22 March 2023

 

Pharos Energy plc

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

2022 Preliminary Results

Pharos Energy plc, an independent energy company, announces its preliminary results for the year ended 31 December 2022. A conference call will take place at 10.00 GMT today.

 

Jann Brown, Chief Executive Officer, commented:

"2022 was a year of significant change for Pharos. Amidst the macroeconomic challenges and ongoing volatility specifically in Egypt, we delivered crucial milestones that have allowed us to rebuild resilience in the balance sheet, helping us to deliver on our strategy of creating long term, sustainable value for our shareholders via both regular cash returns and organic growth. Pharos is in a much stronger position with the 2023 work programme underway and a focus on sustainable cash generation with capital discipline to deliver returns to our stakeholders.

I would like to thank our global colleagues, investors, government and JV/JOC partners for their continued support and I look forward to updating stakeholders as Pharos works towards a new phase of growth in 2023."

 

2022 Corporate Highlights

·    Enhanced fiscal terms secured in Egypt through the signature of the Third Amendment to the El Fayum Concession in January 2022, increasing Contractor's share of revenue from c.42% to c.50%

·      Completion of farm-out transaction and transfer of operatorship of Egyptian assets to IPR in March 2022, delivering a carry of the Group's remaining 45% interest, expected to continue into Q3 2023

·      Completion of $3m share buyback programme announced in July 2022, with a further $3m committed for 2023

·      Announcement of policy for annual dividend, based on Operating Cash Flow

·     Reshaping of Board structure and composition from 9 to 6 Directors with Jann Brown appointed as Chief Executive Officer in March 2022

·      Commitment to achieve Net Zero GHG emissions from all our assets by no later than 2050 announced in September 2022

·      Establishment of an Emissions Management Fund, under which we will set aside $0.25 for each barrel sold at an oil price above $75/bbl from 2023 to support emissions management projects

2022 Operational Highlights

·     Total Group working interest 2022 production 7,166 boepd net ¹ (2021: 8,878 boepd net, 7,533 boepd net on a comparative basis¹), in line with production guidance;:

-       Vietnam production 5,418 boepd net (2021: 5,560 boepd net)

-       Egypt production 1,748 bopd ¹ net (2021: 3,318 bopd; 1,973 bopd on a comparative basis¹)

·      In Vietnam:

-       Drilling programme for two TGT development wells completed in H2 2022, on time and under budget

-       Drilling of one CNV well started in H2 2022 and completed in Q1 2023, on time and under budget

-       Additional interpretation work on the 3D Seismic in Block 125 is continuing and showing promising results with a number of Prospects identified

·      In Egypt:

-       Commencement of the main El Fayum multi-year and multi-well development programme in Q2 2022 after farm-down

-       Seven wells put on production in 2022, plus one additional well drilled in Q4 2022

-       Rig on a long-term contract secured in July 2022, providing a stable platform for a continuous drilling campaign

-       Request for a short extension on North Beni Suef (NBS) granted in Q4 2022

-       Drilling commenced on the first of two NBS commitment exploration wells in parallel with acquisition of additional 3D seismic

 

2022 Financial Highlights

·      Group revenue of $221.6m^{2 3} (2021: $163.8m^{2 3})

·      Cash generated from operations $110.7m (2021: $51.5m)

·      Operating cash flow $53.4m ⁶ (2021: $10.8m)

·      Cash operating costs of $16.36/bbl⁴ (2021: $16.05/bbl⁴)

·      Cash balances as at 31 December 2022 of $45.3m (2021: $27.1m)

·      Net Debt as at 31 December 2022 of $28.9m^4,5 (2021: $57.5m^4,5)

·      Profit for the year of $24.4m (2021: loss $4.7m)

·      Net Debt to EBITDAX of 0.23x ⁴ (2021: 1.00x⁴)

 

2023 Highlights and Outlook

·      Continuation of share buyback programme announced in January, with a further $3m committed for 2023 so far

·      Dividend payment of 1p per share to be proposed for approval at 2023 AGM

·      Net Zero roadmap to be published in H2 2023

·      Forecast cash capex for 2023 c.$38m (c.$23m after Egyptian carry by IPR)

·      Group working interest 2023 production guidance 6,050 - 7,500 boepd net:

-       Vietnam 2023 production guidance 4,700 - 5,700 boepd net

-       Egypt 2023 production guidance 1,350 - 1,800 bopd net (equivalent to gross production of 3,000 - 4,000 bopd)

·      In Vietnam

-       Work on submitting Revised Field Development Plans (RFDPs) for two wells on TGT and one on CNV is progressing, with all wells remaining in contingent budget until approval

-       Application for extensions to TGT & CNV licences submitted to partners for approval

-       Application for extension to Blocks 125 & 126 licence submitted in December 2022, as no suitable rigs were available for drilling in 2023, and is now with the Prime Minister's office for approval

-       Discussions ongoing with a number of interested parties to secure a farm-in partner before drilling the commitment well on Block 125

·      In Egypt

-       Multi-well development drilling in El Fayum continues in 2023, with nine wells planned for the year

-       Two commitment exploration wells expected to be drilled in the El Fayum Concession

-       Drilling of first commitment exploration well on NBS underway, with the additional commitment exploration well to follow later in the year. An additional extension of the exploration period until September 2023 was granted by EGPC in March 2023

-       Acquisition of the c.110 km2 of additional 3D seismic at NBS has started

 

 

¹ The farm-down transaction and transfer of operatorship of Pharos' Egyptian assets to IPR completed on 21 March 2022. Working interest production for Egypt in 2022 is therefore reported as 100% through to completion and 45% thereafter. The comparative basis for 2021 also assumes 100% working interest until 21 March 2021 and then 45% for the remainder of the year.

² Egyptian revenues are stated post government take including corporate taxes

 

³ Stated prior to realised hedging loss of $22.5m (2021: loss of $29.7m)

 

⁴ See Non-IFRS measures on page 38

 

⁵ Includes RBL and National Bank of Egypt working capital drawdown

 

⁶ Operating cash flow = Net cash from operating activities, as set out in the Cash Flow Statement

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 | Georgia Edmonds | 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 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. IPR Lake Qarun operates and holds the remaining 55% working interest in the NBS Concession. 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, Blocks 125 & 126, located in the moderate to deep water Phu Khanh Basin, north east of the Cuu Long Basin, offshore central Vietnam.

 

Chair's Statement

"A strong culture to deliver sustainable value"

2022 has been an extraordinary year for the energy sector globally. An extended period of volatility has driven pivotal changes for Pharos. The Company's response to the dynamic environment during the year has included the reshaping of its portfolio, balance sheet, Board, and its worldwide organisation.

As a result of strong operational performance, completion of the IPR transaction, securing the improved fiscal terms over El Fayum, and with the support of continuing high oil prices resulting from the easing of pandemic restrictions, Pharos now stands in a much stronger financial position than where we were just a year ago. This has allowed us to commence a share buyback programme, which has continued into 2023, and to announce a new dividend policy focused on making sustainable annual cash returns to shareholders. The last twelve months saw us take key steps in our effort to transform the Company, and I strongly believe that we are now well positioned for a positive and sustainable future, with a robust capital structure and exciting organic opportunities in a refocused portfolio.

Board changes

Underpinned by the financial discipline in our corporate DNA, Pharos has remained relentlessly focused on cost control, starting from the Board and moving throughout the organisation. In 2022, as Non-Executive Chair of the Board, I oversaw the reshaping of the Board from nine to six Directors and salary reductions for myself and both of the two Executives, a decision that is commensurate with the scale of the business and the strategic challenges ahead of us as the Company reframes its portfolio. Following the completion of the farm-down of our assets in Egypt to IPR on 23 March 2022, Jann Brown assumed the role of Chief Executive Officer. On the same date, Ed Story and Dr Mike Watts resigned as Directors of Pharos, with Ed now serving as President of the Group's Vietnam business. Senior Non-Executive Director and Deputy Chair, Rob Gray, also stepped down in May 2022. On behalf of the Board, I would like to thank Ed, Mike and Rob for their long and valued service to the Company as Directors. Going forward, I believe we now have a reshaped Board fit for purpose, which will provide the necessary governance and oversight to support our strategic framework.

Diversity in all forms

Across our entire business, we acknowledge the benefits of diversity in all its dimensions and welcome people with differing backgrounds, skills, and experiences. Our commitment to inclusion and diversity remained strong in 2022. As at year-end, I am pleased to report that the Company has four female Directors, representing two thirds of the Board. We are proud that we are able to recruit talent from diverse backgrounds and ethnicities across our entire organisation.  Most notably, our UK-based staff comprises 16 people from 9 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 people bring, and we will continue to align our Company with that ethos.

People & Culture

I would like to express my gratitude to all our colleagues whose hard work, professionalism and dedication has ensured Pharos' resilience, delivery and efficiency during a challenging year. 2022 saw the departure of many of our longstanding talented Egyptian colleagues following the transfer of operatorship of our Egyptian assets to IPR, but I am delighted that so many of them have found new positions so quickly. The team who have stayed with us have all risen to the challenge, and I am impressed by their commitment to maintain open communication and trust, welcoming constructive changes while adapting to new working practices. They have demonstrated that the culture of our workforce is strong and resilient. It is built on the Group's guiding principles of openness and integrity, safety and care, and mutual trust and respect.

The in-person feedback sessions which I conducted during the year with staff has informed the development of our hybrid working programme in the UK. We no longer maintain a permanent office space in London, with UK-based staff now having access to a modest serviced office space in central London. This arrangement, in addition to significantly reducing costs, provides greater flexibility in how and where employees work.  We have found this approach has contributed positively to both our cost base and our productivity, and we will maintain an active dialogue with our workforce to adapt to changing situations as we go forward and ensure that this remains the case. We have also introduced initiatives to address staff isolation and promote team building by hosting in-person meet-ups throughout the year.  

 

Strategy Day & Stakeholder engagement

In October 2022, the Board held a Strategy Day to focus on where and how we can offer value to our stakeholders. On the day, we had presentations and inputs from a number of key parties, including shareholders. Despite the volatility we have experienced in the global macro-economic environment, our strategy to deliver long-term sustainable value for all our stakeholders through regular cash returns to shareholders and organic growth, remains unchanged. The results of our Strategy Day reinforced our commitment to pursue a combination of growth and cash returns per share, and the resumption of the dividend in a clear policy framework has been particularly appreciated. We are grateful to our shareholders who have been crucial to our growth and transformation throughout the years, and I thank you for your encouragement and patience as we navigate through challenging times and move towards a new phase of growth.

Sustainability

In a year when energy security has been at the top of the agenda for governments worldwide, I firmly believe that oil and gas will continue to play an essential role in the global energy mix for many years to come, and that the importance of producing this energy in a safe, environmentally sustainable and socially responsible way will continue to grow. During my role as Senior Vice President of the World Petroleum Council (WPC), I witnessed the transformational impacts of the oil and gas industry, particularly where it replaces coal, on countries that suffer from energy poverty. I strongly believe that there are real opportunities in the energy transition, especially for countries such as Egypt and Vietnam, to benefit from the responsible and sustainable development of their natural resources. Pharos stands ready to play our part in this transition and will continue to support our host governments as they seek to use oil revenues to promote sustainable, inclusive economic development, manage the impact of climate change and achieve their COP commitments.

Sustainability has always been a key value in Pharos' purpose and business strategy.  In 2022, we brought this even more to the foreground. In September 2022, we made a formal commitment to achieve a Net Zero target on Scope 1 (direct) and 2 (indirect) GHG emissions from all our existing and future assets by no later than 2050, with a detailed Net Zero roadmap to come in late 2023. We have also established an Emissions Management Fund to provide support for emissions management projects in line with our climate goals. We are committed to transparency in our reporting and will keep stakeholders updated on our progress.

 

Outlook

2022 was a year of change for Pharos, and I am honoured to be the Chair of the Company at such a pivotal stage in its history. Thanks to the effort, ingenuity and hard work of all of our colleagues, the Company is now well-positioned to deliver sustainable value, with a stable balance sheet and a clear strategy underpinned by a commitment to Net Zero by 2050 and to safe and responsible operations. We enter 2023 with a more confident outlook. On behalf of the Board, I would like to thank our shareholders for their support through the year, as well as our staff, partners, suppliers and advisers, all of whom have helped to provide stability through this period of uncertainty and volatility.

 

 

 

 

 

 

 

 

 

John Martin

Non-Executive Chair

 

Chief Executive Officer's Statement

"Delivering value to all stakeholders"

2022 was a year of significant change for Pharos. Amidst the challenges and ongoing volatility facing the industry, we delivered crucial milestones that have allowed us to rebuild resilience in the balance sheet and helped us deliver on our strategy of offering long term, sustainable value to our shareholders via both regular cash returns and organic growth.

·      In January 2022, the Company received presidential approval on the El Fayum Third Amendment which increased Contractor share of revenues from c.42% to c.50%, thus improving fiscal terms in Egypt.

·      In March 2022, we completed the farm-out transaction and transfer of operatorship of our Egyptian assets to IPR. The combination of IPR's long track-record in Egypt, the enhanced fiscal terms, the Egyptian rig secured on a long-term contract, plus the carry over our remaining 45% interest through 2022 and into 2H 2023, all combined to support delivery of the full potential of these assets, despite the current challenges in the Egyptian economy. 

·      In July 2022, we initiated a $3m share buyback programme to return value to shareholders at a time where the share price was trading at a material discount and to enhance NAV, earnings and dividends per share to shareholders over time. The programme took around six months to complete and, in January of this year, we announced its continuation with a further $3m committed.

·      In September 2022, we announced a clear policy for the recommencement of regular dividend payments, the first of which will be put to the AGM in May 2023 and, subject to shareholder approval, paid in July 2023. 

·      Also in September 2022, we set out a formal commitment to achieve a Net Zero target on Scope 1 (direct) and 2 (indirect) GHG emissions from all our existing and future assets by no later than 2050, which we recognise is a key component for stakeholders.

These key steps, combined with the operational performance set out below, have reset the dial for Pharos. The Group now has a refreshed portfolio, a reduced cost base, and a more resilient balance sheet to allow us to invest in the organic growth opportunities in the portfolio. These opportunities range from near-term developments and exploration potential in Egypt to world-class potential basin-opening exploration in Vietnam.

Strong operational performance in 2022 …

In Vietnam, the Group continued to deliver high netback, stable production. Production in 2022 from the TGT and CNV fields net to the Group's working interest averaged 5,418 boepd, in line with guidance. To sustain production levels, the JOCs carried out a drilling programme comprising two development wells at TGT and one at CNV, which was completed on time and under budget. In 2022, the crude produced from the fields in Vietnam commanded a premium to Brent of just over $4/bbl, achieved a netback of c.$50 per barrel and a forecast payback period for the wells drilled of less than 12 months, making investment in these fields an attractive proposition.

In Egypt, we completed the farm-out to IPR in March 2022, and production from the El Fayum Concession averaged 3,128 bopd gross, 1,748 bopd net to the Group, in line with guidance announced in May 2022. A multi-well development drilling programme on El Fayum was undertaken, with a total of seven wells drilled and put on production in 2022. Most notably, in July 2022, the JOC (Petrosilah) secured a rig on a long-term contract, one year firm plus an option for a second year, from December 2022. This rig is expected to provide a stable platform for a continuous drilling campaign which is essential to adding new barrels to production, subject to improving macroeconomic position in Egypt.

The health and safety of our workforce remains our number one priority and we are committed to operating safely and responsibly at all times. We continue to have an excellent safety record in Vietnam, and I am pleased to report that the Company reported zero LTIs and zero fatal incidents in Vietnam for the past 26 years. This is thanks to the JOCs' consistent efforts to provide and champion workers' health, safety and well-being, and we are careful to maintain this achievement as we have done since 1996. In Egypt, we regret to report one LTI and one environmental spill in 2022, details of which are set out in our Corporate Responsibility report in our Annual Report. We are working with our partner IPR and JOC Petrosilah to investigate and address the underlying issues behind the safety measurements and precautions in operations in order to return to our track record of zero safety and environmental incidents across all assets.

Our operational performance in 2022 has laid a strong foundation for our 2023 work programme to move forward with the growth potential of our assets, supporting delivery of our strategy.

 

… Helping us deliver our strategy

As we navigate the many challenges throughout the year, the Board and senior management team maintain a clear focus on our capital allocation goals: to balance regular returns to shareholders with investment in our assets to generate sustainable value and cash flow, while preserving the resilience of the balance sheet.  As the Company reshapes its portfolio and financial position, our strategy of creating and returning value to shareholders through a combination of annual dividends and organic growth, underpinned by robust cash flow and strengthened balance sheet, stays consistent through changing times. We are committed to delivering value and invest where see near term cash flow and longer term value per share.  We keep each asset in our portfolio under review to ensure that they are delivering the expected value and we have a track record of monetising at the right point in the cycle.

1.   Shareholder Returns

 

We have established a sustainable shareholder return framework via share buybacks and dividends. Our initial $3m share buyback programme announced in July 2022 has completed and we have announced a further commitment of $3 million to continue the programme in 2023. Additionally, in September 2022, we announced our intention to recommence dividend payments starting in 2023. Our policy is set at returning not less than 10% of Operating Cash Flow (OCF) and accordingly takes account of volatility in the market, such as movements in Brent price, tax, and working capital movements. Based on the 2022 results, where OCF of $53.4m (£43.2m) was achieved, the first dividend under this policy will amount to 1p per share, and will be put to shareholders at the AGM in May 2023. Payment of the 2022 dividend is scheduled for July 2023, and the Board expects to pay an interim dividend based on forecast results for 2023 in early January 2024.    

 

2.   Organic growth opportunities

 

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, 3D seismic processing is complete on Block 125, a basin-opening frontier play with world-class potential, and a variety of interesting Prospects have been identified. We are in discussions with a number of parties interested in farming in to support the funding of a commitment well on this Block. Lastly, we are progressing work to submit licence extension requests across our asset base to extend the periods over which we can continue our work. In Egypt, we have infrastructure-led exploration (ILX) opportunities in both the North Beni Suef (NBS) and El Fayum Concessions, which are being developed with our partner IPR in the 2023 work programme. 

 

3.     Cash flow protections

 

We have run cash flow projections over a number of different scenarios and have a balance of hedged and free-floating Group production, with 71% or forecast production unhedged at 31 December 2022, thus providing exposure to the oil price. We also operate in two very different jurisdictions, which provides diversification and resilience in a volatile world. Additionally, to mitigate the impact of the current late payment issues in Egypt, we have a working capital facility with the National Bank of Egypt (NBE) to smooth out payment cycles there. Under this arrangement, Pharos is able to access USD cash from the facility of up to 60% of sales invoices outstanding, with a cap of $18m.

 

4.   Capital allocation

 

We have a culture of prudent financial management, capital allocation and capital return. We exhibit capital discipline through a focus on cost management and control, a part of our DNA. Capital allocation decisions are taken to make investments where they will generate risk-adjusted full-cycle returns and it is this approach that has allowed us to return significant amounts of capital to shareholders in the past. We retain a flexible approach to our portfolio and look to time acquisitions and divestments to optimise cash flow and value per share.

 

Stakeholder engagement

The operational successes the Company had during the year, as well as the strategic building blocks towards reshaping the business, would not have been possible if not for the supportive relationships we have with our stakeholders.

After an extended period of travel restrictions due to the pandemic, in 2022, I was able to travel to Egypt and Vietnam to meet with many of our colleagues and key stakeholders in-person. I am personally very grateful to have been able to reconnect and refresh relationships with our partners after a long period of remote working, and have been greatly encouraged by the supportive and open engagement with our colleagues, JV/JOC partners, regulators, and governments. I met the Chair of EGPC, the industry regulator and state oil company in Egypt, in H2 2022, whose support was a crucial step towards the approval for the improvement in our fiscal terms. In Vietnam, I had the opportunity to meet with both our partners and the regulator to discuss the Revised Field Development Plans and licence extensions for TGT and CNV, and the exploration potential and licence extension for Block 125/126. Closer to home, we also hosted an extensive delegation from Vietnam to contribute our thoughts and experiences as they prepared to take a new petroleum law through the National Assembly, which has now been approved and will take effect from 1 July 2023, helping to expedite some of the approval processes in country. Finally, in December 2022, John Martin and I were honoured to be granted a private audience with the Prime Minster of Vietnam 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. Most recently, in January 2023, the Company held a lunch to engage with analysts, both those covering and not covering the Company, to foster open and communicative relationships with key figures in the industry. We will continue to engage in a personal and meaningful way with our various stakeholders in 2023 and beyond.

Sustainability & Net Zero

Sustainability is a key value in our purpose and business strategy. We are committed to providing energy to support the development and prosperity of the countries, communities and families wherever we work, in line with recognised social and environmental practices. The use of oil and gas in developing economies, particularly where it replaces coal, can provide the energy needed to drive GDP growth as a foundation for long-term economic and social benefits, as long as those resources are developed efficiently, safely and responsibly. In this way, we can create sustainable value for all of our stakeholders: investors, host countries, business and communities.

This year, we have taken an important step with regard to our environmental responsibilities to society and the countries in which we operate. In September 2022, we announced a commitment to achieve Net Zero on our Scope 1 (direct) and Scope 2 (indirect) GHG emissions from all our current and future assets by no later than 2050. We look to achieve this by progressing operational efficiencies, reducing flaring and venting where possible, replacing the power consumption of our facilities with less impactful energy sources and eventually procuring nature-based carbon offset projects for hard-to-abate, residual emissions. As we develop our emissions reduction plans, we will look to accelerate this 2050 target whenever we can. We have also established an Emissions Management Fund in 2022 to provide support for emissions management projects in line with our climate goals. Additionally, we also pledge to publish a detailed Net Zero roadmap in late 2023, to include a baseline emissions inventory for all our assets, asset-level emission reduction frameworks, and introducing interim targets over the short and medium term as well as the capital expenditure and resourcing needed to achieve targets.

We recognise that the journey to Net Zero will be neither simple nor straightforward. Nevertheless, we remain committed to transparency in our reporting and to keeping stakeholders updated on our progress. For more details on our Net Zero commitment, Emissions Management Fund, our emission impact and how we deliver value to the local community, please refer to our Corporate Responsibility Report in our Annual Report.

Outlook

The key steps we have taken to reshape our business have taken Pharos to a stronger place. After a year of delivery, we now have a combination of assets which offer resilience in difficult times, strong cash returns even at low oil prices, plus valuable organic growth potential when investment capital is available. Having taken over the reins at Pharos a year ago, I am confident that we have the assets, plan, team, capital structure and financial discipline to deliver long-term sustainable return to all stakeholders. I would like to thank our global colleagues, investors, government and JV/JOC partners for their continued support through these changes as we navigated through a year of challenges and uncertainties, and I look forward to working with all of them to steer Pharos on a path towards a new phase of growth.

 

 

 

 

 

 

 

Jann Brown

Chief Executive Officer

 

Review of Operations

Vietnam

Vietnam Production in 2022

Production in 2022 from the TGT and CNV fields net to the Group's working interest averaged 5,418 boepd (2021: 5,560 boepd). This is in line with the production guidance for Vietnam announced in January 2022.

TGT production averaged 13,784 boepd gross and 4,089 boepd net to the Group (2021: 13,887 boepd gross and 4,120 boepd net). CNV production averaged 5,317 boepd gross and 1,329 boepd net to the Group (2021: 5,762 boepd gross and 1,440 boepd net).

 

Vietnam Development and Operations in 2022

 

TGT & CNV Fields

On Block 16-1 - TGT Field, the drilling programme for two development wells completed in H2 2022, on time and under budget. The first well, H1-35P, commenced production on 21 October 2022, and the second well, 11XPST, commenced production on 10 November 2022.

 

Additionally, the JOC continues to execute an active well intervention and data-gathering programme on TGT to further optimise production.

 

On Block 9-2 - CNV Field, one development well, CNV-2PST1, started drilling in H2 2022 and completed in Q1 2023 on time and under budget.

Vietnam Exploration in 2022

 

Blocks 125 & 126

On Block 125, the 3D seismic processing was completed in November 2022 and the ongoing interpretation of this data has resulted in the mapping of a variety of world class Prospects in this relatively unexplored basin.

 

The analysis of the 2D seismic shot in 2019 indicated prospectivity in both the shallow and deeper water, and the ongoing interpretation of the 3D seismic has highlighted greater prospectivity in the deeper water section given the scale of the Prospects identified there.

 

 

2023 Work Programme

 

TGT & CNV Fields

Vietnam production guidance for 2023 is 4,700 to 5,700 boepd net.

 

For the 2023 work programme, the JOCs are working towards submitting Revised Field Development Plans (RFDPs) for two wells on TGT and one on CNV, with all wells remaining in contingent budget until approval by partners and the Ministry of Industry and Trade (MOIT).  Production guidance has assumed no contribution from these wells in 2023. 

The official licence extension requests have been sent to partners for approval, prior to submission to PVN for their approval before being put to the Prime Minister for final assent.

Blocks 125 & 126

 

As noted above, 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. Due to limited regional availability the Group has been unable to source a suitable drilling unit for 2023 on acceptable terms. We therefore submitted an application in December 2022 for an extension of the current exploration phase of the PSC which is now with the Prime Minister's office for approval.

 

We will use the time to optimise drilling locations and well planning for this deeper water well, to source a Drillship or DP Semi-Submersible Rig and other long-lead procurement items and to find a partner to support the funding of this well. A number of parties have been invited to review data and discussions are ongoing.

 

In addition, we are now engaged in updating our 3D Hydrocarbon Modelling of the area and in fully analysing the 3D seismic data for amplitude anomalies - spectral decomposition for reservoir facies distribution patterns and AVA/AVO analysis for the presence of hydrocarbons. We have also started a detailed Peer Review study of all our technical work with a leading Energy Subsurface consultancy (ERCE), who will also perform an Independent Resource assessment of our key Prospects.

 

 

Egypt

Egypt Production in 2022

 

The transaction with IPR and transfer of operatorship completed on 21 March 2022. Although the economic date of the transaction was 1 July 2020, operatorship remained with Pharos until March 2022. Accordingly, working interest production in 2022 is reported in the Financial Statements as 100% through to completion of the farm-down and 45% thereafter.

Production for 2022 from the El Fayum Concession averaged 3,128 bopd gross and 1,748 bopd net to the Group. This is in line with the 2022 production guidance announced in January 2022.

Egypt Development and Operations in 2022

Following the transaction with IPR in March 2022, the main El Fayum multi-year and multi-well development programme commenced in Q2 2022. Seven wells were put on production in 2022 (including one well drilled in 2021), and one additional well was drilled in Q4 2022 and completed in Q1 2023.

In July 2022, the El Fayum JOC, Petrosilah, secured a rig on a long-term contract, one year firm plus an option for a second year, which started drilling in December 2022. This rig is expected to provide a stable platform for a continuous drilling campaign, which we consider essential to adding new barrels to production.

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

Egypt Commercial

In January 2022, the Company received approval on the Third Amendment to the El Fayum Concession. The agreement, and the improved fiscal terms, were retroactively effective from November 2020.

 

As a result of the changes introduced by the Third Amendment, the Contractor parties' share of revenue while in full cost recovery mode increases from c.42% to c.50% as from November 2020 (corresponding to additional net revenues to the Contractor of c.$7 million to the date of signature) significantly lowering the development project break-even. The Third Amendment also grants Contractor a three-and-a-half-year extension to the exploration term of the El Fayum Concession, with an additional obligation on Contractor to drill two exploration wells and acquire a 3D seismic survey in the northern area of the concession.

 

The Group is cognisant of the current macroeconomic situation in Egypt, and will continue to review its investment programme in light of recovery of the receivable position.

 

Egypt Exploration in 2022

North Beni Suef (NBS) exploration

 

In Q4 2022, the Company was granted a short extension on North Beni Suef (NBS) to allow additional time to drill high-ranked prospects and all work programme commitments, including the first of two commitment exploration wells, originally planned for Q4 2022. Several prospects have been identified from the existing 3D seismic.

 

 

2023 Work Programme

 

El Fayum

 

Egypt production guidance for 2023 is 1,350 - 1,800 bopd net (equivalent to gross production of 3,000 - 4,000 bopd).

 

In El Fayum, multi-well development drilling continues in 2023, with nine wells planned for the year.

 

On the exploration side, two commitment exploration wells are expected to be drilled in the El Fayum Concession as part of the planned 2023 work programme. These two Satellite exploration wells are planned to target two separate structures near existing producing fields with primary reservoir targets in the Abu Roash G and Upper Bahariya formations. We are working closely with IPR to progress well planning and optimise drilling schedules.

 

The drilling of the first NBS exploration commitment well, originally planned for Q4 2022, has started in Q1 2023. In March 2023, a further extension to the exploration period was granted by EGPC. These two extensions, which run until September 2023, provide additional time to fulfil the Contractor parties' commitment to drill this commitment well. The second commitment exploration well on NBS is planned to be drilled later in 2023, dependent on rig availability. Several prospects have been identified from the existing 3D seismic and acquisition of c.110 km2 of additional 3D seismic has started in Q1 2023.

 

 

 

 

 

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	Egypt4	Group
Oil & Gas 2P Commercial Reserves 1,2
As of 1 January, 2022	10.9	4.3	15.2	37.8	53.0
Production	(1.5)	(0.5)	(2.0)	(0.6)	(2.6)
Revision	(0.6)	(0.4)	(1.0)	(1.5)	(2.5)
Change in net working interest 5	-	-	-	(20.7)	(20.7)
2P Commercial Reserves as of 31 December 2022	8.8	3.4	12.2	15.0	27.2
Oil & Gas 2C Contingent Resource 1,2
As of 1 January, 2022	7.6	3.8	11.4	18.6	30.0
Revision	(0.2)	(0.4)	(0.6)	0.5	(0.1)
Change in net working interest 5	-	-	-	(10.2)	(10.2)
2C Contingent Resources as of 31 December 2022	7.4	3.4	10.8	8.9	19.7
Total Group 2P Reserves & 2C Contingent Resources 3,4 As of 31 December 2022	16.2	6.8	23.0	23.9	46.9

(1) Reserves and contingent resources are categorised in line with 2018 SPE standards.

(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.

(5) Pharos Energy net working interest in El Fayum is 45% post completion of farm down transaction to IPR energy on 21 March 2022

 

 

 

Vietnam Reserves and Contingent Resources

In accordance with the requirements of its Reserve Base Lending Facility, 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 2022.

 

Vietnam Reserves Statistics

 

Net Working Interest (mmboe)	TGT	CNV	Total Vietnam
Oil & Gas 2P Commercial Reserves 1,2
As of 1 January, 2022	10.9	4.3	15.2
Production	(1.5)	(0.5)	(2.0)
Revision	(0.6)	(0.4)	(1.0)
2P Commercial Reserves as of 31 December 2022	8.8	3.4	12.2
Oil & Gas 2C Contingent Resource 1,2
As of 1 January, 2022	7.6	3.8	11.4
Revision	(0.2)	(0.4)	(0.6)
2C Contingent Resources as of 31 December 2022	7.4	3.4	10.8
Total Vietnam 2P Reserves & 2C Contingent Resources 3 As of 31 December 2022	16.2	6.8	23.0

(1) Reserves and contingent resources are categorised in line with 2018 SPE standards.

(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.

 

On TGT, 2P reserves were revised downwards due to lower than expected performance from one of the new infill wells and a slow production ramp-up following the annual maintenance shutdown. 2C contingent resources were revised as volumes from two future infill wells were moved into the reserves category.

 

On CNV, the 2P reserves and 2C contingent resources were revised downwards due to lower performance from the existing wells and delayed dewatering of well 5PST2.

Egypt Reserves and Contingent Resources

Egypt Reserves Statistics

 

Net Working Interest (mmboe)	Egypt
Oil 2P Commercial Reserves 1
As of 1 January, 2022	37.8
Production	(0.6)
Revision	(1.5)
Change in net working interest 3	(20.7)
2P Commercial Reserves as of 31 December 2022	15.0
Oil 2C Contingent Resource 1
As of 1 January, 2022	18.6
Revision	0.5
Change in net working interest 3	(10.2)
2C Contingent Resources as of 31 December 2022	8.9
Total Egypt 2P Reserves & 2C Contingent Resources 2 As of 31 December 2022	23.9

(1) Reserves and contingent resources are categorised in line with 2018 SPE standards.

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

(3) Pharos Energy net working interest in El Fayum is 45% post completion of farm down transaction to IPR energy on 21 March 2022

 

 

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

 

Group's Net Working Interest Reserves and Contingent Resources   El Fayum Fields at 31 December 2022 (mmboe)
Reserves	1P	2P	3P
Oil	7.3	15.0	20.0
Contingent Resources	1C	2C	3C
Oil	3.3	8.9	18.0
Sum of Reserves and Contingent Resources 1,2	1P & 1C	2P & 2C	3P & 3C
Total	10.6	23.9	38.0

(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.

 

TGT Field at 31 December 2022 (mmboe) (net to Group's working interest)
Reserves3	1P	2P	3P
Oil	6.7	8.1	9.2
Gas1	0.4	0.7	0.9
Total	7.1	8.8	10.1
Contingent Resources3	1C	2C	3C
Oil	4.7	7.1	9.0
Gas1	0.1	0.3	0.5
Total	4.8	7.4	9.5
Sum of Reserves and Contingent Resources2	1P & 1C	2P & 2C	3P & 3C
Oil	11.4	15.2	18.2
Gas1	0.5	1.0	1.4
Total	11.9	16.2	19.6

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

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

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

 

 

CNV Field at 31 December 2022 (mmboe) (net to Group's working interest)
Reserves3	1P	2P	3P
Oil	1.8	2.1	2.5
Gas1	1.1	1.3	1.5
Total	2.9	3.4	4.0
Contingent Resources3	1C	2C	3C
Oil	1.3	2.1	3.0
Gas1	0.8	1.3	1.8
Total	2.1	3.4	4.8
Sum of Reserves and Contingent Resources2	1P & 1C	2P & 2C	3P & 3C
Oil	3.1	4.2	5.5
Gas1	1.9	2.6	3.3
Total	5.0	6.8	8.8

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

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

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

 

 

Chief Financial Officer's Statement

I am pleased to report the strengthening of our balance sheet and a considerable improvement in the liquidity of the business. The steps we took in previous periods to streamline our business are showing results, with improved fiscal terms in Egypt and reduced costs throughout the Group. Our finance strategy continues to underpin our business model and our commitment to building shareholder value through organic growth and sustainable returns to shareholders. We have continued with our infield development programme in Vietnam, allowing us to sustain production levels in these highly attractive fast payback wells. The successful completion of the farm down in Egypt in March brought in a small initial cash payment on completion, but more significantly allowed us to benefit from a full carry of all contractor costs for G&A, opex and the capital programme into 2023. This activity has all been supported by improved oil prices and has allowed us to deliver strong positive cash flow and growth in value. As a direct result, we were able to announce returns to shareholders with the $3m share buyback programme in July and also announce our proposal to recommence regular dividend payments, the first based on 2022 Operating Cash Flow.*

^{*Subject to shareholder approval at 2023 AGM}

 

Operating performance

Revenues

Group revenues were up 35% at $221.6m prior to realised hedging loss of $22.5m (2021: $163.8m prior to realised hedging loss of $29.7m).

Revenues for Vietnam of $184.8m (2021: $131.0m) increased significantly year on year. The average realised crude oil price was $106.44/bbl (2021: $72.61/bbl), a 47% increase year on year, and the premium to Brent was over $4/bbl on average (2021: just under $2/bbl). Production was largely flat at 5,418 boepd (2021:  5,560 boepd).

The revenue for Egypt of $36.8m (2021: $32.8m) increased largely due to 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. This was combined with higher average realised crude oil price, up 47% to $96.03/bbl (2021: $65.12/bbl), though offset by reduced production of 1,748 bopd from 3,318 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 $5/bbl for the year.

 

Hedging

A number of hedges were put in place in 2021 for the 2022 year to support our stress testing for going concern and the working capital test required for the prospectus for the Egyptian farm down. We were hedged more than required under our RBL and higher than we would normally commit to in order to support this. For full year 2022, Pharos entered into different commodity (swap and zero collar) hedges to protect the Brent component of forecast oil sales and to ensure future compliance with its obligations under the reserve based lending facility (RBL) over the producing assets in Vietnam. The commodity hedges run until December 2023 and are settled monthly. The majority of hedged production volumes (61%) were in H1 2022, leading to realised losses of $17.3m out of total realised losses of $22.5m for the year, in order to meet requirements under the RBL and also going concern and working capital tests in relation to the Egypt farm out deal.

For 2022, 30% of the Group's total production was hedged, securing an average realised price for the hedged volumes of $73.1/bbl. 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 2023, leaving 71% of Group production unhedged as at 31 December 2022.

Please see below a summary of hedges outstanding as at 31 December 2022, which are all zero cost collar.

 

			1Q23	2Q23	3Q23	4Q23
Production hedge per quarter - 000/bbls			180	180	180	45
Min. Average value of hedge - $/bbl			65.33	65.33	63.33	63.33
Max. Average value of hedge - $/bbl			102.88	102.88	102.23	107.80

 

Operating costs

Group cash operating costs, defined in the Non-IFRS measures section on page 38, were $42.8m (2021: $52.0m). Vietnam increased marginally by 2% from $31.0m to $31.7m in 2022, which equates to $16.03/bbl (2021: $15.28/bbl). The increase is due to higher costs relating to the FPSO as a result of lower Thang Long Joint Operating Company (TLJOC) production (TLJOC has 14.5% cost share in 2022 compared to 22.7% in 2021) throughout, which increased the HLJOC's share of the costs.

Cash operating costs in Egypt were $11.1m in 2022 (2021: $21.0m), which equates to $17.40/bbl (2021: $17.34/bbl). Cash operating costs from 1 January 2022 up to 20 March 2022 are 100% share and from 21 March 2022 includes the Group's remaining 45% share. The increase in cash operating costs relates largely to higher variable costs as a result of an upsurge in the fuel price, offset by the significant devaluation of EGP against the US dollar during the year.

 

DD&A

Group DD&A associated with producing assets increased to $55.1m (2021: $51.0m) driven by a higher depreciating cost base following 2021 and June 2022 impairment reversals taken on both Vietnam and Egypt, partially offset by the decrease in group production year on year. DD&A per bbl is currently $25.79/boe for Vietnam (2021: $21.19/boe). DD&A per bbl for Egypt is $6.43/boe for the full year production entitlement, as the Company had 100% share of Egypt production for the period through to completion of the farm-down, 1 January 2022 to 20 March 2022, and then 45% share for the remainder of the year. At 31 December 2021, 55% of El Fayum property, plant and equipment (PP&E) was re-categorised to assets classified as held for sale. The remaining 45% PP&E cost base was depreciated over 45% share of production for the period through to completion of the farm-down, giving a comparable DD&A per bbl of $7.98/boe (2021: $6.61/boe), which reflects the impairment reversals previously noted.

 

Administrative Expenses

Administrative expenses in 2022 of $10.0m (2021: $13.2m) are substantially lower than prior year due to our restructuring efforts. After adjusting for the non-cash items under IFRS 2 Share Based Payments of $1.3m (2021: $2.2m), the administrative expense is $8.7m (2021: $11.0m). Following completion of the farm down to IPR in March 2022 and the AGM in May 2022, the Board was reduced from 9 to 6 Directors. The remaining non-executives' fees were restated to the levels prior to the reductions taken during 2020 and 2021. As previously noted in the 2021 Annual Report & Accounts, the incoming CEO took a 21% reduction in base salary on assuming the role. The Egypt office was also restructured following the farm down.

 

Operating Profit

Operating profit from continuing operations for the year was $72.3m (2021: $6.3m) excluding the net impairment reversal of $27.9m (2021: $42.0m net impairment reversal), reflecting the higher commodity price environment throughout the year, offset by 19% reduction in production volumes.

 

Other/Restructuring Expenses and Loss on Disposal

Other/restructuring expenses for the year totalled $0.8m (2021: $3.3m) and included restructuring costs for both the head office in London and the Egypt office in Cairo ($0.1m). In addition, there was $0.7m charge relating to the premium on the transfer of the lease on the London office.

Loss on disposal for the year totalled $6.3m (2021: $nil) and 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, were 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). The first payment of the contingent consideration, being $5 million in respect of the Brent price during 2022, is due from IPR in June 2023.

 

Finance Costs

Finance costs increased to $12.7m (2021: $6.4m), mainly relating to a one-off charge of $2.6m following a change in estimated future cash flows following the December 2022 RBL redetermination and amortisation of capitalised borrowing costs of $1.5m (2021: $2.4m gain due to changes in future cash flows), interest expense payable and similar fees of $6.1m primarily due to higher interest rates charged on the RBL and NBE  (2021: $3.8m), unwinding of discount on provisions of $1.3m (2021: $0.8m) and foreign exchange losses of $1.2m primarily driven by the devaluation of EGP against USD (2021: foreign exchange gains of $0.6m).

Cash operating cost per barrel*	2022 $m	2021 $m
Cost of sales	116.8	114.6
Less
Depreciation, depletion and amortisation	(55.1)	(51.0)
Production based taxes	(14.7)	(10.1)
Export duty	(3.2)	-
Inventories	1.8	0.1
Trade Receivable risk factor provision	(1.5)	-
Other cost of sales	(1.3)	(1.6)
Cash operating costs	42.8	52.0
Production (BOEPD)	7,166	8,878
Cash operating cost per BOE ($)	16.36	16.05

 

 

DD&A per barrel*	2022 $m	2021 $m
Depreciation, depletion and amortisation	(55.1)	(51.0)
Production (BOEPD)	7,166	8,878
DD&A per BOE ($)	21.07	15.74

 

 * Cash operating cost per barrel and DD&A per barrel are alternative performance measures. See page 38.

 

 

Cash operating cost per barrel by Segment	Vietnam     $m	Egypt Up to 20/03/22 1   $m	Egypt From 21/03/22 to 31/12/22 1 $m	Egypt Total   $m	Total     $m
Cost of sales	99.6	4.9	12.3	17.2	116.8
Less
Depreciation, depletion and amortisation	(51.0)	(0.6)	(3.5)	(4.1)	(55.1)
Production based taxes	(14.5)	-	(0.2)	(0.2)	(14.7)
Export duty	(3.2)	-	-	-	(3.2)
Inventories	1.6	-	0.2	0.2	1.8
Trade Receivable risk factor provision	-	(0.5)	(1.0)	(1.5)	(1.5)
Other cost of sales	(0.8)	(0.2)	(0.3)	(0.5)	(1.3)
Cash operating costs	31.7	3.6	7.5	11.1	42.8
Production (BOEPD)	5,418	2,857	1,441	1,748	7,166
Cash operating cost per BOE ($)	16.03	15.94	18.21	17.40	16.36

 

¹ movements from 1 January 2022 up to 20/03/22 are 100% share and from 21/03/22 includes the Group's remaining 45% share. 100% cash operating costs for period from 21/03/22 to 31/12/22 amounts to $16.7m.

 

 

Cash flows and accounting for Egypt

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

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

The Group, through its subsidiary PEF, owned and managed the business up to completion.  On completion an adjustment to compensate IPR for 55% of net cash flows, revenue offset by costs since the effective 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, the Group's 45% share of field costs - capex, opex and G&A - are accounted for as incurred by the Group, although all such costs are paid by IPR and set off against the carry. Please see Note 14 for more details on the disposal of asset held for sale. 

All revenues earned are paid direct to the Group. 

 

DD&A per barrel by Segment	Vietnam $m	Egypt $m	Total $m
Depreciation, depletion and amortisation	51.0	4.1	55.1
Production (BOEPD)	5,418	1,748	7,166
DD&A per BOE ($) *	25.79	6.43	21.07

 

* Calculation based on full production entitlement for the year. Actual DD&A charges were calculated on 45% share of production for the full year, giving a revised DD&A per bbl metric of $7.98/boe.

 

Movements in Property, Plant and Equipment		2022 $m	2021 $m
As at 1 Jan		399.8	435.8
Capital spend		23.2	24.7
Revision in decommissioning assets		(13.9)	(1.9)
Recognition of right-of-use assets		0.8	-
Re-classification of assets held for sale		-	(62.0)
DD&A- Oil and gas properties		(55.1)	(51.0)
DD&A - Other assets		(0.1)	(0.4)
Impairment reversal/(charge) - PP&E		27.1	54.6
As at 31 Dec		381.8	399.8
Property, Plant and Equipment		381.0	399.8
Right-to-use-Asset (IFRS 16 Impact)		0.8	-
As at 31 Dec		381.8	399.8

 

 

Taxation

The overall net tax charge of $56.2m (2021: $43.3m) relates to tax charges in Vietnam of $47.9m plus the deferred tax charge on impairment reversal of $8.3m (2021: Vietnam tax charges of $24.8m plus the deferred tax charge on impairment reversal of $18.5m).

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 swaps 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 $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.

 

Profit/(loss) post-tax

The post-tax profit for the year from continuing operations and prior to the impairment reversal of $27.9m, impairment tax charge of $8.3m, exceptional costs of $0.8m and loss on disposal of $6.3m was $11.9m (2021: post tax loss for the year of $24.9m from continuing operations and prior to the impairment reversal of $42.0m, impairment tax charge of $18.5m and exceptional costs of $3.3m). The overall profit for the year was $24.4m (2021: $4.7m loss).

 

Cash flow

Operating cash flow (before movements in working capital) was $128.8m (2021: $60.1m). After tax charges of $54.7m (2021: $39.9m), restructuring and exceptional expenses $2.7m (2021: $0.7m) and working capital adjustments of $18.1m (2021: $8.6m), the cash generated from operations was $53.4m (2021: $10.8m). Cash generated from operations, after tax charges, exceptional expenses and working capital movements, will form the basis of our dividend framework going forward. 

Operating cash flow (before movements in working capital) adjusted for the impact of the hedging positions of $22.5m loss (2021: $29.7m loss) gives an underlying operational performance of $151.3m (2021: $89.8m), which is consistent with the significant improvement seen in commodity prices offset by the production decrease year on year.

The increase in receivables was $7.7m (2021: increase in receivables of $7.2m). The movement in 2022 is primarily driven by $16.1m increase from Egypt, which was mainly due to the increase in EGPC receivables inclusive of $7m catch-up invoice for improved fiscal terms under the Third Amendment to the El Fayum Concession and the lack of hard currency in country. As noted in previous updates to the market, the Group has opted not to accept the payment of PEF's receivables balance in EGP unless required for operations. 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. The International Monetary Fund (IMF) recently announced that its Executive Board had approved the provision of a $3 billion, 46-month extended fund facility to Egypt, which the IMF expects to catalyse additional financing of approximately $14 billion from Egypt's international and regional partners. In addition, Egypt is seeking access to up to a further $1 billion from the IMF's newly created resilience and sustainability facility to support climate-related policy goals. Taken together, these developments are widely anticipated to improve Egypt's FX reserves and overall liquidity in the first half of 2023. The Company therefore remain optimistic that outstanding receivables with EGPC will start to be recovered during 2023. The increase in Egypt receivables was partially offset by timing differences on the Vietnam cargoes, leading to a decrease in receivables of $6.9m despite higher commodity prices. 

Capital expenditure on continuing operations for the year was lower at $31.9m (2021: $41.8m). On Block 16-1 - TGT Field, the drilling programme for two development wells completed in H2 2022, on time and under budget. The first well, H1-35P, commenced production on 21 October 2022, and the second well, 11XPST, commenced production on 10 November 2022. On Block 9-2 - CNV Field, one development well, CNV-2PST1, commencing in H2 2022 and has now been completed. In El Fayum, seven wells were put on production in 2022 (including one well drilled in 2021), and one additional well drilled in Q4 2022 is due for completion in Q1 2023.

Net cash outflows from financing activities of $19.8m (2021: $31.1m inflow) included outflows in relation to the RBL of $0.2m in June 2022 and $12.9m in December following the half year and year end redetermination processes and the amount drawn stood at $65.0m at year end.

The RBL loan, which is secured over only the existing Vietnam producing assets, matures in July 2025. The facility amount is amortised by $14.2m every re-determination from 1 July 2022, with a facility amount as at 31 December 2022 of $85.75m, which decreased to $71.5m from 1 January 2023 and will decrease further to $57.3m from 1 July 2023. 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.

Financing activities also included net $2.7m outflow in relation to the NBE revolving credit facility, which 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 2022 was $9.2m. A further $2.9m outflow was due to the share buyback programme that was initiated in July 2022. The first phase of that programme, completed in January 2023, resulted in a total of 10.3 million shares being purchased, at a daily average price of 24.4p.

 

 

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 2022, the total payments to governments for the Group amounted to $245.3m (2021: $198.2m), of which $211.5m or 86% (2021: $151.9m or 77%) was related to the Vietnam producing licence areas, of which $140.7m (2021: $102.6m) was for indirect taxes based on production entitlement. In Egypt payments to government totalled $31.3m (2021: $44.7m), of which $28.8m (2021: $44.1m) related to indirect taxes based on production entitlement.

Balance sheet

Intangible assets increased during the period to $16.5m (2021: $12.4m). Additions for the year related to Blocks 125 & 126 in Vietnam $3.1m (2021: $10.6m), Egypt $1.0m (2021: $3.9m) and $0.2m (2021: $0.7m) for the Israeli bid round licence fee. The Group has written off $0.2m (2021: $2.2m) relating to the Israel asset as no substantive expenditure has been identified under IFRS 6. In 2021, $2.1m of intangible assets relating to the Egypt concessions were re-classified as assets held for sale.

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

 

Impairment reversals

As a result of previously recognised impairment losses, combined with ongoing oil price volatility, economic uncertainty leading to an increase in inflation 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 which constitutes a level 3 valuation within the fair value hierarchy. The recoverable amount is supported by the fair value derived from a discounted cash flow valuation of the 2P production profile.

Summary of Impairments - Oil and Gas properties	TGT $m	CNV $m	Egypt $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: 1
As at 1 Jan 2022	266.0	84.2	49.2	399.4
Additions	7.0	3.2	13.6	23.8
Changes in decommissioning asset 2	(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 Dec 2022	242.4	76.4	62.5	381.3

 

2021
Pre-tax impairment reversal	49.1	3.8	1.7	54.6
Deferred tax charge	(17.1)	(1.4)	-	(18.5)
Post-tax impairment reversal	32.0	2.4	1.7	36.1
Reconciliation of carrying amount: 1
As at 1 Jan 2021	239.3	91.2	104.1	434.6
Additions	11.4	0.3	12.9	24.6
Reclassified as assets held for sale	-	-	(1.4)	(1.4)
Changes in decommissioning asset 2	(1.0)	(0.9)	-	(1.9)
DD&A	(32.8)	(10.2)	(8.0)	(51.0)
Impairment reversal	49.1	3.8	1.7	54.6
Sub-total	266.0	84.2	109.3	459.5
Reclassified as assets held for sale	-	-	(60.1)	(60.1)
As at 31 Dec 2021	266.0	84.2	49.2	399.4

 

¹ Egypt carrying value reflects 45% share (2021: 100%).

² 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 (2021: change in discount rate only for both TGT and CNV)

It should be noted that the TGT impairment reversal for full year 2022 has been restricted to reflect the remaining balance of historic impairment charges previously recorded against the field. Further details of these impairment charges, including key assumptions in relation to oil price and discount rate are provided in Note 10 of the preliminary financial statements.

 

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 $7.2m at 31 December 2022 (2021: $5.9m), of which $7.0m related to Vietnam and $0.2m to Egypt. Trade and other receivables increased to $60.9m (2021: $28.1m) of which $11.4m (2021: $18.2m) relates to Vietnam and $49.0m (2021: $8.5m) relates to Egypt. For Egypt, the closing balance includes $20.9m of carry (2021: $nil), 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 $24.2m from EGPC 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.

Cash and cash equivalents at the end of the year were $45.3m (2021: $27.1m) mainly driven by net cash flows from operating activities of $53.4m (2021: $10.8m) as a result of higher commodity prices during the year, offset by lower production.

Trade and other payables were $14.0m (2021: $30.6m), of which $6.3m (2021: $14.5m) relates to the Egypt payables, inclusive of Stratton royalty obligation and following re-classification of Petrosilah working capital balances to joint venture receivables following the farm-down transaction. $4.8m (2021: $4.8m) relates to Vietnam payables, $0.5m (2021: $6.5m) net hedging liability and $1.9m (2021: $4.4m) Head Office payables. Tax payables decreased to $5.2m (2021: $5.4m) which is linked to the timing of cargoes from TGT.

Borrowings were $74.2m (2021: $80.5m), a decrease of $6.3m with $13.1m related to repayments following the RBL redeterminations in June and December, partially offset by $4.1m amortisation of capitalised borrowing costs and one-off charges in relation to the redeterminations. This was offset by a net increase in the NBE credit facility of $2.7m during the year.

Long-term provisions comprise the Group's decommissioning obligations and, for 2021, the royalty over the El Fayum asset. In Vietnam, the decommissioning provision decreased from $66.9m at 2021 year-end to $54.3m at 2022 mainly due to an increase in discount rate from 1.51% to 3.83% as a result of an increase in prevailing risk-free market rates, partially offset by the TGT infill wells programme completed during the year. The amounts set aside into the abandonment funds total $50.2m (2021: $48.1m). No decommissioning obligation exists under the El Fayum Concession. 

The royalty provision relates to a historical arrangement granting a 3% royalty on PEF's share of profit oil and excess cost recovery from El Fayum in Egypt. At 31 December 2022, the long-term provision was $nil (2021: $2.2m) and the amount disclosed in current payables is $2.5m (2021: $3.4m)

 

 

Own shares

The Pharos Employee Benefit Trust ("EBT") holds ordinary shares of the Company for the purposes of satisfying long-term incentive awards for senior management. At the end of 2022, the trust held 2,126,857 (2021: 1,767,757), representing 0.48% (2021: 0.40%) of the issued share capital.

In addition, as at 31 December 2022, the Company held 9,122,268 (2021: 9,122,268) treasury shares, representing 2.06% (2021: 2.02%) of the issued share capital. All shares purchased under the on-market buyback programme originally announced in July 2022 and extended in January 2023 have been or will be cancelled rather than retained in treasury.

 

Dividend Framework

The Company intends to recommence dividend payments starting in 2023.  Our policy is now set at returning no less than 10% of Operating Cash Flow (OCF).

 

OCF has been selected as the most appropriate measure as it automatically takes account of:

 

•       movements in Brent price;

•       tax, which is the main form of government take in Vietnam; and

•       working capital movements.

 

The first dividend will therefore be a final dividend for the 2022 financial year. The Board have recommended a final dividend of 1.00 pence per share (based on a minimum 10% OCF of $5.34m at the average rate of exchange for 2022) subject to approval of the shareholders at the Company's 2023 AGM. The final dividend will be paid in full on 12 July 2023 in Pounds Sterling to ordinary shareholders on the register at the close of business on 16 June 2023. Going forward, we expect the payment pattern will move to a conventional pattern of an interim and a final dividend. As is normally the case with interim dividends, and unlike the final dividend for 2022 to be proposed at the 2023 AGM, the interim dividend will not be conditional on separate shareholder approval. 

 

 

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 which could affect the Group's future performance and position.

A base case forecast has been considered that utilises oil prices of $88.3/bbl in 2023 and $84.8/bbl in 2024. 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 $59/bbl in May 2023 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 June 2023. Both the base case and RWC take into account effect of hedging that has already been put in place at 31 December 2022 and subsequent hedges placed in 2023, now covering c.33% for the full year 2023 and 6% of Q1 2024. We have therefore secured an average floor price and ceiling price of c.$64/bbl and c. $100/bbl, respectively, for the entire hedged volumes. Under the RWC scenario, we have identified appropriate mitigating actions, which could look to defer capital expenditure programme 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 breakeven price of c.$30/bbl. We have limited capital expenditure in Vietnam which includes the delay of CNV 2PST1 well. The cash flows have also been tested in the unlikely event that an extension for the 125/126 is not secured. The majority of our debt is secured against the Vietnam assets under the RBL, only $9.2m drawn on an uncommitted revolving credit facility on the Egypt revenue invoices.

In Egypt, we have 9 wells in 2023 and the Base case assumes a full investment scenario.

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 2022 Accounts. 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 lot to look forward to as we move forward in 2023 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 and carry in Egypt, extra $5m contingent consideration payment in 2023 and potentially for the next 3 years (oil price dependent). We are encouraged by the intervention from the IMF and hope to see an improved position in our Egyptian receivables.

·      Strong support from our RBL lenders over the Vietnam assets as we continue in 2023 to pay down this facility and a renewal of our uncommitted revolving credit facility with the National Bank of Egypt.

Further returns to shareholders are anticipated in 2023, with the announcement in January of an additional $3m committed to an extension of the Company's on-market share buyback programme, and the resumption of sustainable dividends based on OCF to be proposed at the 2023 AGM.

 

 

Sue Rivett

Chief Financial Officer

 

 

 

Condensed consolidated income statement
for the year to 31 December 2022
									2022	2021
							Notes		$ million	$ million
Continuing operations
Revenue							3		199.1	134.1
Cost of sales							4		(116.8)	(114.6)
Gross profit									82.3	19.5
Administrative expenses									(10.0)	(13.2)
Impairment reversal/(charge) Intangibles							3, 9		0.8	(2.2)
Impairment reversal PP&E							3, 10		27.1	54.6
Impairment charge - Assets classified as held for sale							3, 14		-	(10.4)
Operating profit									100.2	48.3
Other/restructuring expense							5		(0.8)	(3.3)
Loss on disposal							14		(6.3)	-
Investment revenue									0.2	-
Finance costs							6		(12.7)	(6.4)
Profit before tax							3		80.6	38.6
Tax									(56.2)	(43.3)
Profit/(loss) for the year									24.4	(4.7)
Profit/(loss) per share (cents)							8
Basic									5.6	(1.1)
Diluted									5.4	(1.1)
Condensed consolidated statements of comprehensive income
for the year to 31 December 2022
									2022	2021
									$ million	$ million
Profit/(loss) for the year									24.4	(4.7)
Items that may be subsequently reclassified to profit or loss:
Fair value loss arising on hedging instruments during the year									(18.9)	(27.7)
Less: Loss arising on hedging Instruments reclassified to profit or loss									22.5	29.7
Total comprehensive gain/(loss) for the year									28.0	(2.7)

 

     The above condensed consolidated income statement and condensed consolidated statements of comprehensive income should

     be read in conjunction with the accompanying notes.

CONDENSED CONSOLIDATED Balance sheet
							Group			Company
						2022	2021		2022	2021
					Notes	$ million	$ million		$ million	$ million
Non-current assets
Intangible assets					9	16.5	12.4		-	-
Property, plant and equipment					10	381.0	399.8		-	-
Right-of-use assets						0.8	-		-	-
Investments						-	-		335.5	278.7
Loan to subsidiaries						-	-		23.0	27.4
Other assets						59.1	48.1		-	-
						457.4	460.3		358.5	306.1
Current assets
Inventories						7.2	10.7		-	-
Trade and other receivables						60.9	28.1		0.4	1.4
Tax receivables						2.1	1.5		0.1	0.4
Cash and cash equivalents						45.3	27.1		8.8	5.3
Assets classified as held for sale					14	-	62.0		-	-
						115.5	129.4		9.3	7.1
Total assets						572.9	589.7		367.8	313.2
Current liabilities
Trade and other payables						(14.0)	(30.6)		(1.9)	(4.3)
Borrowings						(39.6)	(33.3)		-	-
Lease Liabilities						(0.3)	-		-	-
Tax payables						(5.2)	(5.4)		(1.2)	(1.0)
Liabilities directly associated with assets classified as held for sale					14	-	(8.5)		-	-
						(59.1)	(77.8)		(3.1)	(5.3)
Non-current liabilities
Other payables						(0.9)	-		-	-
Deferred tax liabilities						(92.9)	(91.2)		-	-
Borrowings						(34.6)	(47.2)		-	-
Lease liabilities						(0.5)	-		-	-
Long term provisions						(54.3)	(69.1)		-	-
						(183.2)	(207.5)		-	-
Total liabilities						(242.3)	(285.3)		(3.1)	(5.3)
Net assets						330.6	304.4		364.7	307.9
Equity
Share capital						34.3	34.9		34.3	34.9
Share premium						58.0	58.0		58.0	58.0
Other reserves						253.6	250.5		199.7	202.4
Retained (deficit) / earnings						(15.3)	(39.0)		72.7	12.6
Total equity						330.6	304.4		364.7	307.9

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

CONDENSED consolidated STATEMENTs OF CHANGES IN EQUITY

	Group
	Called up share capital $ million	Share premium $ million	Other reserves $ million	Retained earnings /(deficit) $ million	Total $ million
As at 1 January 2021	31.9	55.4	243.0	(36.6)	293.7
Loss for the year	-	-	-	(4.7)	(4.7)
Other comprehensive income	-	-	2.0	-	2.0
Share issued	3.0	2.6	5.3	-	10.9
Share-based payments	-	-	2.5	-	2.5
Transfer relating to share-based payments	-	-	(2.3)	2.3	-
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 31 December 2022	34.3	58.0	253.6	(15.3)	330.6

 

	Company
	Called up share capital $ million	Share premium $ million	Other reserves $ million	Retained earnings $ million	Total $ million
As at 1 January 2021	31.9	55.4	197.6	6.9	291.8
Profit for the year	-	-	-	1.9	1.9
Shares issued	3.0	2.6	5.3	-	10.9
Currency exchange translation differences	-	-	0.1	1.5	1.6
Share-based payments	-	-	2.5	-	2.5
Transfer relating to share-based payments	-	-	(3.1)	2.3	(0.8)
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 31 December 2022	34.3	58.0	199.7	72.7	364.7

 

 

 

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 2022

			Group			Company
	Notes	2022 $ million	2021 $ million		2022 $ million	2021 $ million
Net cash from (used in) operating activities	13	53.4	10.8		(11.6)	(7.1)
Investing activities
Purchase of intangible assets		(4.4)	(15.2)		-	-
Purchase of property, plant and equipment		(25.4)	(24.4)		-	-
Consideration in relation to farm out of Egyptian assets1		18.4	2.0		-	-
Assignment fee in relation to farm out of Egyptian assets		(0.5)	-		-	-
Payment to abandonment fund		(2.1)	(2.2)		-	-
Other investment in subsidiary undertakings		-	-		-	(8.4)
Dividends received from subsidiary undertakings		-	-		19.0	6.1
Net cash (used in) from investing activities		(14.0)	(39.8)		19.0	(2.3)
Financing activities
Share based payments		(0.4)	-		-	-
Repayment of borrowings		(27.1)	(12.5)		-	-
Proceeds from borrowings		16.7	39.9		-	-
Interest paid on borrowings		(6.0)	(6.8)		-	-
Lease payments		(0.1)	(0.4)		-	-
Net proceeds from issue of share capital		-	10.9		-	10.9
Share buy back		(2.9)	-		(2.9)	-
Funding movements with subsidiaries		-	-		(1.0)	-
Net cash (used in) from financing activities		(19.8)	31.1		(3.9)	10.9
Net increase in cash and cash equivalents		19.6	2.1		3.5	1.5
Cash and cash equivalents at beginning of year		27.1	24.6		5.3	3.5
Effect of foreign exchange rate changes		(1.4)	0.4		-	0.3
Cash and cash equivalents at end of year		45.3	27.1		8.8	5.3

 

¹ During the year IPR, acting as operator and agent, was authorised to settle its operating liabilities of $6.6m and investing liabilities of $8.8m against the consideration due from the associated carry debtor (Note 14) amounting to $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 2022 or 2021, but is derived from those accounts. A copy of the statutory accounts for 2021 has been delivered to the Registrar of Companies and those for 2022 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.   Significant 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. The Group did not have to change its accounting policies or make retrospective adjustments as a result of adopting these standards.

-      Property, Plant and Equipment: Proceeds before Intended Use - Amendments to IAS 16

-      Onerous Contracts - Cost of Fulfilling a Contract - Amendments to IAS 37

-      Annual Improvements to IFRS Standards 2018-2020

-      Reference to the Conceptual Framework - Amendments to IFRS 3

(c)  New standards and interpretations not yet adopted

Certain new accounting standards and interpretations have been published that are not mandatory for 31 December 2022 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.

 

						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 (Note 14)			-	(6.3)	-	(6.3)
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)
						2021
			SE Asia $ million	Egypt $ million	Unallocated $ million	Group $ million
Oil and gas sales			131.0	32.8	-	163.8
Realised loss on commodity hedges			-	-	(29.7)	(29.7)
Total revenue			131.0	32.8	(29.7)	134.1
Depreciation, depletion and amortisation - Oil and gas			(43.0)	(8.0)	-	(51.0)
Depreciation, depletion and amortisation - Other			-	(0.4)	-	(0.4)
Impairment charge - Intangibles			-	-	(2.2)	(2.2)
Impairment reversal - PP&E			52.9	1.7	-	54.6
Impairment charge - Assets classified as held for sale			-	(10.4)	-	(10.4)
Profit (loss) before tax1			98.8	(10.1)	(50.1)	38.6
Tax charge on operations			(24.8)	-	-	(24.8)
Tax charge on impairment reversal			(18.5)	-	-	(18.5)

 

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

Included in revenues arising from South East Asia and Egypt are revenues of $182.5m and $36.8m which arose from the Group's three largest customers, who contributed more than 10% to the Group's oil and gas revenue (2021: $128.3m and $32.8m in South East Asia and Egypt from the Group's two 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.

	2022 $ million	2021 $ million
Vietnam	97.1	131.0
Egypt	36.8	32.8
China	87.7	-
	221.6	163.8

 

Non-current assets	2022 $ million	2021 $ million
Vietnam	332.5	360.8
Egypt	65.8	51.4
	398.3	412.2

Excludes other assets.

 

4.   Cost of sales

										2022			2021
										$ million			$ million
Depreciation, depletion and amortisation										55.1			51.0
Production based taxes										14.7			10.1
Export duty										3.2			-
Production operating costs										45.6			53.6
Inventories										(1.8)			(0.1)
										116.8			114.6

 

5.   Other/restructuring expense

										2022			2021
										$ million			$ million
Redundancy costs										0.1			3.0
Premium - lease transfer1										0.7			0.3
										0.8			3.3

 

 

¹ 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 (2021: $0.3m) was released from the escrow account and paid to the new tenant.

 

 

6.   Finance Cost

	2022 $ million	2021 $ million
Unwinding of discount on provisions	1.3	0.8
Interest expense payable and similar fees	6.0	3.8
Interest on lease liabilities	-	-
Amortisation of capitalised borrowing costs	4.1	2.4
Net foreign exchange losses/(gains)	1.3	(0.6)
	12.7	6.4

 

In 2022, $1.3m relates to the unwinding of discount on the provisions for decommissioning (2021: $0.8m). 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 8 - 9 years) in the removal and decommissioning of the facilities currently in place.

 

Following the June and December 2022 redeterminations in relation to the Group's reserve based lending facility, there was a change in estimated future cash flows, as a result a one off loss of $2.6m and amortised cost of $1.5m have been recognised in profit or loss.                                          

                       

7.   Tax

	2022 $ million	2021 $ million
Current tax charge	54.5	37.6
Deferred tax credit on operations	(6.6)	(12.8)
Deferred tax charge on impairment reversals	8.3	18.5
Total tax charge	56.2	43.3

 

The Group's corporation tax is calculated at 50% (2021: 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 2022 and 2021, both current and deferred taxation have arisen in overseas jurisdictions only.

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

	2022 $ million	2021 $ million
Profit before tax	80.6	38.6
Profit before tax at 50% (2021: 50%)	40.3	19.3
Effects of:
Non-taxable income	(3.3)	(8.0)
Non-deductible expenses	5.6	4.5
Tax losses not recognised	13.8	28.7
Adjustments to tax charge in respect of previous periods	(0.2)	(1.2)
Tax charge for the year	56.2	43.3

 

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.

The effect of non-deductible exploration costs written back of $(0.5)m in 2022 related to the partial reversal of an impairment of exploration assets in Vietnam.

Non-taxable income principally relates to Vietnam impairment reversal of $(3.3)m (2021: $(8.0)m). Non-deductible expenses primarily relate to Vietnam DD&A charges for costs previously capitalised, which are non-deductible for Vietnamese tax purposes of $5.6m (2021: $1.8m). A further $nil (2021: $2.7m) 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 2021, 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 $28m 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
	2022 $ million	2021 $ million
Gain/(loss) for the purposes of basic profit/(loss) per share	24.4	(4.7)
Effect of dilutive potential ordinary shares - Cash settled share awards and options	(0.3)	-
Gain/(loss) for the purposes of diluted profit/(loss) per share	24.1	(4.7)

 

	Number of shares (million)
	2022	2021
Weighted average number of ordinary shares	439.3	437.8
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	440.2	452.0

 

In accordance with IAS 33 "Earnings per Share", the effects of 14.2m antidilutive potential shares have not been included when calculating dilutive earnings per share for the year ended 31 December 2021, as the Group was loss making.

 

9.   Intangible assets

Intangible assets at 2022 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 (2021: $10.6m), Egypt $1.0m (2021: $3.9m) of which $0.9m (2021: $0.6m) relates to North Beni Suef, and $0.2m (2021: $0.7m) for Israel. 

During 2022, $0.2m was spent in Israel on geoscience and geophysical studies (2021: $0.7m). Following completion of the seismic processing in order to mature prospectivity ahead of a drilling decision, Capricorn as the operator and along with the Company and other JV partners, informed the Ministry of Energy of the JV's intention to relinquish the licences. The bank guarantee of $2.7m held, as at 31 December 2021, for the Israeli offshore exploration licenses, was released accordingly. At 31 December 2022, the Group has therefore decided to write off the $0.2m in Israel as no substantive expenditure has been identified as indicated in IFRS 6.

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 were written off in the income statement in accordance with the Group's accounting policy on oil and gas exploration and evaluation expenditure.

At 31 December 2021, interpretation of the seismic data in relation to Blocks 125 and 126 in Vietnam was ongoing and the carrying value of Egypt exploration and evaluation expenditure was to be reviewed following completion of the farm out of the Egypt concessions.

At 31 December 2022, on Block 125, the 3D seismic processing was complete and the ongoing interpretation of the data resulted in the mapping of a variety of Prospects in the relatively unexplored deep water basin.  A commitment well was planned for 2023 with an estimated cost of $15m, but the focus on deep water means that a drillship is needed and the Company has been unable to source one for 2023. An application has therefore been submitted for an extension of the license and the Company now plans to drill a commitment well in 2024. In Egypt, as part of the planned work programme for 2023, two commitment wells are expected to be drilled in the El Fayum Concession. In order to meet a commitment on North Beni Suef, two exploration wells are expected to be drilled in calendar year 2023.

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 exploration and evaluation expenditure at 31 December 2022 stands at $25.6m (2021: $25.4m). This will be kept under review as the exploration activity continues.

 

10.  Property, plant and equipment

 

As a result of previously recognised impairment losses, combined with the ongoing oil price volatility, economic uncertainty leading to an increase in inflation 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 which constitutes a level 3 valuation within the fair value hierarchy. The recoverable amount is supported by the fair value derived from a discounted cash flow valuation of the 2P production profile.

Summary of Impairments - Oil and Gas Properties				2022
2022	TGT $ million	CNV $ million	Egypt $ 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: 1
As at 1 Jan 2022	266.0	84.2	49.2	399.4
Additions	7.0	3.2	13.6	23.8
Changes in decommissioning asset 2	(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 Dec 2022	242.4	76.4	62.5	381.3

 

 

				2021
2021	TGT $ million	CNV $ million	Egypt $ million	Total $ million
Pre-tax impairment reversal	49.1	3.8	1.7	54.6
Deferred tax charge	(17.1)	(1.4)	-	(18.5)
Post-tax impairment reversal	32.0	2.4	1.7	36.1
Reconciliation of carrying amount: 1
As at 1 Jan 2021	239.3	91.2	104.2	434.7
Additions	11.4	0.3	12.9	24.6
Reclassified as assets held for sale	-	-	(1.4)	(1.4)
Changes in decommissioning asset 2	(1.0)	(0.9)	-	(1.9)
DD&A	(32.8)	(10.2)	(8.0)	(51.0)
Impairment reversal	49.1	3.8	1.7	54.6
Sub-total	266.0	84.2	109.4	459.6
Reclassified as assets held for sale	-	-	(60.2)	(60.2)
As at 31 Dec 2021	266.0	84.2	49.2	399.4

 

¹ Egypt carrying value reflects 45% share (2021: 100%).

² 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 (2021: change in discount rate only for both TGT and CNV).

 

Vietnam

The key assumptions to which the fair value measurement is most sensitive are oil price, discount rate and 2P reserves (2021: oil price, discount rate and 2P reserves). As at 31 December 2022, the fair value of the assets are estimated based on a post-tax nominal discount rate of 13.3% (2021: 11.4%) and a Brent 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 (2021: an oil price of $73.9/bbl in 2022, $70.2/bbl in 2023, $67.8/bbl in 2024, $68.0/bbl in 2025 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 (compare to new NBV) of $11.8m on TGT and $3.7m on CNV. A 1% increase in discount rate would result in post-tax impairments of $4.0m on TGT and $1.0m 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; $88.3/bbl in 2023, $84.8/bbl in 2024, $79.4/bbl in 2025, $72.7/bbl in 2026, $65.6/bbl in 2027, $58.3/bbl in 2028, $50.7/bbl in 2029 and $42.7/bbl in 2030. Using these prices and an 13.3% discount rate would result in additional post-tax impairments of $13.8m on TGT and $5.0m on CNV.

The impairment tests for TGT and CNV assume that production ceases in 2029 and 2030 respectively.

Egypt

The key assumptions to which the fair value measurement is most sensitive are oil price, discount rate, capital spend and 2P reserves (2021: oil price, discount rate, capital spend and 2P reserves). As at 31 December 2022, the fair value of the assets are estimated based on a post-tax nominal discount rate of 15.9% (2021: 14%) and a Brent 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 (2021: an oil price of $73.9/bbl in 2022, $70.2/bbl in 2023, $67.8/bbl in 2024, $68.0/bbl in 2025 plus inflation of 2.0% thereafter).

Testing of sensitivity cases indicated that a $5/bbl reduction in long term oil price used would result in an impairment of $7.8m (compare to new NBV). A 1% increase in discount rate would result in an impairment charge of $2.8m. We have also run a sensitivity using a 15.9% discount rate and the Net Zero price scenario which would result in an additional impairment of $25.5m.

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 2022, Pharos entered into different commodity (swap and zero cost collar) hedges to protect the Brent component of forecast oil sales and to ensure future compliance with its obligations under the reserve based lending facility (RBL) over the producing assets in Vietnam. Pharos was hedged more than required under the conditions of the RBL and higher than the Company would normally commit to in order to support stress testing for going concern and the working capital test required for the prospectus for the Egypt farm down. As a result, the majority of hedged production volumes (61%) were in H1 2022, leading to realised losses of $17.3m out of total realised losses of $22.5m for the year in order to meet these requirements.

The commodity hedges run until December 2023 and are settled monthly. For 2022, 30% of the Group's total production was hedged, securing a minimum price for the hedged volumes of $67.9/bbl. 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 2023, leaving 71% of Group production unhedged as 31 December 2022 (2021: cover was 23% of the Group's forecast production until December 2022, securing a minimum price for this hedged volume of $68.2 per barrel).

A summary of hedges outstanding as at 31 December 2022 is presented below, which are all zero cost collar.

			1Q23	2Q23	3Q23	4Q23
Production hedge per quarter - 000/bbls			180	180	180	45
Min. Average value of hedge - $/bbl			65.33	65.33	63.33	63.33
Max. Average value of hedge - $/bbl			102.88	102.88	102.23	107.80

 

Pharos has designated the swaps and 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 2022 a loss of $22.5m was realised (2021: loss of $29.7m).  The outstanding unrealised loss on open position as at 31 December 2022 amounts to $0.7m (2021: loss of $4.3m).

The carrying amount of the swaps and 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 liability position as of December 2022 was $1.1m (2021: liability position $6.5m).

 

12.  Distribution to Shareholders

The Board have recommended a final dividend of 1.00 pence per share (equivalent to $5.46m at the average rate of exchange for 2022) subject to approval of the shareholders at the Company's 2023 AGM. This reflects a return to shareholders of at least 10% of Operating Cash Flow (OCF), consistent with the revised dividend policy after the Company withdrew dividend payments in 2021 and 2020 due to ongoing uncertainty in the macro environment. The final dividend will be paid in full on 12 July 2023 in Pounds Sterling to ordinary shareholders on the register at the close of business on 16 June 2023.

 

 

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

			Group			Company
		2022 $ million	2021 $ million		2022 $ million	2021 $ million
Operating profit/(loss)		100.2	48.3		44.2	(3.6)
Share-based payments		1.3	2.4		1.3	2.4
Depletion, depreciation and amortisation		55.2	51.4		-	-
Impairment reversal		(27.9)	(42.0)		(53.9)	(7.9)
Operating cash flows before movements in working capital		128.8	60.1		(8.4)	(9.1)
(Increase)/decrease in inventories		(0.9)	0.8		-	-
(Increase)/decrease in receivables 1		(7.7)	(7.2)		1.2	0.4
(Decrease)/increase in payables		(9.5)	(2.2)		(1.8)	2.2
Cash generated by (used in) operations		110.7	51.5		(9.0)	(6.5)
Interest received/(paid)		0.1	(0.1)		0.1	-
Other/restructuring expense outflow		(2.7)	(0.7)		(2.7)	(0.6)
Income taxes paid		(54.7)	(39.9)		-	-
Net cash from (used in) operating activities		53.4	10.8		(11.6)	(7.1)

 

¹ Includes $1.5m (2021: $0.1m) increase in risk factor provision in respect of Egypt trade receivables.

 

During the year a total of $4.6m (2021: $8.3m) 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 (2021: $nil), $1.1m was set against trade payables (2021: $8.3m), $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

In December 2021, the company classified 55% of the Group's operated interest in each of our Egyptian Concessions, El Fayum and North Beni Suef, as Assets classified as held for sale (Net assets classified as held for sale as 31 December 2021: $53.5m).

An impairment of $10.4m was recognised to bring the value of the net assets classified as held for sale down to the fair value less costs to sell calculated as at 31 December 2021. 

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 following assets and liabilities were reclassified as held for sale in relation to the discontinued operation as at 31 December 2021: 

 

 

	2021 $ million
Intangible assets	2.1
Property, plant and equipment - oil and gas properties - NBV	61.6
Impairment charge - Assets classified as held for sale	(10.4)
Property, plant and equipment - oil and gas properties - after impairment	51.2
Property, plant and equipment - other - NBV	0.4
Inventories	6.3
Trade and other receivables	2.0
Assets classified as held for sale	62.0
Trade and other payables	(8.5)
Liabilities directly associated with assets classified as held for sale	(8.5)
Net assets classified as held for sale	53.5

 

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	13.9
Other receivable with IPR	0.5
Consideration received and to be received	55.7
Assignment fees payable to EGPC	(3.7)
Success fees paid on completion	(1.7)
Loss on disposal	(6.3)

 

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

The carry of $36.3m 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.

The carry decreases every month against the cash calls received from IPR. The total amount utilised as at 31 December 2022 amounts to $15.4m, which has been disclosed in "Consideration received on farm out of Egyptian assets" in the cash flow as part of investing activities (combined with $3.0m firm consideration received on 30 March 2022). No cash outflow is required until we utilise the whole amount.

The Group 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. As at 31 December 2022, the contingent consideration amounts to $13.9m ($5.0m current and $8.9m non-current). Testing of sensitivity for a $5/bbl reduction in long term oil price used would result in $1.3m decrease in contingent consideration to $12.6m.

The loss on disposal has increased by $0.5m from the position stated as at 30 June 2022 in the Company's interim financial statements. This is due primarily to a reduction of the amount classified as the carry element of the consideration from $37.0m to $36.3m 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. The reduction in the carry is partially offset by an increase in the amount classified as contingent consideration from $13.6m to $13.9m, reflecting the Group's entitlement to the full $5 million of the first tranche of the contingent consideration payable in respect of average Brent price during 2022.  

As at 31 December 2022, $3.7m relates to the assignment fee for the sale of 55% of the Group's operated interest in each of our Egyptian Concessions, El Fayum and North Beni Suef, to IPR. $0.5m Group's share of NBS Concession assignment bonus was settled against Trade Receivables. Out of the remaining $3.2m, $2.3m is booked as current other payable and $0.9m as non-current other payable.

The final consideration is still being finalised between IPR and Pharos. The financial exposure from finalising the consideration to Pharos, reflecting the remaining amounts still under discussion, is considered immaterial to the financial statements.   

 

15.  Preliminary results announced

Copies of the announcement will be available to download from www.pharos.energy. The Annual Report and Accounts, together with notice of the 2023 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 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.

									2022			2021
									$ million			$ million
Cost of sales									116.8			114.6
Less:
Depreciation, depletion and amortisation									(55.1)			(51.0)
Production based taxes									(14.7)			(10.1)
Export duty									(3.2)			-
Inventories									1.8			0.1
Trade receivable risk factor provision									(1.5)			-
Other cost of sales									(1.3)			(1.6)
Cash operating costs									42.8			52.0
Production (BOEPD)									7,166			8,878
Cash operating cost per BOE ($)									16.36			16.05

 

Cash-operating costs per barrel by Segment (2022)

 

												Vietnam			Egypt			Total
												$ million			$ million			$ million
Cost of sales												99.6			17.2			116.8
	Less: Depreciation, depletion and amortisation											(51.0)		(4.1)			(55.1)
	Production based taxes											(14.5)		(0.2)			(14.7)
	Export duty											(3.2)		-			(3.2)
	Inventories											1.6		0.2			1.8
	Trade receivable risk factor provision											-		(1.5)			(1.5)
	Other cost of sales											(0.8)		(0.5)			(1.3)
Cash operating costs												31.7			11.1			42.8
Production (BOEPD)												5,418			1,748			7,166
Cash operating cost per BOE ($)												16.03			17.40			16.36

 

 

 

 

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.

 

									2022			2021
									$ million			$ million
Depreciation, depletion and amortisation									(55.1)			(51.0)
Production (BOEPD)									7,166			8,878
DD&A per BOE ($)									21.07			15.74

 

 

DD&A per barrel by Segment (2022)

									Vietnam		Egypt		Total
									$ million		$ million		$ million
Depreciation, depletion and amortisation									(51.0)		(4.1)		(55.1)
Production (BOEPD)									5,418		1,748		7,166
DD&A per BOE ($)									25.79		6.43		21.07

 

 

 

Net Debt

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

									2022		2021
									$ million		$ million
Cash and cash equivalents										45.3	27.1
Borrowings 1									(74.2)		(84.6)
Net Debt									(28.9)		(57.5)

¹ Excludes unamortised capitalised set up costs

 

EBITDAX

EBITDAX is earnings from continuing activities before interest, tax, depreciation, amortisation, impairment of PP&E and intangibles, exploration expenditure and other/restructuring expense items in the current year.

									2022		2021
									$ million		$ million
Operating profit/(loss)										100.2	48.3
Depreciation, depletion and amortisation										55.2	51.4
Impairment reversal										(27.9)	(42.0)
EBITDAX									127.5		57.7

 

 

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.

									2022		2021
									$ million		$ million
Net Debt										(28.9)	(57.5)
EBITDAX										127.5	57.7
Net Debt/EBITDAX									(0.23)		1.00

 

 

Gearing

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

									2022		2021
									$ million		$ million
Total Debt 1										74.2	84.6
Total Equity										330.6	304.4
Debt to Equity									0.22		0.28

¹ Excludes unamortised capitalised set up costs

 

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.

 

									2022		2021
									$ million		$ million
Net cash from operating activities										53.4	10.8
Weighted number of shares in the year										439,253,641	437,512,648
Operating cash per share									0.12		0.02

 

 

 

 

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 or BOPD

Barrels of oil per day

 

cash

Cash, cash equivalent and liquid investments

capex

Capital expenditure

CEO

Chief Executive Officer

 

CNV

Ca Ngu Vang field located in Block 9-2, Vietnam

Company or Pharos

Pharos Energy plc

Contingent Resources or contingent resources

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

DP Semi-Submersible

Dynamic positioning semi-submersible drilling rig

 

E&P

Exploration & Production

EBITDAX

Earnings before interest, tax, DD&A, impairment of PP&E and intangibles, exploration expenditure and other/restructuring items in the current year

EGP

Egyptian Pounds, the lawful currency of the Arab Republic of Egypt

EGPC

Egyptian General Petroleum Corporation, an Egyptian state oil and gas company and the industry regulator

El Fayum or the El Fayum Concession

The concession agreement for petroleum exploration and exploitation entered into on 15 July 2004 between the Arab Republic of Egypt, EGPC and Pharos El Fayum in respect of the El Fayum area, Western Desert, as amended from time to time

 

Financial Statements

The preliminary financial statements of the Company and the Group for the year ended 31 December 2022

FPSO

Floating, production, storage and offloading Vessel

 

G&A

General and administration

GDP

Gross domestic product

GHG

Greenhouse gas

Group

Pharos and its direct and indirect subsidiary undertakings

 

H1

The first half of a calendar year

H2

The second half of a calendar year

 

HLJOC

Hoang Long Joint Operating Company, the operator of the TGT field on Block 16-1, Vietnam

HVJOC

Hoan Vu Joint Operating Company, the operator of the CNV field on Block 9-2, Vietnam

IFRS

International Financial Reporting Standards

IMF

The International Monetary Fund

IPR or IPR Energy Group

The IPR Energy group of companies, including IPR Lake Qarun and IPR Energy AG, or such of them as the context may require

IPR Lake Qarun

IPR Lake Qarun Petroleum Co, an exempted company with limited liability organised and existing under the laws of the Cayman Islands (registration number 379306), a wholly owned subsidiary of IPR Energy AG

 

JOC

joint operating company

JV

joint venture

 

km

kilometre

km²

square kilometre

LTI

Lost Time Injury

LTIF

Lost Time Injury Frequency

LTIP

Long Term Incentive Plan

m

million (where used to describe a monetary amount)

 

McDaniel

McDaniel & Associates Consultants Ltd

mmboe

million barrels of oil equivalent

NAV

Net asset value

NBE

The National Bank of Egypt, the largest Egyptian commercial bank and owned by the state of Egypt

NBS, North Beni Suef or the North Beni Suef Concession

The concession agreement for petroleum exploration and exploitation entered into on 24 December 2019 between the Arab Republic of Egypt, EGPC and Pharos El Fayum in respect of the North Beni Suef area, Nile Valley

 

OCF

Operating cash flow

opex

Operational expenditure

 

PEF

Pharos El Fayum, a wholly owned subsidiary of the Company holding the Group's participating interest in El Fayum and North Beni Suef

Petrosilah

An Egyptian joint stock company held 50/50 between EGPC and the Contractor parties (being IPR Lake Qarun and PEF following completion of the farm-down of the El Fayum Concession)

Petrovietnam

Vietnam Oil and Gas Group, the Vietnamese state-owned integrated oil and gas company

PP&E

Property, plant and equipment

Prospect or 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

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 Group's shares access to the FPSO used for TGT production

 

UK

United Kingdom

USD or US dollars

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

 

$

United States Dollar

£                                                                                                                                   

UK Pound Sterling

1C

Low estimate scenario of Contingent Resources

1P

Equivalent to proved Reserves; denotes low estimate scenario of Reserves

2C or 2C Contingent Resources

Best estimate scenario of Contingent Resources

2P Reserves or 2P Commercial Reserves

Equivalent to the sum of proved plus probable Reserves; denotes best estimate scenario of Reserves

3C

High estimate scenario of Contingent Resources

3P

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