.3)	(4.1)	Adjustment and amortisation of capitalised borrowing costs
Income tax credit/(charge)	16.2	(8.3)	Deferred tax on impairment charge/(reversal)
Total	(53.8)	(14.9)

Cash flow

Operating cash flow (before movements in working capital) was $103.8m (2022: $128.8m). After tax charges of $44.3m (2022: $54.7m), restructuring and exceptional expenses $nil (2022: $2.7m), working capital adjustments of $15.0m (2022: $18.1m) and interest received of $0.4m (2022: $0.1m), the cash generated from operations was $44.9m (2022: $53.4m).

Cash generated from operations, after tax charges, exceptional expenses and working capital movements, is the basis of our dividend framework.

Operating cash flow (before movements in working capital) adjusted for the impact of the hedging positions of $0.2m loss (2022: $22.5m loss) gives an underlying operational performance $104.0m (2022: $151.3m), which is consistent with the reduction in commodity prices and the production decrease year on year.

The increase in receivables was $19.1m (2022: increase in receivables of $7.7m). The movement in 2023 is primarily driven by $11.4m increase from Egypt, due to EGPC receivables. Since 2Q 2022, the Group has opted not to accept the payment of PEF's receivables balance in EGP unless required for operations, such as funding of ongoing expenditures upon expiry of the carry with IPR. PEF is entitled under contract to be paid for hydrocarbon sales in US dollars. The progressive devaluation of EGP against USD means that it is preferable to continue to hold USD denominated receivables.

In the space of two weeks, the Egyptian Government has: (i) announced a landmark agreement with ADQ (an Abu Dhabi sovereign wealth fund), whereby the latter will invest $35 billion for the development of the new coastal city of Ras El Hekma (the first $10 billion of which were immediately paid to Egypt); (ii) on 6 March 2024, raised all main interest rates by 600 basis points; signed a significantly expanded new loan from the IMF ($8 billion, including the original $3 billion secured in December 2022, which should facilitate additional $12 billion from other institutional lenders including the World Bank and the European Union); and let the Egyptian pound (EGP) fully float.

It is also widely expected that the flotation of the EGP will trigger an acceleration in the Egyptian Government's privatisation plan.

The Group is optimistic that its receivables position with EGPC will improve during 2024, through a combination of payments in USD and some EGP revenues or settlements, as needed, to fund our share of operational expenditure.

There was also an increase in Vietnam trade receivables of $7.4m (2022: decrease in receivables of $6.9m) due to three cargoes being lifted in December 2023. Payments for these cargoes were received in January 2024.

Capital expenditure on continuing operations for the year was lower at $26.7m (2022: $31.9m). On Block 16-1 - TGT Field, no new development wells were drilled in the year. During 2022, two development wells were drilled. On Block 9-2 - CNV Field, one development well, CNV-2PST1, completed in February 2023 and performed strongly, producing in excess of pre-drill estimates. In El Fayum, three wells were put on production and injection in 2023 and, on NBS, the first exploration commitment well, NBS-SW1X, was declared a commercial discovery and put on production in December 2023.

Net cash outflows from financing activities of $50.1m (2022: $19.8m outflow) included outflows in relation to the RBL of $22.4m in June 2023 and $12.6m in December 2023 (2022: $0.2m in June 2022 and $12.9m in December 2022) following the half year and year end redetermination processes. The amount drawn stood at $30.0m at year end.

The RBL facility, which is secured only over the Group's interest in the Vietnam producing assets, matures in July 2025. The facility amount is amortised by $14.2m, every redetermination, from 1 July 2022. The facility amount decreased to $43.0m from 1 January 2024 and will decrease further to $28.8m from 1^st July 2024. The Group is able to dividend up from the Vietnam RBL zone to the Company twice a year in January and July following approval of the redetermination. The Debt Service Reserve Account (DSRA) was put in funds of $12.5m on the first business day of 2024 to service the principal repayment due in July 2024 plus interest.

There was no net outflow from NBE revolving credit facility (2022: $2.7m). This facility allows PEF 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 2023 was $9.2m (2022: $9.2m).

Financing activities also included $2.8m outflow (2022: $2.9m) in relation to the $3m extension of the share buyback programme initiated in January 2023 and there was $5.6m outflow (2022: $nil) following payment of the final dividend for the 2022 financial year approved by shareholders at the AGM in May 2023.

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. 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 2023, the total payments to governments for the Group amounted to $188.0m (2022: $245.3m), of which $166.5m or 89% (2022: $211.5m or 86%) was related to the Vietnam producing licence areas, of which $110.8m (2022: $140.7m) was for indirect taxes based on production entitlement. In Egypt, payments to government totalled $19.3m (2022: $31.3m), of which $18.4m (2022: $28.8m) related to indirect taxes based on production entitlement.

Balance sheet

Intangible assets increased during the period to $18.2m (2022: $16.5m). Additions for the year related to Blocks 125 & 126 in Vietnam $3.1m (2022: $3.1m), Egypt $8.0m (2022: $1.0m) and $nil (2022: $0.2m) for the Israeli bid round licence fee. The first exploration well on NBS (NBS-SW1X) was declared a commercial discovery in December 2023 and exploration costs of $2.9m (2022: $nil) relating to the development lease were transferred to property, plant and equipment. There were total Exploration and evaluation expenditure impairment charges of $6.5m in the year (2022: $0.2m).

The movements in the Property, Plant and Equipment asset class are shown above.

Impairment (charges)/reversals

As a result of previously recognised impairment losses, combined with the ongoing oil price volatility, economic uncertainty leading to high inflation globally and discount rates, and movements in 2P reserves, we have tested each of our oil and gas producing properties for impairment. The results of these impairment tests are summarised below. For each producing property, the recoverable amount has been determined using the value in use method. The recoverable amount is calculated using a discounted cash flow valuation of the 2P production profile.

Summary of Impairments - Oil and Gas properties	TGT $m	CNV $m	El Fayum $m	NBS $m	Total $m
2023
Pre-tax impairment (charge)/credit	(46.3)	0.3	(11.0)	(1.9)	(58.9)
Deferred tax credit/(charge)	16.5	(0.3)	-	-	16.2
Post-tax impairment charge	(29.8)	-	(11.0)	(1.9)	(42.7)

Reconciliation of carrying amount:
As at 1 January 2023	242.4	76.4	62.5	-	381.3
Additions	1.3	3.0	7.6	-	11.9
Transfer from intangible assets	-	-	-	2.9	2.9
Changes in decommissioning asset ¹	-	(2.5)	-	-	(2.5)
DD&A	(38.8)	(12.2)	(4.4)	-	(55.4)
Impairment (charge)/reversal	(46.3)	0.3	(11.0)	(1.9)	(58.9)
As at 31 December 2023	158.6	65.0	54.7	1.0	279.3

	TGT $m	CNV $m	El Fayum $m	NBS $m	Total $m
2022
Pre-tax impairment reversal	19.7	3.6	3.8	-	27.1
Deferred tax charge	(6.9)	(1.4)	-	-	(8.3)
Post-tax impairment reversal	12.8	2.2	3.8	-	18.8

Reconciliation of carrying amount:
As at 1 January 2022	266.0	84.2	49.2	-	399.4
Additions	7.0	3.2	13.6	-	23.8
Changes in decommissioning asset ¹	(11.1)	(2.8)	-	-	(13.9)
DD&A	(39.2)	(11.8)	(4.1)	-	(55.1)
Impairment reversal	19.7	3.6	3.8	-	27.1
As at 31 December 2022	242.4	76.4	62.5	-	381.3

¹ Changes in decommissioning asset for TGT is due to a change in discount rate only, whereas CNV reflects the change in field abandonment plan and discount rate (2022: change in discount rate and the field abandonment plan for TGT; change in discount rate only for CNV)

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.

Oil inventory was $3.3m at 31 December 2023 (2022: $7.2m), of which $3.1m related to Vietnam and $0.2m to Egypt. Trade and other receivables increased to $62.3m (2022: $60.9m) of which $19.0m (2022: $11.4m) relates to Vietnam and $42.7m (2022: $49.0m) relates to Egypt. For Egypt, the closing balance includes $4.9m of carry (2022: $20.9m), which reflects the remaining disproportionate funding contribution from IPR to compensate for net cash flows since the economic date of the farm down transaction, 1 July 2020, and the completion date of 21 March 2022. The carry decreases every month by the cash calls received from IPR. In addition, Egypt trade receivables include $33.4m from EGPC, after expected credit loss provision of $4.0m recognised under IFRS 9, where collection has been delayed by the devaluation of EGP and ongoing restrictions on outgoing USD transfers by the Central Bank of Egypt previously highlighted (2022: trade receivable from Egypt $22.4m after risk factor provision of $1.8m).

Cash and cash equivalents at the end of the year were $32.6m (2022: $45.3m) and the decrease was mainly driven by $35.0m net repayment of borrowings (2022: $10.4m) and cash flows from operating activities of $45.3m (2022: $53.4m) as a result of reduced commodity prices during the year and lower production.

Trade and other payables were marginally higher at $14.2m (2022: $14.0m), of which $7.9m (2022: $6.6m) relates to Egypt net JV payables in relation to operations and Stratton royalty obligation. $2.2m (2022: $4.8m) relates to Vietnam payables, $nil (2022: $0.5m) net hedging liability and $4.1m (2021: $1.9m) Head Office payables, inclusive of $1.7m interim dividend paid in January 2024. Tax payables increased to $5.8m (2022: $5.2m) which is linked to the timing of cargoes from TGT.

Borrowings were $40.5m (2022: $74.2m), a decrease of $33.7m with $35.0m related to repayments following the RBL redeterminations in June and December, partially offset by $1.3m amortisation of capitalised borrowing costs and one-off charges in relation to the redeterminations. The movement on the NBE revolving credit facility was $nil for the year, so the balance on the facility as at 31 December 2023 remained consistent at $9.2m (2022: $9.2m).

Long-term provisions comprise the Group's decommissioning obligations for the Vietnam fields. The decommissioning provision decreased from $54.3m at 2022 year end to $53.8m at 31 December 2023 mainly due to a lower CNV obligation following finalisation of the revised abandonment plan in April 2023 and an increase in discount rate from 3.83% to 3.87% as a result of an increase in prevailing risk-free market rates. The amounts set aside into the abandonment funds total $53.7m (2022: $50.2m). No decommissioning obligation exists under the El Fayum Concession.

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 2023, the trust held 2,126,857 (2022: 2,126,857), representing 0.49% (2022: 0.48%) of the issued share capital.

In addition, as at 31 December 2023, the Company held 9,122,268 (2022: 9,122,268) treasury shares, representing 2.11% (2022: 2.06%) of the issued share capital. All shares purchased under the on-market buyback programme originally announced in July 2022 and extended in January 2023 and December 2023 have been or will be cancelled rather than retained in treasury.

Share buyback and dividend framework

Following a period of improved 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. The Company announced the continuation of a further $3m share buyback programme in January 2023 (the First Programme Extension), of which $2.8m had been incurred by the end of December 2023. On 6 December 2023, the Company announced that it intended to continue the share buyback programme in 2024 through its commitment of a further $3m (excluding stamp duty and expenses). This further extension of the programme commenced following completion of the First Programme Extension in early 2024.

In September 2022, we announced a clear sustainable policy for the recommencement of regular dividend payments. This policy is to return no less than 10% of 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.

A final dividend of 1.00 pence per share, $5.6m equivalent, was recommended by the Board in respect of the year ended 31 December 2022. This was approved by shareholders at the Company's 2023 AGM in May and paid in full on 12 July 2023 to shareholders on the register at the close of business on 16 June 2023. No interim dividend was paid in respect of the year ended 31 December 2022. On 6 December 2023, an interim dividend of 0.33 pence per share, $1.7m equivalent, was declared by the Board in respect of the year ended 31 December 2023 and paid on 24 January 2024 to shareholders on the register at the close of business on 22 December 2023.

The Board have recommended a final dividend in respect of the year ended 31 December 2023 of 0.77 pence per share subject to approval of the shareholders at the Company's 2024 AGM. Subject to this approval, the final dividend will be paid in full on 19 July 2024 in Pounds Sterling to ordinary shareholders on the register at the close of business on 14 June 2024, with an ex-dividend date of 13 June 2024. This would take the 2023 full year dividend to 1.10 pence per share, an increase of 10% on the 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 that utilises oil prices of $81.5/bbl in 2024 and $79/bbl in 2025. The key assumptions and related sensitivities include a "Reasonable Worst Case" (RWC) scenario, where the Board has taken into account the risk of an oil price crash broadly similar to what occurred in 2020. It assumes the Brent oil price down by a third to $54.3/bbl in April 2024 and gradually recovers to base price in next 12 months, concurrent with 5% reductions in Vietnam and Egypt production compared to our base case from April 2024. Both the base case and RWC take into account effect of hedging that has already been put in place at 31 December 2023 and subsequent hedges placed in 2024, now covering 28% for the full year 2024 and 12% of 1H 2025. We have therefore secured an average floor price and ceiling price of c. $63.5/bbl and c. $89/bbl, respectively, for the entire hedged volumes. Under the RWC scenario, we have identified appropriate mitigating actions, which could look to defer uncommitted expenditure as required.

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.

Our business in Vietnam remains robust, with a low breakeven oil price. In TGT we have 2 wells planned to be drilled in 2H 2024. The majority of our debt ($30m as of 31 December 2023) is secured against the Vietnam producing assets under the RBL, which will be repaid by July 2025.

In Egypt, we have limited capital expenditure, low cost recompletions and waterflood in El-Fayum and development drilling in NBS in 2H 2024. As of 31 December 2023 $9.2m drawn on an uncommitted revolving credit facility on the Egypt revenue invoices.

On the basis of the forecasts provided above, the Group is expected to have sufficient financial headroom for the 12 months from the date of approval of the 2023 Financial Statements. 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 have a great deal to look forward to as we move forward in 2024 and beyond.

· A strong and stable balance sheet, improved liquidity, improved fiscal terms in Egypt, stable production with a solid USD cash flow from our Vietnam portfolio and a reduced cost base throughout the Group

· Continued development drilling across our portfolio

· Reducing debt and getting to a net cash position early in the year

· Significantly improving economic situation in Egypt, which could start to unlock our receivables position there

Further returns to shareholders are expected in 2024, with the announcement in January of an additional $3m committed to an extension of the Company's ongoing share buyback programme, and a 10% increase in full year dividends subject to approval of the final dividend at the 2024 AGM.

Sue Rivett

Chief Financial Officer

Review of Operations

Vietnam

Vietnam Production in 2023

Production in 2023 from the TGT and CNV fields net to the Group's working interest averaged 5,127 boepd (2022: 5,418 boepd). This is in line with the production guidance for Vietnam announced in January 2023 of 4,700 - 5,700 boepd net.

TGT production averaged 12,341 boepd gross and 3,661 boepd net to the Group (2022: 13,784 boepd gross and 4,089 boepd net). CNV production averaged 5,861 boepd gross and 1,466 boepd net to the Group (2022: 5,317 boepd gross and 1,329 boepd net).

Vietnam Development and Operations in 2023

TGT & CNV Fields

On Block 16-1 - TGT Field, operational activities were focused on adding low-cost production through well intervention and production optimisation opportunities (surface and subsurface) in absence of new wells drilling. The TGT RFDP was approved by MOIT on 9 January 2024.

On Block 9-2 - CNV Field, the field saw strong performance from its first new lateral well, which was delivered on time, under budget, and put on production in 1Q 2023. The CNV RFDP for additional drilling was submitted to partners for approval in 2023, and discussions are ongoing.

The Company has continued to receive positive feedback from Petrovietnam and MOIT on the applications for five-year extensions to the petroleum contracts for the TGT and CNV fields.

Vietnam Exploration in 2023

Blocks 125 & 126

On Blocks 125 & 126, a two-year PSC extension was granted by MOIT on 13 June 2023, extending the first exploration period of the PSC to 8 November 2025. This approval shows the encouraging level of support from the Vietnamese Government and discussions with a number of interested parties to secure a farm-in partner are progressing.

An independent CPR for Block 125 was published on 20 July 2023, confirming a range of gross unrisked prospective oil resources of between 1,178 MMstb (1U) and 29,785 MMstb (3U) with a Mean value of 13,328 MMstb. The report supports the Group's internal assessments and paves the way for further work to develop new leads and mature leads to prospects.

The ongoing interpretation of 3D seismic data has highlighted greater prospectivity in the deeper water section of Block 125. In order to drill one of these deeper water prospects as the commitment exploration well under the current exploration phase of the PSC, a Drillship or Dynamically-Positioned (DP) Semi-Submersible Rig is needed.

2024 Work Programme

TGT & CNV Fields

· Vietnam production guidance for 2024 is 3,900 - 5,000 boepd net.

· Planning is well-advanced for a two-well TGT drilling programme in 2H 2024.

· Continued engagement with partners and regulators to finalise the five-year licence extensions for TGT and CNV.

Blocks 125 & 126

· Ongoing discussions with another operator to secure a well drilling slot during their multi-well drilling programme in the region.

· Progressing parallel discussions with several potential farm-in partners for Blocks 125 & 126. Securing a rig slot will positively impact the farm-out discussions.

Egypt

Egypt Production in 2023

Production for 2023 from the El Fayum Concession averaged 3,069 bopd gross and 1,381 bopd net to the Group. This is in line with the 2023 production guidance announced in January 2023 of 1,350 - 1,800 bopd net.

Egypt Development and Operations in 2023

El Fayum

Three new wells in El Fayum (2 producers and 1 injector) were put on production and injection in 2023, in line with pre-drill expectations.

North Beni Suef

On NBS, the first exploration commitment well (NBS-SW1X) was declared a commercial discovery and put on production in December 2023. A new 20-year development lease for NBS-SW1X was awarded by EGPC in September 2023, opening up a new area for production and development.

Two workover rigs remain on field to contribute to production through low-cost well repairs, recompletions, and deployment of water injection.

Egypt Exploration in 2023

El Fayum exploration

On El Fayum, there was exploration success with the first commitment well in the Abu Roash G and Upper Bahariya formations in July 2023. The well is set up for re-entry and testing in 2024.

North Beni Suef (NBS) exploration

On NBS, all technical commitments of the initial exploration period have been fulfilled with 3D seismic survey acquired on time and on budget in 2H 2023, and the completion of two exploration commitment wells. As noted above, in September 2023, NBS-SW1X was declared a commercial discovery. Production from the well commenced in December 2023, following the grant of the first development lease on the Concession. The second and final exploration commitment well for the first phase of the NBS exploration period (NBS-5X) was drilled in the Abu Roash G formation at a deeper depth and failed to encounter oil-bearing sands. The result of this well does not hinder other mapped prospects in the Concession.

2024 Work Programme

El Fayum & NBS

· Egypt production guidance for 2024 is 1,300 - 1,500 bopd net.

· Continuation of modest and measured approach to capital allocation and drilling in El Fayum and NBS, with potential to ramp up activity this year and beyond in response to the improving economic environment.

· Focus for this year's work programme in El Fayum is low-cost recompletions and waterflood.

· Development drilling in the NBS SW field is planned to start in 2H 2024.

· Processing and interpretation of c.130km² of 3D seismic data on NBS is underway and expected to be completed in 2H 2024.

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. Gross reserves and contingent resources have been independently audited by RISC Advisory Pty Ltd (RISC) for Vietnam and McDaniel & Associates Consultants Ltd. (McDaniel) for Egypt.

Group Reserves Statistics

Net working interest, mmboe	TGT	CNV	Vietnam³	El Fayum	NBS	Egypt⁴	Group
Oil and Gas 2P Commercial Reserves^1,2
As at 1 January 2023	8.8	3.4	12.2	15.0	-	15.0	27.2
Production	(1.3)	(0.5)	(1.8)	(0.5)	-	(0.5)	(2.3)
Revision	(1.2)	(0.1)	(1.3)	(0.9)	-	(0.9)	(2.2)
Discoveries	-	-	-	-	0.8	0.8	0.8
2P Commercial Reserves as at 31 December 2023	6.3	2.8	9.1	13.6	0.8	14.4	23.5

Oil and Gas 2C Contingent Resources^1,2
As at 1 January 2023	7.4	3.4	10.8	8.9	-	8.9	19.7
Revision	(1.1)	2.2	1.1	0.7	-	0.7	1.8
2C Contingent Resources as at 31 December 2023	6.3	5.6	11.9	9.6	-	9.6	21.5

Total of 2P Reserves and 2C Contingent Resources as at 31 December 2023	12.6	8.4	21.0	23.2	0.8	24.0	45.0

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.

3) Reserves and Contingent Resources have been independently audited by RISC.

4) Reserves and Contingent Resources have been independently audited by McDaniel.

Vietnam Reserves and Contingent Resources

In accordance with the requirements of its RBL, the company commissioned RISC to provide an independent audit of gross (100% field) reserves and contingent resources for TGT and CNV as of 31 December 2023.

Vietnam Reserves Statistics

Net working interest, mmboe	TGT	CNV	Vietnam
Oil and Gas 2P Commercial Reserves^1,2,3
As at 1 January 2023	8.8	3.4	12.2
Production	(1.3)	(0.5)	(1.8)
Revision	(1.2)	(0.1)	(1.3)
2P Commercial Reserves as at 31 December 2023	6.3	2.8	9.1

Oil and Gas 2C Contingent Resources^1,2,3
As at 1 January 2023	7.4	3.4	10.8
Revision	(1.1)	2.2	1.1
2C Contingent Resources as at 31 December 2023	6.3	5.6	11.9

Total of 2P Reserves and 2C Contingent Resources as at 31 December 2023	12.6	8.4	21.0

1) Reserves and Contingent Resources are categorised in line with 2018 SPE/WPC/AAPG/SPEE /SWLA Petroleum Resource Management System.

2) Assumes oil equivalent conversion factor of 6,000 scf/boe.

3) Reserves and Contingent Resources have been independently audited by RISC.

On TGT, 2P reserves were revised downwards due to a 9-month delay in drilling of the two infill wells, lower expected benefit from well activities as the field becomes more mature and a slow production ramp-up following the annual maintenance shutdown in the last quarter of the year. 2C contingent resources were revised accordingly.

On CNV, the 2P reserves were largely in line with the previous year. 2C contingent resources were revised upwards due to the inclusion of one additional lateral side-track well.

In Vietnam, the Group has applied for an extension to the petroleum contracts for the TGT and CNV fields. We expect changes to the discovered resources upon receiving approval from the government.

Egypt Reserves and Contingent Resources

Egypt Reserves Statistics

Net working interest, mmboe	El Fayum	NBS	Egypt
Oil and Gas 2P Commercial Reserves^1,2
As at 1 January 2023	15.0	-	15.0
Production	(0.5)	-	(0.5)
Revision	(0.9)	-	(0.9)
Discoveries	-	0.8	0.8
2P Commercial Reserves as at 31 December 2023	13.6	0.8	14.4

Oil and Gas 2C Contingent Resources^1,2
As at 1 January 2023	8.9	-	8.9
Revision	0.7	-	0.7
2C Contingent Resources as at 31 December 2023	9.6	-	9.6

Total of 2P Reserves and 2C Contingent Resources as at 31 December 2023	23.2	0.8	24.0

1) Reserves and Contingent Resources are categorised in line with 2018 SPE/WPC/AAPG/SPEE /SWLA Petroleum Resource Management System.

2) Reserves and Contingent Resources have been independently audited by McDaniel.

On El Fayum, the delay in the execution of the field development plan have resulted in a downward revision of the 2P reserves, pushing some volumes into the contingent resources category.

North Beni Suef is included in the reserves assessment for the first time, following a successful exploration well and granting of the Development Lease. Initial reserves are granted based on a limited development of two producer wells offset to the discovery well. The full development programme will be incorporated following the interpretation of the new 3D seismic acquired during 2023.

Group's Net Working Interest Reserves and Contingent Resources

TGT Field at 31 December 2023 (mmboe) (net to Group's working interest)

Reserves²	1P	2P	3P
Oil	4.8	5.9	7.1
Gas¹	0.2	0.4	0.6
Total	5.0	6.3	7.7

Contingent Resources²	1C	2C	3C
Oil	3.3	6.1	9.0
Gas¹	0.1	0.2	0.4
Total	3.4	6.3	9.4

Sum of Reserves and Contingent Resources³	1P & 1C	2P & 2C	3P & 3C
Oil	8.1	12.0	16.1
Gas¹	0.3	0.6	1.0
Total	8.4	12.6	17.1

1) Assumes oil equivalent conversion factor of 6,000 standard cubic feet per barrel of oil equivalent.

2) Reserves and Contingent Resources have been audited independently by RISC.

3) The summation of Reserves and Contingent Resources has been prepared by the Company.

CNV Field at 31 December 2023 (mmboe) (net to Group's working interest)

Reserves²	1P	2P	3P
Oil	1.3	1.7	2.1
Gas¹	0.8	1.1	1.3
Total	2.1	2.8	3.4

Contingent Resources²	1C	2C	3C
Oil	1.8	3.5	5.2
Gas¹	1.1	2.1	3.2
Total	2.9	5.6	8.4

Sum of Reserves and Contingent Resources³	1P & 1C	2P & 2C	3P & 3C
Oil	3.1	5.2	7.3
Gas¹	1.9	3.2	4.5
Total	5.0	8.4	11.8

1) Assumes oil equivalent conversion factor of 6,000 standard cubic feet per barrel of oil equivalent.

2) Reserves and Contingent Resources have been audited independently by RISC.

3) The summation of Reserves and Contingent Resources has been prepared by the Company.

El Fayum Concession at 31 December 2023 (mmboe) (net to Group's working interest)

Reserves¹	1P	2P	3P
Oil	6.8	13.6	17.9

Contingent Resources¹	1C	2C	3C
Oil	3.6	9.6	19.2

Sum of Reserves and Contingent Resources²	1P & 1C	2P & 2C	3P & 3C
Total	10.4	23.2	37.1

1) Reserves and Contingent Resources have been audited independently by McDaniel.

2) The summation of Reserves and Contingent Resources has been prepared by the Company.

North Beni Suef Concession at 31 December 2023 (mmboe) (net to Group's working interest)

Reserves¹	1P	2P	3P
Oil	0.2	0.8	0.9

Contingent Resources¹	1C	2C	3C
Oil	-	-	-

Sum of Reserves and Contingent Resources²	1P & 1C	2P & 2C	3P & 3C
Total	0.2	0.8	0.9

1) Reserves and Contingent Resources have been audited independently by McDaniel.

2) The summation of Reserves and Contingent Resources has been prepared by the Company.

Condensed consolidated income statement
for the year to 31 December 2023
		2023	2022
	Notes	$ million	$ million
Continuing operations
Revenue	3	167.9	199.1
Cost of sales	4	(111.2)	(116.8)
Gross profit		56.7	82.3

Administrative expenses		(9.0)	(10.0)
Pre-licence costs		(0.4)	-
Impairment (charge)/reversal - Intangibles assets	3, 9	(6.5)	0.8
Impairment (charge)/reversal - Property, plant and equipment	3, 10	(58.9)	27.1

Operating (loss)/profit		(18.1)	100.2

Other/restructuring expense	5	(0.6)	(0.8)
Loss on disposal	14	-	(6.6)
(Loss)/gain on fair value movement of financial asset	14	(0.3)	0.3
Investment revenue		0.2	0.2
Finance costs	6	(10.2)	(12.7)
(Loss)/profit before tax	3	(29.0)	80.6
Income tax charge	7	(19.8)	(56.2)
(Loss)/profit for the year		(48.8)	24.4

(Loss)/profit per share (cents)	8
Basic		(11.4)	5.6
Diluted		(11.4)	5.4


Condensed consolidated statement of comprehensive income
for the year to 31 December 2023
		2023	2022
		$ million	$ million

(Loss)/Profit for the year		(48.8)	24.4
Items that may be subsequently reclassified to profit or loss:
Fair value gain/(loss) arising on hedging instruments during the year		0.6	(18.9)
Less: Loss arising on hedging Instruments reclassified to profit or loss 11		0.2	22.5
Total comprehensive (loss)/income for the year		(48.0)	28.0

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
		2023	2022	2023	2022
	Notes	$ million	$ million	$ million	$ million
Non-current assets
Intangible assets	9	18.2	16.5	-	-
Property, plant and equipment	10	279.3	381.0	-	-
Right-of-use assets		0.5	0.8	-	-
Investments		-	-	294.3	335.5
Loan to subsidiaries		-	-	16.8	23.0
Other assets		58.6	59.1	-	-

		356.6	457.4	311.1	358.5

Current assets
Inventories		3.3	7.2	-	-
Trade and other receivables		62.3	60.9	0.4	0.4
Tax receivables		2.2	2.1	0.2	0.1
Cash and cash equivalents		32.6	45.3	1.7	8.8


		100.4	115.5	2.3	9.3

Total assets		457.0	572.9	313.4	367.8

Current liabilities
Trade and other payables		(14.2)	(14.0)	(4.0)	(1.9)
Borrowings		(29.5)	(39.6)	-	-
Lease Liabilities		(0.3)	(0.3)	-	-
Tax payables		(5.8)	(5.2)	(0.9)	(1.2)

		(49.8)	(59.1)	(4.9)	(3.1)

Non-current liabilities
Other payables		(0.5)	(0.9)	-	-
Deferred tax liabilities		(68.2)	(92.9)	-	-
Borrowings		(11.0)	(34.6)	-	-
Lease liabilities		(0.2)	(0.5)	-	-
Long term provisions		(53.8)	(54.3)	-	-

		(133.7)	(183.2)	-	-

Total liabilities		(183.5)	(242.3)	(4.9)	(3.1)
Net assets		273.5	330.6	308.5	364.7

Equity
Share capital		33.7	34.3	33.7	34.3
Share premium		58.0	58.0	58.0	58.0
Other reserves		255.4	253.6	200.6	199.7
Retained (deficit) / earnings		(73.6)	(15.3)	16.2	72.7
Total equity		273.5	330.6	308.5	364.7

The above condensed consolidated balance sheet should be read in conjunction with the accompanying notes.

CONDENSED consolidated STATEMENT OF CHANGES IN EQUITY

	Group
Notes	Called up share capital $ million	Share premium $ million	Other reserves $ million	Retained earnings /(deficit) $ million	Total $ million
As at 1 January 2022	34.9	58.0	250.5	(39.0)	304.4
Profit for the year	-	-	-	24.4	24.4
Other comprehensive income	-	-	3.6	-	3.6
Share buy back	(0.6)	-	0.6	(2.9)	(2.9)
Treasury shares repurchased	-	-	(0.6)	-	(0.6)
Share-based payments	-	-	1.7	-	1.7
Transfer relating to share-based payments	-	-	(2.2)	2.2	-
As at 1 January 2023	34.3	58.0	253.6	(15.3)	330.6
Loss for the year	-	-	-	(48.8)	(48.8)
Other comprehensive income	-	-	0.8	-	0.8
Share buy back	(0.6)	-	0.6	(2.8)	(2.8)
Share-based payments	-	-	1.0	-	1.0
Distributions to shareholders 12	-	-	-	(7.3)	(7.3)
Transfer relating to share-based payments	-	-	(0.6)	0.6	-
As at 31 December 2023	33.7	58.0	255.4	(73.6)	273.5

	Company
	Called up share capital $ million	Share premium $ million	Other reserves $ million	Retained earnings $ million	Total $ million
As at 1 January 2022	34.9	58.0	202.4	12.6	307.9
Profit for the year	-	-	-	60.7	60.7
Share buy back	(0.6)	-	0.6	(2.9)	(2.9)
Share-based payments	-	-	1.7	-	1.7
Transfer relating to share-based payments	-	-	(5.0)	2.3	(2.7)
As at 1 January 2023	34.3	58.0	199.7	72.7	364.7
Loss for the year	-	-	-	(47.0)	(47.0)
Share buy back	(0.6)	-	0.6	(2.8)	(2.8)
Share-based payments	-	-	1.0	-	1.0
Distributions to shareholders 12	-	-	-	(7.3)	(7.3)
Transfer relating to share-based payments	-	-	(0.7)	0.6	(0.1)
As at 31 December 2023	33.7	58.0	200.6	16.2	308.5

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 2023

			Group		Company
	Notes	2023 $ million	2022 $ million	2023 $ million	2022 $ million
Net cash from (used in) operating activities	13	44.9	53.4	(8.1)	(11.6)
Investing activities
Purchase of intangible assets		(9.7)	(4.4)	-	-
Purchase of property, plant and equipment		(13.5)	(25.4)	-	-
Payment to abandonment fund		(3.5)	(2.1)	-	-
Consideration in relation to farm out of Egyptian assets¹		15.6	18.4	-	-
Contingent consideration received in relation to farm out of Egyptian assets		5.0	-	-	-
Assignment fee in relation to farm out of Egyptian assets		(0.5)	(0.5)	-	-
Dividends received from subsidiary undertakings		-	-	11.4	19.0
Net cash (used in) from investing activities		(6.6)	(14.0)	11.4	19.0

Financing activities
Share based payments		-	(0.4)	-	-
Repayment of borrowings		(44.2)	(27.1)	-	-
Proceeds from borrowings		9.2	16.7	-	-
Interest paid on borrowings		(6.4)	(6.0)	-	-
Lease payments		(0.3)	(0.1)	-	-
Share buy back		(2.8)	(2.9)	(2.8)	(2.9)
Dividends paid to shareholders		(5.6)	-	(5.6)	-
Funding movements with subsidiaries		-	-	(2.1)	(1.0)
Net used in financing activities		(50.1)	(19.8)	(10.5)	(3.9)

Net (decrease)/ increase in cash and cash equivalents		(11.8)	19.6	(7.2)	3.5
Cash and cash equivalents at beginning of year		45.3	27.1	8.8	5.3
Effect of foreign exchange rate changes		(0.9)	(1.4)	0.1	-
Cash and cash equivalents at end of year		32.6	45.3	1.7	8.8

¹ During the year IPR, acting as operator and agent, was authorised to settle its operating liabilities of $3.5m (2022: $6.6m) and investing liabilities of $12.1m (2022: $8.8m) against the consideration due from the associated carry debtor amounting to $15.6m (2022: $15.4m). 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 ensure clarity of disclosure of the operating cash costs of the business.

The above condensed consolidated 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 2023 or 2022, but is derived from those accounts. A copy of the statutory accounts for 2022 has been delivered to the Registrar of Companies and those for 2023 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 the recognition and measurement criteria of international accounting standards in conformity with the requirements of the Companies Act 2006 and International Financial Reporting Standards, as issued by the International Accounting Standard Board (IASB). The financial information has also been prepared in accordance with the recognition and measurement criteria of International Financial Reporting Standards as issued by the IASB.

The financial information has also been prepared on a going concern basis of accounting.

(b) New and amended standards adopted by Pharos

A number of new or amended standards became applicable for the current reporting period.

Amendments to IAS 1 Presentation of Financial Statements and IFRS Practice Statement 2 Making Materiality Judgements- Disclosure of Accounting Policies:

The Group has adopted the amendments to IAS 1 for the first time in the current year.

The amendments change the requirements in IAS 1 with regard to disclosure of accounting policies. The amendments to IAS 1 and IFRS Practice Statement 2 Making Materiality Judgements ('four-step materiality process') provide guidance and examples to help entities apply materiality judgements to accounting policy disclosures.

The amendments replace all instances of the term 'significant accounting policies' with 'material accounting policy information'. Accounting policy information is material if, when considered together with other information included in an entity's financial statements, it can reasonably be expected to influence decisions that the primary users of general purpose financial statements make on the basis of those financial statements. Accounting policy information may be material because of the nature of the related transactions, other events or conditions, even if the amounts are immaterial. However, not all accounting policy information relating to material transactions, other events or conditions is itself material.

The amendments have had an impact on the Group's disclosures of accounting policies, but not on the measurement, recognition or presentation of any items in the Group's financial statements.

The Group did not have to change its accounting policies or make retrospective adjustments as a result of adopting these standards.

- Insurance Contracts - IFRS 17 (including the June 2020 and December 2021 Amendments)

- Definition of Accounting Estimates - Amendments to IAS 8

- Deferred Tax related to Assets and Liabilities arising from a Single Transaction - Amendments to IAS 12

- International Tax Reform - Pillar Two Model Rules - Amendments to IAS 12

Certain new accounting standards and interpretations have been published that are not mandatory for 31 December 2023 year end and have not been early adopted by the Group. These standards are not expected to have a material impact on the Group in the current or future reporting periods nor on foreseeable future transactions.

3. Segment information

The Group has one principal business activity being oil and gas exploration and production. The Group's continuing 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.


				2023
	SE Asia $ million	Egypt $ million	Unallocated $ million	Group $ million
Oil and gas sales	149.2	18.9	-	168.1
Realised loss on commodity hedges	-	-	(0.2)	(0.2)
Total revenue	149.2	18.9	(0.2)	167.9
Depreciation, depletion and amortisation - Oil and gas	(51.0)	(4.4)	-	(55.4)
Depreciation, depletion and amortisation - Other	-	(0.2)	-	(0.2)
Pre-licence costs	-	(0.4)	-	(0.4)
Impairment charge - Intangibles	-	(6.5)	-	(6.5)
Impairment charge - PP&E	(46.0)	(12.9)	-	(58.9)
Loss on fair value movement of financial asset	-	(0.3)	-	(0.3)
Profit/(loss) before tax¹	5.6	(18.4)	(16.2)	(29.0)
Tax charge on operations	(36.0)	-	-	(36.0)
Tax credit on impairment charge	16.2	-	-	16.2


				2022
	SE Asia $ million	Egypt $ million	Unallocated $ million	Group $ million
Oil and gas sales	184.8	36.8	-	221.6
Realised loss on commodity hedges	-	-	(22.5)	(22.5)
Total revenue	184.8	36.8	(22.5)	199.1
Depreciation, depletion and amortisation - Oil and gas	(51.0)	(4.1)	-	(55.1)
Depreciation, depletion and amortisation - Other	-	(0.1)	-	(0.1)
Impairment reversal/(charge) - Intangibles²	1.0	-	(0.2)	0.8
Impairment reversal - PP&E	23.3	3.8	-	27.1
Loss on disposal	-	(6.6)	-	(6.6)
Gain on fair value movement of financial asset	-	0.3	-	0.3
Profit/(loss) before tax¹	108.3	16.9	(44.6)	80.6
Tax charge on operations	(47.9)	-	-	(47.9)
Tax charge on impairment reversal	(8.3)	-	-	(8.3)

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 Includes $1.0m reversal of impairment of Block 125&126 tax receivable (other receivable - current), offset by $(0.2)m write-off of seismic costs relating to Israel exploration Zones A and C.

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 $149.2m and $18.9m which arose from the Group's two largest customers, who contributed more than 10% to the Group's oil and gas revenue (2022: $182.5m and $36.8m in South East Asia and Egypt from the Group's three largest customers).

Geographical information

The Group's oil and gas revenue and non-current assets (excluding other receivables) 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.

	2023 $ million	2022 $ million
Vietnam	149.2	97.1
Egypt	18.9	36.8
China	-	87.7
	168.1	221.6

Non-current assets	2023 $ million	2022 $ million
Vietnam	240.4	332.5
Egypt	57.6	65.8
	298.0	398.3

Excludes other assets.

4. Cost of sales

	2023	2022
	$ million	$ million

Depreciation, depletion and amortisation	55.4	55.1
Production based taxes	10.5	14.7
Export duty	-	3.2
Production operating costs	41.3	45.6
Inventories	4.0	(1.8)
	111.2	116.8

5. Other/restructuring expense

	2023	2022
	$ million	$ million

Redundancy costs	-	0.1
Other	0.6	-
Premium - lease transfer	-	0.7
	0.6	0.8

In 2023, other expenses of $0.6m were due to changes in the best estimate of the adjustment relating to the interim period between the economic date of 1 July 2020 and the completion date of the disposal of 55% interest in the Egypt concessions.

In 2022, $0.7m relates to the transfer of the London office lease to a third party, at which point the Company derecognised the right of use asset and associated lease liability. In 2020, $1.2m was transferred to an escrow account held by a third party (recorded within prepayments). The amount was released to the income statement over 21 months on the condition the new tenant paid the rent to the landlord. In 2022, the remaining balance of $0.7m was released from the escrow account and paid to the new tenant.

6. Finance costs

	2023 $ million	2022 $ million
Unwinding of discount on provisions	2.0	1.3
Interest expense payable and similar fees	6.4	6.0
RBL modification charge and amortisation of capitalised borrowing costs	1.3	4.1
Net foreign exchange losses	0.5	1.3
	10.2	12.7

In 2023, $2.0m relates to the unwinding of discount on the provisions for decommissioning (2022: $1.3m). The provisions are based on the net present value of the Group's share of the expenditure which may 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.

Following the June and December 2023 redeterminations and the $35.0m repayment of principal in relation to the Group's reserve based lending facility, there was a change in estimated future cash flows. As a result, a charge of $2.7m (2022: $2.6m) was recognised in profit and loss, offset by an amortisation adjustment of $(1.4)m (2022: amortised cost of $1.5m).

7. Tax

	2023 $ million	2022 $ million
Current tax charge	44.5	54.5
Deferred tax credit on operations	(8.5)	(6.6)
Deferred tax (credit)/charge on impairment	(16.2)	8.3
Total tax charge	19.8	56.2

The Group's corporation tax is calculated at 50% (2022: 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. During 2023 and 2022, both current and deferred taxation have arisen in overseas jurisdictions only.

The charge for the year can be reconciled to the (loss)/profit per the income statement as follows:

	2023 $ million	2022 $ million
(Loss)/ Profit before tax	(29.0)	80.6
(Loss)/ Profit before tax at 50% (2022: 50%)	(14.5)	40.3

Effects of:
Non-taxable income	-	(3.3)
Non-deductible expenses	18.0	5.6
Tax losses not recognised	16.5	13.8
Adjustments to tax charge in respect of previous periods	(0.2)	(0.2)
Tax charge for the year	19.8	56.2

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 2022, non-taxable income relates to Vietnam impairment reversal of $(3.3)m. Non-deductible expenses primarily relate to Vietnam impairment charges of $6.8m and Vietnam DD&A charges for costs previously capitalised, which are non-deductible for Vietnamese tax purposes of $10.4m (2022: $5.6m). A further $0.8m (2022: $nil) relates to non-deductible corporate costs including share scheme incentives.

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 our local subsidiary Pharos El Fayum (PEF). The Group records a tax charge, with a corresponding increase in revenues, for the tax paid by EGPC on its behalf. However, this is only valid if PEF is in a historic profit making position and no such tax has been recorded this year.

The effect from tax losses not recognised relates to costs, primarily of the Company, deductible for tax in the UK but not expected to be utilised in the foreseeable future. For 2023, it also includes losses arising in Egypt for which no future benefit can be obtained under the terms of the concession agreement. During 2022, Egypt concessions recorded a net profit before tax of $16.9m (profit after tax impact of $8.5m) which has been offset against tax losses not recognised, as Egypt is in a historic loss making position. The group did not recognise deferred tax assets in relation to historical tax losses available to offset future taxable profits of $18m on the basis that there will be no future benefits arising from these losses as any taxes in the future will be paid by EGPC on behalf of the group.

8. Earnings per share

The calculation of the basic and diluted earnings per share is based on the following data:

	Group
	2023 $ million	2022 $ million
(Loss) /Gain for the purposes of basic profit/(loss) per share	(48.8)	24.4
Effect of dilutive potential ordinary shares - Cash settled share awards and options	-	(0.3)
(Loss)/ Gain for the purposes of diluted profit/(loss) per share	(48.8)	24.1

	Number of shares (million)
	2023	2022
Weighted average number of ordinary shares	427.2	439.3
Effect of dilutive potential ordinary shares - Share awards and options	-	0.9
Weighted average number of ordinary shares for the purpose of diluted profit/(loss) per share	427.2	440.2

In accordance with IAS 33 "Earnings per Share", the effects of 2.9m antidilutive potential shares have not been included when calculating dilutive earnings per share for the year ended 31 December 2023, as the Group was loss making.

9. Intangible assets

Intangible assets at 2023 year end comprise the Group's exploration and evaluation projects which are pending determination. Included in the additions is Blocks 125 & 126 in Vietnam $3.1m (2022: $3.1m) and Egypt $8.0m (2022: $1.0m), of which $6.7m (2022: $0.9m) relates to North Beni Suef.

At June 2020 and December 2020 an impairment indicator of IFRS 6 was triggered following the Group's decision to defer all non-essential investment in Vietnam and Egypt at this point. No substantive expenditure for its exploration areas in Vietnam and Egypt was either budgeted or planned in the near future. Exploration costs including costs associated with Blocks 125 & 126 in Vietnam of $17.9m and costs associated with Egypt projects in the amount of $5.3m ($2.4m share post-farm out) were written off in the income statement in accordance with the Group's accounting policy on oil and gas exploration and evaluation expenditure.

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. On 20 July 2023, the Company published an independent assessment by ERCE for Block 125, which confirmed a range of gross unrisked prospective oil resources of between 1,178 MMstb (1U) and 29,785 MMstb (3U) with a Mean value of 13,328 MMstb for the Prospects in the North West area of Block 125 currently covered fully or partially by 3D seismic. These resources do not include Leads already identified in Blocks 125 & 126 but not yet covered by 3D seismic. Work is ongoing to progress well planning and discussions are ongoing to secure a partner ahead of drilling the commitment well in 2025. Whilst ongoing costs for exploration are therefore forecast and funds 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 2023 therefore remains at $17.9m (2022: $17.9m).

In Egypt, as part of the planned work programme for 2023, an exploration well was drilled on El Fayum in July 2023. It was the first commitment well in the Abu Roash G and Upper Bahariya formations and the well is set-up for re-entry and testing in 2024. During 2023, as no further substantive exploration or evaluation is planned or budgeted for the El Fayum Batran-1X well drilled in 2021, the asset of $1.6m has been impaired in full.

On NBS, the first exploration commitment well (NBS-SW1X) was declared a commercial discovery in September 2023 and put on production in December 2023. As a result, exploration costs of $2.9m relating to the development lease were reclassified to property, plant and equipment. A further dry-hole well of $0.8m (NBS-SW5X) was impaired in full, leaving $4.1m (post-2020 impairment charge of $1.2m) in exploration and evaluation expenditure. No substantive expenditure is budgeted or planned in the future in relation to the NBS exploration acreage and the remaining balance of $4.1m has been fully impaired.

The accumulated impairment charges against Egypt exploration and evaluation expenditure at 31 December 2023 stands at $8.9m (2022: $2.4m).

10. Property, plant and equipment

Summary of Impairments - Oil and Gas Properties					2023
2023	TGT $ million	CNV $ million	El Fayum $ million	NBS $ million	Total $ million
Pre-tax impairment (charge)/credit	(46.3)	0.3	(11.0)	(1.9)	(58.9)
Deferred tax credit/(charge)	16.5	(0.3)	-	-	16.2
Post-tax impairment charge	(29.8)	-	(11.0)	(1.9)	(42.7)

Reconciliation of carrying amount:
As at 1 January 2023	242.4	76.4	62.5	-	381.3
Additions	1.3	3.0	7.6	-	11.9
Transfer from intangible assets	-	-	-	2.9	2.9
Changes in decommissioning asset ¹	-	(2.5)	-	-	(2.5)
DD&A	(38.8)	(12.2)	(4.4)	-	(55.4)
Impairment (charge)/reversal	(46.3)	0.3	(11.0)	(1.9)	(58.9)
As at 31 December 2023	158.6	65.0	54.7	1.0	279.3

					2022
2022	TGT $ million	CNV $ million	El Fayum $ million	NBS $ million	Total $ million
Pre-tax impairment reversal	19.7	3.6	3.8	-	27.1
Deferred tax charge	(6.9)	(1.4)	-	-	(8.3)
Post-tax impairment reversal	12.8	2.2	3.8	-	18.8

Reconciliation of carrying amount:
As at 1 January 2022	266.0	84.2	49.2	-	399.4
Additions	7.0	3.2	13.6	-	23.8
Changes in decommissioning asset¹	(11.1)	(2.8)	-	-	(13.9)
DD&A	(39.2)	(11.8)	(4.1)	-	(55.1)
Impairment reversal	19.7	3.6	3.8	-	27.1
As at 31 December 2022	242.4	76.4	62.5	-	381.3

¹ Changes in decommissioning asset for CNV is due to revision of field abandonment plan and discount rate, whereas TGT reflects an immaterial change in discount rate only (2022: Changes in decommissioning asset for TGT is due to changes in discount rate and the field abandonment plan, whereas CNV reflects the change in discount rate only).

Vietnam

The key assumptions to which the recoverable amount is most sensitive are oil price, discount rate and 2P reserves (2022: oil price, discount rate and 2P reserves). In 2023, for TGT, there was a downwards technical revision of 2P reserves and the production profile compared to prior year. For CNV, there was upwards revision of the production profile following strong performance from the new lateral well. As at 31 December 2023, the fair value of the assets are estimated based on a post-tax nominal discount rate of 12.6% (2022: 13.3%) and a Brent oil price of $81.5/bbl in 2024, $79.0/bbl in 2025, $79.2/bbl in 2026, $76.3/bbl in 2027 plus inflation of 2.0% thereafter (2022: an oil price of $88.3/bbl in 2023, $84.8/bbl in 2024, $79.4/bbl in 2025, $74.5/bbl in 2026 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 impairments charge (compared to new NBV) of $15.1m on TGT and $3.1m on CNV. A 1% increase in discount rate would result in post-tax impairments of $2.4m on TGT and $0.8m on CNV.

We have also run sensitivities 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; $81.5/bbl in 2024, $79.0/bbl in 2025, $79.2/bbl in 2026, $72.2/bbl in 2027, $64.8/bbl in 2028, $57.2/bbl in 2029, $49.2/bbl in 2030 and $49.2/bbl in 2031. Using these prices and a 12.6% discount rate would result in additional post-tax impairments of $10.3m on TGT and $4.0m on CNV.

The impairment tests for TGT and CNV assume that production ceases in 2029 and 2030 respectively, assuming the licences are extended by at least three years reflecting past practice and a commercial assessment (and consistent with the reserves estimates independently audited by RISC Advisory Pty Ltd.) that it is highly probable given the economic circumstances and current discussions. The current negotiations over terms are for a longer duration than that assumed and would be expected to improve the value in use calculated.

Egypt

The key assumptions to which the recoverable amount is most sensitive are oil price, discount rate, capital spend and 2P reserves (2022: oil price, discount rate, capital spend and 2P reserves). In 2023, there was a downwards technical revision of El Fayum 2P reserves and production profile compared to prior year and NBS 2P reserves were recognised for the first time following commencement of production in December 2023. As at 31 December 2023, the fair value of the assets are estimated based on a post-tax nominal discount rate of 18.0% (2022: 15.9%) and a Brent oil price of $81.5/bbl in 2024, $79.0/bbl in 2025, $79.2/bbl in 2026, $76.3/bbl in 2027 plus inflation of 2.0% thereafter (2022: an oil price of $88.3/bbl in 2023, $84.8/bbl in 2024, $79.4/bbl in 2025, $74.5/bbl in 2026 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 impairment charges (compared to new NBV) of $7.1m for El Fayum and $0.9m for NBS. A 1% increase in discount rate would result in impairment charges of $2.1m on El Fayum and $0.1m on NBS. We have also run a sensitivity using 18.0% discount rate and the Net Zero price scenario which would result in an additional impairment of $23.5m on El Fayum and $1.0m on NBS.

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 2023, Pharos entered into zero cost collar hedges to protect the Brent component of forecast oil sales and to ensure future compliance with its obligations under the RBL over the producing assets in Vietnam.

The commodity hedges run until June 2025 and are settled monthly. For 2023, 36% of the Group's total production was hedged, securing average floor and ceiling prices for the hedged volumes at $64.5/bbl and $100.8/bbl, respectively. The Group's RBL requires the Company to hedge at least 35% of Vietnam RBL production volumes and the current hedging programme meets this requirement through to December 2024, leaving 72% of Group production unhedged as at 31 December 2023 (2022: 30% of the Group's total production was hedged, securing a minimum price for these hedged volumes of $67.9 per barrel).

A summary of hedges outstanding as at 31 December 2023 is presented below, which are all zero cost collar.

	1Q24	2Q24	3Q24	4Q24	1Q25	2Q25
Production hedge per quarter - 000/bbls	120	120	150	120	60	60
Min. Average value of hedge - $/bbl	63.00	63.00	64.40	63.00	64.00	64.00
Max. Average value of hedge - $/bbl	91.50	87.88	88.66	89.00	90.00	90.00

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 2023, a loss of $0.2m was realised (2022: loss of $22.5m). The outstanding unrealised gain on open position as at 31 December 2023 amounts to $0.1m (2022: loss of $0.7m).

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 receivable position as of December 2023 was $0.1m (2022: liability position $1.1m).

12. Distribution to Shareholders


Amounts recognised as distributions to equity holders in the year:	2023 $ million	2022 $ million
Final dividend for the year ended 31 December 2022 of 1.00 pence per share, paid in the year	5.6	-
Interim dividend for the year ended 31 December of 2023 of 0.33 pence per share, declared in year	1.7	-
	7.3	-

Proposed final dividend for the year ended 31 December 2023 of 0.77 pence per share	4.2	-

The proposed final dividend for the year ended 31 December 2023 of 0.77 pence per share takes the 2023 full-year dividend to 1.10 pence per share, in excess of the minimum 10% of Operating Cash Flow (OCF) per the Company's dividend policy.

The final dividend of 1.00 pence per ordinary share in respect of the year ended 31 December 2022 ($5.6m) was paid on 12 July 2023. The interim dividend of 0.33 pence per ordinary share was paid on 24 January 2024. The proposed final dividend of 0.77 pence per ordinary share in respect of the year ended 31 December 2023, subject to approval of shareholders at the Company's 2024 AGM in May, is payable on 19 July 2024 to all shareholders on the register at the close of business on 14 June 2024.

13. Reconciliation of operating profit/(loss) to operating cash flows

		Group		Company
	2023 $ million	2022 $ million	2023 $ million	2022 $ million
Operating (loss)/profit	(18.1)	100.2	(58.6)	44.2
Share-based payments	0.9	1.3	0.9	1.3
Depletion, depreciation and amortisation	55.6	55.2	-	-
Impairment charge/(reversal)	65.4	(27.9)	49.4	(53.9)
Operating cash flows before movements in working capital	103.8	128.8	(8.3)	(8.4)

Decrease/(increase) in inventories	3.9	(0.9)	-	-
(Increase)/decrease in receivables ¹	(19.1)	(7.7)	(0.2)	1.2
Increase/(decrease) in payables	0.2	(9.5)	0.1	(1.8)
Cash generated by (used in) operations	88.8	110.7	(8.4)	(9.0)

Interest received	0.4	0.1	0.3	0.1
Other/restructuring expense outflow	-	(2.7)	-	(2.7)
Income taxes paid	(44.3)	(54.7)	-	-
Net cash from (used in) operating activities	44.9	53.4	(8.1)	(11.6)

¹ Includes $2.2m (2022: $1.5m) increase in risk factor provision in respect of Egypt trade receivables.

During the year a total of $3.2m of trade receivables due from EGPC in Egypt were settled by way of non-cash offset, out of which $2.2m relates to a second instalment of assignment bonus due to EGPC in relation to the IPR Farm out, $0.5m relates to a bonus due to EGPC for the NBS development lease and $0.5m relates to training bonuses and fees paid to EGPC for participation in a bid round process.

During 2022, a total of $4.6m of trade receivables due from EGPC in Egypt were settled by way of non-cash offset, out of which $1.0m relates to 3rd Amendment signature bonus, $1.1m was set against trade payables, $2.0m Assignment bonus settled on behalf of the Farm out partner, IPR, and $0.5m Group's share of NBS Concession assignment bonus.

14. Disposal of 55% interest in Egypt Concessions and fair value movement

Following the completion of the farm-out transaction of Egyptian assets to IPR, the accounting for the assets reflect the following:

The economic date of the transaction was 1 July 2020, with completion on 21 March 2022.

Pharos owned and managed the business up to completion. On completion, an adjustment to compensate for net cash flows since the economic date has been adjusted for in the level of carry to be provided by IPR to Pharos.

In the financial statements, for the period post completion, Pharos 45% share of field costs - capex, opex and G&A - are accounted for as incurred by Pharos, although all such costs are paid by IPR and set off against the carry.

All revenues earned are paid direct to Pharos.

The firm consideration was received in two tranches, $2.0m in September 2021 and $3.0m on 30 March 2022.

The carry of $35.9m is disproportionate funding contribution from IPR adjusted for working capital and interim period adjustments from the effective economic date of 1 July 2020 and completion date.

Disposal of asset held for sale:

	2022 $ million
Intangible assets	(2.3)
Property, plant and equipment	(54.4)
Inventories	(5.9)
Trade and other receivables	(2.3)
Trade and other payables	8.3
Disposal of 55% of El Fayum and NBS	(56.6)

Firm consideration received - IPR Cash Receipts	5.0
Other receivable - Carry	36.3
Other receivable - contingent consideration	13.6
Other receivable with IPR	0.5
Consideration received and to be received	55.4
Assignment fees payable to EGPC	(3.7)
Success fees paid on completion	(1.7)
Loss on disposal	(6.6)

$0.4m reduction in the amount classified as the carry element from $36.3m to $35.9m following a change in the best estimate of the adjustment relating to the interim period between the economic date of 1 July 2020 and the completion date was charged to the income statement as part of "Other/restructuring expense" during 2023.

The fair value movement of $0.3m was charged to the income statement during 2023. This is due to $0.4m revision of the contingent consideration, partially offset by $0.1m reduction in contingent liability (assignment fee). The fair value movement of $0.3m relating to revision of the contingent consideration and credited to the income statement during 2022 was reclassified from "Loss on disposal" to "(Loss)/Gain on fair value movement of financial asset" to be consistent with 2023 presentation.

15. Subsequent events

EGPC Trade Receivables

On 26 March 2024, following announcements from the Egyptian government of increased liquidity in-country, the Group received notification from EGPC that $10m will be paid as partial settlement of outstanding trade receivables following payment delays through 2023. The funds will clear on 27 March 2024, according to the swift confirmation received.

16. 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 2024 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, gearing, free cash flow and operating cash per share.
For the RBL covenant compliance, three Non-IFRS measures are included: Net debt, EBITDAX and Net debt/EBITDAX.

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 is 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.

	2023	2022
	$ million	$ million

Cost of sales	111.2	116.8
Less:
Depreciation, depletion and amortisation	(55.4)	(55.1)
Production based taxes	(10.5)	(14.7)
Export duty	-	(3.2)
Inventories	(4.0)	1.8
Trade receivable risk factor provision	(2.2)	(1.5)
Other cost of sales	(1.8)	(1.3)
Cash operating costs	37.3	42.8
Production (BOEPD)	6,508	7,166
Cash operating cost per BOE ($)	15.70	16.36

Cash-operating costs per barrel by Segment (2023)

		Vietnam		Egypt		Total
		$ million		$ million		$ million

Cost of sales		95.6		15.6		111.2
	Less: Depreciation, depletion and amortisation	(51.0)	(4.4)		(55.4)
	Production based taxes	(10.4)	(0.1)		(10.5)
	Inventories	(3.9)	(0.1)		(4.0)
	Trade receivable risk factor provision	-	(2.2)		(2.2)
	Other cost of sales	(1.5)	(0.3)		(1.8)

Cash operating costs		28.8		8.5		37.3
Production (BOEPD)		5,127		1,381		6,508
Cash operating cost per BOE ($)		15.39		16.86		15.70

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.

	2023	2022
	$ million	$ million
Depreciation, depletion and amortisation	(55.4)	(55.1)
Production (BOEPD)	6,508	7,166
DD&A per BOE ($)	23.32	21.07

DD&A per barrel by segment (2023)

	Vietnam	Egypt	Total
	$ million	$ million	$ million
Depreciation, depletion and amortisation	(51.0)	(4.4)	(55.4)
Production (BOEPD)	5,127	1,381	6,508
DD&A per BOE ($)	27.25	8.73	23.32

Net Debt

Net debt comprises interest-bearing bank loans, less cash and cash equivalents.

	2023		2022
	$ million		$ million
Cash and cash equivalents		32.6	45.3
Borrowings ¹	(39.2)		(74.2)
Net Debt	(6.6)		(28.9)

¹ Excludes unamortised capitalised set up costs

EBITDAX

EBITDAX is earnings from continuing activities before interest, tax, DD&A, impairment charge/(reversal) of PP&E and intangibles, exploration expenditure including pre-licence costs and Other/restructuring expense items in the current year.

	2023		2022
	$ million		$ million
Operating (loss)/profit		(18.1)	100.2
Depreciation, depletion and amortisation		55.6	55.2
Pre-licence costs		0.4	-
Impairment charge/(reversal)		65.4	(27.9)
EBITDAX	103.3		127.5

Net debt/EBITDAX

Net Debt/EBITDAX ratio expresses how many years it would take to repay the debt, if net debt and EBITDAX stay constant.

	2023		2022
	$ million		$ million
Net Debt		(6.6)	(28.9)
EBITDAX		103.3	127.5
Net Debt/EBITDAX	(0.06)		(0.23)

Gearing

Debt to equity ratio is calculated by dividing interest-bearing bank loans by stockholder equity. The debt to equity ratio expresses the relationship between external equity (liabilities) and internal equity (stockholder equity).

	2023		2022
	$ million		$ million
Total Debt ¹		39.2	74.2
Total Equity		273.5	330.6
Debt to Equity	0.14		0.22

¹ Excludes unamortised capitalised set up costs

Free cash flow

Free cash flow is calculated by subtracting capital cash expenditure from net cash from operating activities.

	2023		2022
	$ million		$ million
Net cash from operating activities		44.9	53.4
Capital cash expenditure		(26.7)	(31.9)
Free cash flow	18.2		21.5

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.

	2023		2022
	$ million		$ million
Net cash from operating activities		44.9	53.4
Weighted number of shares in the year		427,170,044	439,253,641
Operating cash per share	0.11		0.12

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

CPR

Competent person's report or equivalent (e.g. mineral expert's report)

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

ERCE

ERC Equipoise Limited, an independent energy consulting group

Financial Statements

The preliminary financial statements of the Company and the Group for the year ended 31 December 2023

FPSO

Floating, production, storage and offloading Vessel

G&A

General and administration

GHG

Greenhouse gas

Group

Pharos and its direct and indirect subsidiary undertakings

The first half of a calendar year

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

Joint venture

Kilometre

km²

Square kilometre

LTI

Lost Time Injury

LTIP

Long Term Incentive Plan

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

MOIT

The Vietnamese Ministry of Industry and Trade

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

Net Zero Roadmap

The Group's detailed net zero roadmap to achieve net zero GHG emissions by 2050, published in December 2023

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

RFDP

Revised field development plan

RISC

RISC Advisory Pty Ltd

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

United Kingdom

USD, US dollars or $

United States dollars, the lawful currency of the United States of America

UK Pound Sterling

Low estimate scenario of Contingent Resources

Equivalent to proved Reserves; denotes low estimate scenario of Reserves

Low estimate scenario of gross unrisked prospective resources

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

High estimate scenario of Contingent Resources

Equivalent to the sum of proved, probable and possible Reserves; denotes high estimate scenario of Reserves

High estimate scenario of gross unrisked prospective resources

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END

FR UBSNRSVUOURR

TIDM	PHAR
Share Price	29.60p-1.33%
Market Cap	£123.23m

TIDM	PHAR
Share Price	29.60p-1.33%
Market Cap	£123.23m

t

Company Information

RNS Metadata

Company Information

RNS Metadata

2023 Preliminary Results

Date	27 Mar 2024
Time	07:00:12
Category	Results
ID	4838I

Date	27 Mar 2024
Time	07:00:12
Category	Results
ID	4838I