27 March
2024
Pharos
Energy plc
("Pharos" or the "Company" or, together with its
subsidiaries, the "Group")
2023 Preliminary
Results
Pharos Energy plc,
an independent energy company,
announces its preliminary results for the year
ended 31 December 2023. A conference call for analysts will take
place at 11.00 GMT today.
Jann Brown, Chief Executive Officer,
commented:
"Pharos delivered on several fronts in 2023, laying the
groundwork for significant momentum going into 2024. The Group had
drilling success both in Vietnam, with the CNV production well
coming in strongly, and in Egypt, with two discoveries from
exploration wells on NBS and El Fayum. On Block 125, parallel
discussions with several potential farm-in partners are ongoing and
we are actively working with another operator in the region to
enhance our efforts in securing a suitable rig.
"We have managed the challenges of payment delays in Egypt,
thanks in part to our carry, but also by careful cost control and
capital discipline. We ended the year in a strong financial
position with net debt down to $6.6m and cash balances of $32.6m,
from revenues of $168.1m. We are also delighted that we have now
received $10m from EGPC, as they resume payments to foreign oil
companies on the back of the substantial support packages committed
to Egypt, putting us into a net cash position today. A strong
balance sheet provides us with the foundation to continue our track
record of delivering shareholder returns, adding $8.4m through a
combination of share buyback programmes ($2.8m of which was
completed in 2023) and dividend payments in 2023.
"Today, the Board have recommended a final dividend for the
2023 financial year of 0.77 pence per share, subject to
shareholders' approval at the Company's 2024 AGM. This would take
the 2023 full year dividend to 1.10 pence per share, an increase of
10% on the prior year.
"Looking ahead, we are advancing plans to drill the
potentially transformational Block 125 in Vietnam, and we look
forward to updating shareholders on progress. In the meantime, we
continue to execute on our strategy, including continuing on our
recently published roadmap to net zero, of delivering value for all
stakeholders in 2024 and beyond."
2023 Operational Highlights
· Group working interest 2023 production was 6,508 boepd net
(2022: 7,166 boepd net), in line with 2023 guidance:
- Vietnam 5,127 boepd (2022: 5,418 boepd)
- Egypt 1,381 bopd (2022: 1,748 bopd)
· In
Vietnam:
- Strong performance from first new CNV lateral well, put on
production in 1Q 2023
- CNV Revised Field Development Plan (RFDP) submitted to
partners for approval, with discussions ongoing
- Continuing positive feedback received from PetroVietnam and
the Ministry of Industry and Trade (MOIT) on five-year extension
proposals to the TGT & CNV licences
- On Blocks 125 & 126, two-year PSC extension granted to 8
November 2025
- Competent Person's Report (CPR) for Block 125 published in
July 2023, confirming a range of gross unrisked prospective oil
resources of between 1,178 MMstb (1U) and 29,785 MMstb (3U) with a
Mean value of 13,328 MMstb
· In
Egypt:
- Three new wells (2 producers and 1 injector) put on
production and injection in 2023, in line with pre-drill
expectations
- On El Fayum, exploration success with the first commitment
well in the Abu Roash G and Upper Bahariya formations in July 2023.
The well is set up for re-entry and testing in 2024
- On North Beni Suef (NBS), first exploration commitment
well (NBS-SW1X) declared a commercial
discovery and put on production in
December 2023, opening up a new area for production and
development
- Approval received from EGPC in September 2023 for the grant
of a 20-year development lease for NBS-SW1X
- 3D seismic survey acquired on time and on budget in 2H
2023
2023 Financial Highlights
· Group revenue of $168.1m 1,2 (2022: $221.6m
1,2)
· Cash
generated from operations $88.8m (2022: $110.7m)
· Operating cash flow $44.9m 3 (2022:
$53.4m)
· Cash
operating costs of $15.70/bbl 4 (2022: $16.36/bbl
4)
· Cash
balances as at 31 December 2023 of $32.6m (2022: $45.3m)
· Net
debt as at 31 December 2023 of $6.6m 4,5 (2022: $28.9m
4,5)
· Loss
for the year of $48.8m (2022: profit $24.4m)
· Net
debt to EBITDAX of 0.06x 4 (2022: 0.23x
4)
2024 Outlook and Highlights
· Group working interest production guidance of 5,200 - 6,500
boepd net:
- Vietnam 3,900 - 5,000 boepd
- Egypt 1,300 - 1,500 bopd
· In
Vietnam:
- TGT RFDP approved by MOIT on 9 January 2024
- Planning underway for a two-well TGT drilling programme,
expected to commence 2H 2024
- On Block 125, ongoing discussions with another operator to
secure a well drilling slot during their multi-well drilling
programme in the region
- Parallel discussions with several potential farm-in partners
for Block 125 in progress
· In
Egypt:
- Continuation of modest and measured approach to capital
allocation and drilling in El Fayum and NBS, with potential to ramp
up activity this year and beyond in response to the improving
economic environment
- Focus for this year's work programme in El Fayum is low-cost
recompletions and waterflood
- Processing and interpretation of c.130km2 of 3D
seismic data on NBS is underway and expected to be completed in 2H
2024
- Development drilling in the NBS SW field planned to start in
2H 2024
- Ongoing engagement with EGPC regarding payment of
receivables, and more favourable outlook following $57 billion
support packages
- Concession terms in Egypt being reviewed following award of
20-year development lease over NBS
· Forecast Group cash capex in the year is expected to be $32m
($27.1m after Egyptian carry by IPR)
· Egypt cash opex and capex expected to be substantially funded
in EGP from historical receivables
· Notification of $10m to be received today from EGPC in USD
against receivable balance following payment delays through
2023
· Continuation of share buyback programme, with a further $3m
committed for 2024
· Interim dividend in relation to the financial year ending 31
December 2023 of 0.33 pence per share, amounting to $1.7m, paid out
on 24 January 2024. Final dividend of 0.77 pence per share for the
year to be paid on 19 July 2024, subject to shareholder
approval
· Appointment of Dr Bill Higgs as a new independent
Non-Executive Director
· Jann
Brown to retire and step down from the Board, effective 30 April
2024
· Appointment of Shore Capital Stockbrokers Limited (Shore
Capital) as the Company's joint broker
1 Egyptian revenues are stated post government take including
corporate taxes
2 Stated prior to realised hedging loss of $0.2m (2022: loss of
$22.5m)
3 Operating cash flow = Net cash from
operating activities, as set out in the Cash Flow
Statement
4 See Non-IFRS measures on page 39
5 Includes RBL and National Bank of Egypt working capital
drawdown
Enquiries
Pharos Energy
plc
Tel: 020 7747 2000
Jann Brown, Chief Executive
Officer
Sue Rivett, Chief Financial
Officer
Camarco
Tel: 020 3757 4980
Billy Clegg | Andrew Turner |
Rebecca Waterworth | Kirsty Duff
Notes to editors
Pharos Energy plc is an
independent energy company with a focus on sustainable growth and
returns to stakeholders, which is listed on the premium segment of
the London Stock Exchange. Pharos has production, development
and/or exploration interests in Egypt and Vietnam. In Egypt, Pharos
holds a 45% working interest share in the El Fayum Concession in
the Western Desert, with IPR Lake Qarun, part of the international
integrated energy business IPR Energy Group, holding the remaining
55% working interest. The El Fayum Concession produces oil from 10
fields and is located 80 km southwest of Cairo. It is operated by
Petrosilah, a 50/50 joint stock company between the contractor
parties (being IPR Lake Qarun and Pharos) and the Egyptian General
Petroleum Corporation (EGPC). Pharos also holds a 45% working
interest share in the North Beni Suef (NBS) Concession in Egypt,
which is located immediately south of the El Fayum Concession. The
first development lease on the NBS Concession was awarded in
September 2023 and production started in December 2023. IPR Lake
Qarun holds the remaining 55% working interest in the NBS
Concession, with development operations on the Concession currently
undertaken by Petrosilah on behalf of the newly formed joint
operating company, Petro Beni Suef. The first exploration phase
under the NBS Concession expired in March 2024 with all work
programme commitments completed. In Vietnam, Pharos has a 30.5%
working interest in Block 16-1 which contains 97% of the Te Giac
Trang (TGT) field and is operated by the Hoang Long Joint Operating
Company. Pharos' unitised interest in the TGT field is 29.7%.
Pharos also has a 25% working interest in the Ca Ngu Vang (CNV)
field located in Block 9-2, which is operated by the Hoan Vu Joint
Operating Company. Blocks 16-1 and 9-2 are located in the shallow
water Cuu Long Basin, offshore southern Vietnam. Pharos also holds
a 70% interest in, and is designated operator of, exploration
Blocks 125 & 126, located in moderate to deep water in the Phu
Khanh Basin, north east of the Cuu Long Basin, offshore central
Vietnam.
Chair's
Statement
A year of good
performance
2023 has been a year characterised
by good operational and financial performance across the
Group.
Throughout the portfolio, the
team's focus on operational delivery was evidenced by good drilling
performance in both Vietnam, with the CNV well coming in strongly,
and in Egypt, with discoveries on both the El Fayum and NBS
exploration wells. We have continued to build on a culture of
capital discipline to deliver material improvement to the Group's
balance sheet despite ongoing payment lags in Egypt. This
performance has allowed the Board to continue our commitment to
sustainable shareholder returns in 2023, a core component of the
Company's strategy since its listing in 1997.
These achievements are a testament
to the hard work, dedication, and commitment of the entire Pharos
team. I would like to congratulate all of my colleagues on a year
of good performance which has positioned Pharos for a positive and
sustainable future, with strong operational momentum, a robust
capital structure, and exciting growth
opportunities.
Board
changes
Over the past year, I have greatly
appreciated the support of my fellow Board members and the diverse
skillsets that they bring to the table. Since joining Pharos in
2019, I have overseen the reshaping of the Board to ensure we meet
stakeholders' expectations to ensure an independent Board that
provides high standards of governance and oversight to support our
long-term strategic framework. As such, I am delighted that Bill
Higgs has joined the Pharos Board as an Independent Non-Executive
Director. Bill is a very high calibre appointment, bringing a
wealth of technical and commercial experience. His initial focus
will be to maximise value from our exciting exploration prospects
in Vietnam Blocks 125 & 126.
It is with great sadness that I
note the death of Ed Story in December 2023. Ed founded the Company
in 1991 and had been pivotal to the Company and its business from
inception, specifically its listing in London in 1997 and its
subsequent foray into a dozen different countries. Since retiring
as CEO in March 2022, Ed had remained active as part of the
Company's team in Vietnam. His responsibilities will now pass to
Vincent Duignan, the Group Exploration Manager & General
Manager South East Asia.
Jann Brown has informed the Board
of her intention to retire and step down from the Board effective
30 April 2024, in a separate announcement today. The search for a
replacement CEO will commence shortly and Jann has agreed to stay
in her position as CEO to effect a managed and smooth transition. I
would like to take this opportunity to thank Jann for her
significant contribution to Pharos over the years. Jann will be
leaving the Company in a strong position, both financially and
operationally. We wish Jann well in her retirement.
A diverse and inclusive
culture
Pharos is proud of our small yet
diverse workforce, whose broad range of backgrounds, ethnicities,
skills and experience help strengthen the Company for the future.
As at year end, I am pleased to report that the Company has four
female Directors, representing two thirds of the Board. Most
notably, our UK-based staff comprises 17 people from 10 different
nationalities, of which women accounted for c.65%. We operate in a
global industry, and it is important to ensure that we benefit from
the diverse perspectives that our people bring.
The Board and Management team are
dedicated to creating a safe workplace for all, in which people are
confident to engage and contribute. The opening up of the world
post COVID-19 has allowed the Board to meet in person and engage
meaningfully with our colleagues across the world. In June 2023,
the Company organised an off-site day where colleagues from Egypt,
Vietnam and the UK met in London to exchange business ideas,
provide feedback and promote team-building. This is important not
only for the effective functioning of the Board, but also to
develop and empower all employees, underpinning our commitment to
maintaining high standards of governance.
We recognise that 2023 has seen
significant geopolitical instability, something that has had
far-reaching impacts on communities and families, the global
economy, and trade. Our thoughts remain with those who have been
affected by the active conflicts in Ukraine and the Middle East. We
continue to support our colleagues and contractors during this
difficult time, as well as ensuring that our business can continue
to function unaffected.
Ongoing dialogues with
stakeholders
Pharos' operational success and
long-standing partnerships, spanning over 25 years, are built on a
culture of transparency and integrity. Since joining the Board,
Jann and I have maintained regular dialogues with local
governments, joint-operating partners, local communities, and
shareholders to ensure the Board is well-informed as the Company
develops its plans for growth.
In November 2023, the Board held a
Strategy Day to focus on where and how we can offer value to our
stakeholders, with inputs from a number of key parties, experts and
shareholders. The results of our Strategy Day reinforced our
commitment to pursue a combination of cash returns per share and
reinvestment to enhance our asset base - a strategy regularly
communicated back to our stakeholders. In November, Jann and I also
met with the Vietnamese Minister of Industry and Trade to discuss
the proposed licence extensions on our assets in country,
highlighting the important benefits that these bring, not just to
Pharos but also to Vietnam.
The Board and its management team
will continue to engage in a personal and meaningful way with our
various stakeholders in 2024 and beyond. We are grateful to our
shareholders whose support during times of uncertainty have been
crucial to our growth and transformation throughout the
years.
Making a positive
difference
Recent events in 2023 have shown a
need for better and more balanced energy systems worldwide,
delivering energy that is not only lower carbon, but also reliable
and affordable for developed and emerging nations alike. The
outcomes of COP28 in December 2023 highlighted the importance of
energy and climate security, and I firmly believe that responsible
production and development of oil and gas resources, especially in
economies transitioning from heavy reliance on coal such as Egypt
and Vietnam, can be a major driver for economic development and
alleviating energy poverty. Our host governments understand and
appreciate Pharos' in-country impact that goes beyond national
revenues from oil and gas production. In light of our strong
relationships, local governments have encouraged Pharos to look
into opportunities across other branches of the energy sector in
their countries. We recognise a diverse mix of energy resources is
crucial for long-term energy security, and we appreciate our host
nations' trust in us and the long-term role that we play in their
countries' energy transition.
While it is clear that there are
emerging opportunities across the energy sector, our first priority
is improving our emissions footprint by enhancing our own
operational efficiency. I am proud of the progress that we have
made on our Net Zero journey. In December 2023, Pharos published a
detailed Net Zero Roadmap to achieve net zero GHG emissions by
2050. The Net Zero Roadmap, which was researched and developed by
the Company in close consultation with specialist advisors and
consultants, models emission reduction pathways to achieve net zero
Scope 1 (direct) and Scope 2 (indirect) GHG emissions from all
existing and proposed future assets by 2050 or before. We look to
reduce our emissions over the years and remain committed to
transparency in our sustainability journey.
Social stewardship is at the heart
of our sustainability journey. In 2023, we supported a record 22
community investment projects across Egypt, Vietnam, and the UK,
investing a total of $247,373 in education, training, healthcare
and infrastructure in our local communities. Pharos remains
committed to deploying our expertise and capital to partner with
host governments to develop local capacity, enhance energy security
and unlock value from our host nations' natural resources in an
environmentally sustainable and socially responsible
manner.
Outlook
Jann and her team continued to
deliver on the Company's strategy in 2023 and built on our track
record of sustainable shareholder returns. Focusing on a clear
growth strategy and disciplined capital management approach, we
will continue to deliver regular returns to shareholders whilst
growing the value of our company.
As Chair, I would like to thank
the Pharos team for their commitment and delivery through the year.
I am also grateful to our host nations and communities for their
continued trust, our shareholders for their confidence, and our
partners, suppliers and advisors for their support. We have created
a portfolio of assets and set of capabilities which are unique
within our sector, and the Board looks to the future with great
confidence in our ability to deliver growth and value in 2024 and
beyond.
John Martin
Non-Executive Chair
Chief Executive Officer's
Statement
Commitment to adding
value
Pharos delivered on several fronts
in 2023. Throughout the year, the Board and senior management team
maintained a clear focus on capital discipline to strengthen our
financial position and enhance existing opportunities within our
portfolio. We put the funding of our established dividend programme
at the heart of our business model, and it is through this lens
that we assess our capital allocation goals. We are determined to
balance regular returns to shareholders with investment in our
assets to generate sustainable growth, and value per share whilst
preserving balance sheet resilience.
Our investment programme in
2023
We have managed the challenges of
payment delays in Egypt, thanks in part to our carry, but also by
strict cost control and capital discipline. We ended the year in a
strong financial position with net debt down 77% to $6.6m and cash
balances of $32.6m, from revenues of $168.1m. A stronger balance
sheet provides the foundation to continue our track record to
deliver shareholder returns, adding $8.4m this year through a
combination of share buyback programmes and dividend payments. As
at year end 2023, we are proud to have returned a total of $537.6m
to shareholders.
Our assets are the foundation of
our returns and during the year, we made progress on a number of
opportunities within the portfolio. In Vietnam, we continued to
deliver a high netback and stable production during the year.
Production in 2023 from the TGT and CNV fields averaged 5,127
boepd, in line with guidance, with delivery from the first CNV
lateral well coming in above expectations in the first half. The
approval of the TGT RFDP from MOIT in January 2024 was the final
step towards the commencement of a two-well TGT drilling programme,
which is expected to start in the second half of this year. On the
exploration side, the publication of the independent report
prepared by ERCE on Blocks 125 & 126 further highlights the
world-class scale and potential in these basin-opening exploration
blocks, confirming 13,328 MMstb of mean
gross unrisked prospective oil resources. With the exploration
period of the PSC now extended to November 2025, Pharos is well
placed to source a rig, bring in a farm-in partner and complete all
necessary work to drill the first exploration well on this exciting
opportunity.
In Egypt, discretionary investment
has been modest, and focused on delivering a steady performance
from El Fayum, averaging 1,381 bopd, in line with guidance. We also
ensured that our commitments to host governments were fulfilled.
Most notably, the Group drilled two exploration wells, one on each
of the North Beni Suef and El Fayum Concessions, with drilling
successes on each of these. The NBS-SW1X exploration commitment
well was declared a commercial discovery and put on production only
nine months after drilling, following the grant of a 20-year
development lease in September 2023. This was a crucial first step
towards proving up this new reserve base and adding further barrels
to overall Group reserves and subsequently production. The reforms
recently announced by the Egyptian government, plus the
international funding packages totalling together $57 billion, set
out the path for Egypt's economic recovery and the restoration of
sustainable, inclusive growth. In the early stages of these
reforms, the JV will maintain a measured approach to capital
allocation and drilling in Egypt in 2024. However, we recognise
that it is important to be fully prepared to increase our
investment levels once payments for oil production reach a more
regular pattern.
The health and safety of our
workforce remains our highest priority. We are committed to
operating safely and responsibly at all times. Pharos continued to
have an excellent safety record during 2023, and I am pleased to
highlight that the Company reported zero LTIs across the Group. In
particular, in Vietnam, this is an achievement that we have
maintained since 1997 thanks to the JOCs' consistent efforts to
provide and champion workers' health, safety, and well-being. We
are careful to maintain this achievement going into
2024.
Our stable operational performance
in 2023 has laid a solid foundation for the 2024 work programme to
further develop growth potential in our assets. Underpinned by a
strong balance sheet and steady production base across the
portfolio, Pharos is in a good position to execute our strategy of
delivering sustainable value through a focus on organic and
inorganic growth opportunities, coupled with our commitment to
regular shareholder returns.
A clear focus on our
strategic priorities
1. Regular shareholder returns
At Pharos, we have a firm
commitment to add sustainable shareholder value, and both the means
and discipline to do it. We established a sustainable shareholder
return framework via share buybacks and dividends, as part of the
return mix that we can control. Dividends have been a key part of
the Company's equity story since its listing and, following
approval at the 2023 AGM, we returned $5.6m to shareholders via a
single dividend for the 2022 financial year of 1 pence per share.
In December 2023, an interim dividend of 0.33 pence per share, or
$1.7m equivalent, was paid in January 2024. Our dividend policy is
set in a clear formula, returning no less than 10% of operating
cash flow (OCF) and takes into account volatility in the market
such as movements in commodity prices, tax, and working capital
movements. Today, the Board have recommended a final dividend for
the 2023 financial year of 0.77 pence per share which, subject to
shareholders' approval at the Company's 2024 AGM, would take the
2023 full year dividend to 1.10 pence per share, an increase of 10%
on the prior year. In addition, we announced in December 2023 the
continuation of our share buyback programme, with a further $3m
committed for 2024. This is another way for Pharos to return value
to shareholders and to enhance NAV, earnings and dividends per
share to shareholders over time.
2. Cash flow protections
Prudent financial management is a
core part of our corporate DNA. Our focus on capital discipline
through careful cost management and control has resulted in
material net debt reduction in recent years. We maintain a balance
of hedged and free-floating Group production, with less than 30% of
the Group's 2024 production hedged at 31 December 2023, thus
providing material exposure to the oil price. Pharos also operates
in two very different jurisdictions which provides diversification
and resilience in a volatile world. In particular, we are proud of
our consistent payment record in Vietnam, with TGT & CNV crude
commanding an impressive premium to Brent of just under $7/bbl in
2023, a significant improvement from the prior year's $4/bbl. This
has been driven by improvements in oil prices and our three-year
sales contract for all TGT crude oil cargoes with BSR, which
provides benefits in delivering into the local economy and reducing
logistical spend as well as output tax savings. Additionally, to
mitigate the impact of payment issues in Egypt, we have a working
capital facility with the National Bank of Egypt (UK) to smooth out
payment cycles there. Our receivables balance has built up in part
due to the benefit of the carry we have had over all JV expenditure
in Egypt, leaving us with in-country corporate costs only, and
partly due to our position of not drawing down the balance in local
currency. With the carry expiring in 1Q 2024, we intend to use this
receivables balance to fund the majority of the JV expenditure
going forward. As our dividend policy is based on the resilience of
our operating cash flow, we maintain a strict capital control
framework to protect our cash flows.
3. Diverse opportunity sets
We have a portfolio of organic
growth opportunities in both Vietnam and Egypt, with options
continuously being explored and development work progressed to
maximise the potential of these complementary assets. In Vietnam, a
variety of interesting leads and prospects have been identified on
Block 125, a unique deep-water frontier exploration opportunity. We
are in active parallel discussions with several parties interested
in farming-in to support the funding of a commitment well on this
Block and engaging with another operator to secure a well drilling
slot during their multi-well drilling programme in the region. In
Egypt, the exploration successes in both the North Beni Suef and El
Fayum Concessions, complemented by the 20-year development lease on
NBS-SW1X, added significant value to our low-cost Egyptian asset
base and bode well for future growth.
We keep our assets under review to
ensure that they are delivering the expected value and will look to
monetise if we can accelerate this. As we maintain a firm handle on
our existing portfolio, we are also considering inorganic
opportunities. We actively look for opportunities to generate
additional value and cash flow for our shareholders. We have a
highly competent and dedicated team with strong industry relations
to assess these in a disciplined and systematic manner.
Net Zero and our role in the
energy transition
As Pharos explores these
opportunities, we remain focused on the role we play in the
socio-economic development of our host countries. We believe that
oil and gas companies like Pharos, with our commitment to producing
safely and responsibly, a wealth of industry expertise, and a
strong balance sheet, will continue to play an important part in
the energy transition, especially in emerging economies. In our
dialogues with our host governments, we note their recognition of
the importance of our operations and investments to their energy
security and prosperity. We are encouraged to keep investing in
their countries to ensure that they benefit from their natural
resources as have many other nations, particularly in the developed
world. This is exactly what we have done in 2023, having committed
to the domestic sale of 100% of oil and gas produced from our
producing assets in both Egypt and Vietnam during the
year.
The critical role of upstream
producers in the energy supply chain also opens opportunities to
add value through the integration of other alternative energy
resources, both to improve upstream efficiency and for standalone
cash generation.
Pharos strengthened our commitment
to net zero in 2023. We took another step in maturing our net zero
strategy by publishing our Net Zero Roadmap in December, which
provided further clarity in our pathway towards our 2050 climate
commitment. The Net Zero Roadmap, which was researched and
developed by the Company in close consultation with specialist
advisors, established decarbonisation levers and interim targets to
reduce our 2030 emissions by 15% against baseline 2021 emission.
Additional information about our decarbonisation strategy, Emission
Management Fund, and climate governance structure are included in
our Net Zero Roadmap, which is available to download on our
website.
We recognise that the path to net
zero will not be straightforward, as it will take time to implement
certain decarbonisation technologies and require pragmatism from
our local partners, governments, and other stakeholders.
Nevertheless, we are committed to our climate goals and will
navigate our net zero journey in an honest and transparent manner,
true to our corporate values of the 'The Pharos Way': Safety &
Care, Energy & Challenge, Openness & Integrity, Empowerment
& Accountability, and Pragmatism & Focus.
Our relationships with
stakeholders
'The Pharos Way' drives not only
our attitude towards sustainability and net zero, but also the way
we build and maintain our relationship with stakeholders. We were
greatly encouraged by the open and receptive dialogues we had with
key stakeholders during the year.
In January 2023, the Company held
a lunch to engage with analysts, both those providing research on
the Company and those that do not, to foster relationships with key
figures in the industry. During the year, we have met key
individuals representing Regulators and Government in both Egypt
and in Vietnam. We also engage regularly and meaningfully with the
investment community and debt providers through multiple roadshows,
meetings, live presentations, and Q&A sessions. We remain
actively engaged with our joint venture partners and regularly
participate in budget reviews, work programme discussions, and
Management Committee meetings throughout the year. The Board and
management team work hard to ensure we meaningfully engage with the
whole workforce at various points during the year, as previously
discussed in the Chair's Statement.
The supportive relationship that
exists between Pharos and its different groups of stakeholders is a
key building block to the successful delivery of our strategy, and
we will continue to build on these collaborative relationships in
2024 and beyond.
Outlook
Although 2023 brought continued
uncertainties, Pharos rose to these challenges and delivered a
stabilised asset base set for growth, a more resilient balance
sheet, well-protected cash flows, and an exciting mix of
opportunities to pursue in 2024.
Finally, the significant change in
the outlook for the Egyptian economy means that the most turbulent
years look to be behind us. I have therefore decided that this is
the right time for me to step down and hand over the baton to
someone who will lead that next phase.
With capital discipline in our
DNA, a clear set of strategic objectives, a portfolio of
complementary assets, a strong financial position, a dedicated and
diverse workforce, a committed Board and bench strength across the
management team, the company has started 2024 well positioned to
deliver long-term sustainable value for all and my successor will
be chosen to take that to the next level.
I would like to take this
opportunity to thank all our stakeholders for their ongoing support
and our employees for their hard work, commitment and tenacity. I
am confident in our ability to execute our strategy and look
forward to steering Pharos on a path towards a new phase of growth
and shareholder returns.
Jann Brown
Chief Executive Officer
Chief Financial Officer's
Statement
Financially
strong
I am pleased to report strong
financial performance from our operations and a strengthening of
our liquidity position, with net debt down 77% to $6.6m at the end
of the year. We have returned a 7% yield, or $8.4m, to shareholders
in the form of dividends and share buybacks and invested $26.7m in
our asset base, all while paying down $35m of debt. This is despite
a backdrop of reduced commodity prices and delays in payment for
our Egyptian sales. In Egypt, we generated $2.5m of free cash
during the year from a combination of receipts from our sales,
receipt of the contingent consideration and the carry from our
prior year farm out to IPR.
Our finance strategy continues to
support our commitment to building shareholder value through
organic growth and sustainable returns to shareholders.
We are in a net cash position as
of today and, as we move out of the carry period on our Egyptian
concessions, we look forward to drawing down on our receivables
balance with EGPC to support our ongoing operations and capital
investment in El Fayum and our new 20-year development lease at
North Beni Suef.
Today, I am delighted to confirm
the receipt of $10m in USD of our outstanding receivables, which
equates to 26.7% of the year end balance.
Operating performance
Revenues
Group revenues of $168.1m, prior
to realised hedging loss of $0.2m (2022: $221.6m prior to realised
hedging loss of $22.5m) were negatively impacted by a 17% decrease
in realised commodity prices.
Revenues for Vietnam of $149.2m
(2022: $184.8m) decreased year on year as a result of lower
realised prices and a reduction in sales volumes due to timing of
cargoes. The average realised crude oil
price was $87.42/bbl (2022: $106.44/bbl), an 18% decrease year on
year, and the premium to Brent was just under $7/bbl on average
(2022: over $4/bbl). Production was lower at 5,127 boepd (2022:
5,418 boepd). In October 2023, the Company and its partners
signed a three year sales contract for all TGT crude oil cargoes
with BSR to cover the period 1 January 2024 to 7 December 2026.
This agreement supports energy security in-country and eliminates
export duty being paid on cargoes, plus enables the JOC to recover
input VAT. The premium to Brent will continue to be agreed every
six months, which provides the Group with significant downside
price protection for production from our largest Vietnam
field.
The revenue for Egypt of $18.9m
(2022: $36.8m, which includes an additional $7m following the
improvement in the fiscal terms with the Third Amendment to the El
Fayum Concession, increasing cost recovery oil from 30% to 40% from
November 2020) decreased largely due to lower average realised
crude oil price, down 19% to $78.18/bbl (2022: $96.03/bbl). On an
equivalent basis, 45% working interest for the full year and after
excluding additional revenues from the Third Amendment, 2022
revenues were $24.0m. Production fell to 1,381 bopd (2022: 1,748
bopd, following the farm-down of 55% interest and transfer of operatorship of the Group's Egyptian assets
to IPR completed on 21 March 2022). There
are two discounts applied to the El Fayum crude production - a
general Western Desert discount and one related specifically to El
Fayum. Both are set by EGPC and combined stayed consistent at over
$4/bbl for the year (2022: over $5/bbl).
Hedging
For 2023, Pharos entered into zero
cost collar hedges to protect the Brent component of forecast oil
sales and to ensure future compliance with its obligations under
the RBL over the producing assets in Vietnam and to provide
downside protection to cash flows in the event of commodity price
falling. The commodity hedges run until June 2025 and are settled
monthly. Our hedging positions for the year resulted in a small
$0.2m realised loss (2022: loss of $22.5m).
During 2023, 36% of the Group's
total oil entitlement production was hedged, securing average floor
and ceiling prices for the hedged volumes at $64.5/bbl and
$100.8/bbl, respectively. The Group's RBL requires the Company to
hedge at least 35% of Vietnam RBL production volumes and the
current hedging programme meets this requirement through to
December 2024, leaving 72% of Group production unhedged as at 31
December 2023.
Please see below a summary of
hedges outstanding as at 31 December 2023, which are all zero cost
collar.
|
|
1Q24
|
2Q24
|
3Q24
|
4Q24
|
1Q25
|
2Q25
|
Production hedge per quarter -
000/bbls
|
|
120
|
120
|
150
|
120
|
60
|
60
|
Min. Average value of hedge -
$/bbl
|
|
63.00
|
63.00
|
64.40
|
63.00
|
64.00
|
64.00
|
Max. Average value of hedge -
$/bbl
|
|
91.50
|
87.88
|
88.66
|
89.00
|
90.00
|
90.00
|
|
|
|
|
|
|
|
|
|
Operating costs
Group cash operating costs,
defined in the Non-IFRS measures section on page
39, were $37.3m (2022: $42.8m). Vietnam
decreased by 9% from $31.7m to $28.8m in 2023, the equivalent of
$15.39/bbl (2022: $16.03/bbl). The
decrease is due to lower costs relating to the FPSO as a result of
higher 3rd party production throughput from the TLJOC,
which decreased the HLJOC's share of the costs (TLJOC had 23.2%
cost share in 2023 compared to 14.5% in 2022). In addition, for 1H
2022, there was $3.2m of export duty paid on TGT oil cargoes, which
in 2023, we were not required to pay due to the oil being sold into
the local economy.
Cash operating costs in Egypt were
$8.5m in 2023 (2022: $11.1m), which equates to $16.86/bbl (2022:
$17.40/bbl). The 3% decrease in cash operating costs per barrel was
mainly related to decreases in transportation and fuel costs per
bbl together with decreases in the fixed costs due to the
devaluation of EGP against the USD during
the year. Cash
operating costs from 1 January 2022 up to 20 March 2022 were 100%
share and from 21 March 2022 included only the Group's remaining
45% share. On a 100% equivalent basis, the
cash operating costs for 2023 were $19.2m (2022:
$19.3m).
DD&A
Group DD&A associated with the
producing assets increased marginally to $55.4m (2022:
$55.1m) driven by a higher depreciating
cost base following December 2022 impairment reversals taken on
both Vietnam and Egypt, partially offset by the 9% decrease in
production year on year and lower DD&A rates per barrel from
July following the net impairment charges taken on Vietnam and
Egypt assets in June 2023.
DD&A per bbl is currently
$27.25/boe for Vietnam (2022: $25.79/boe). DD&A per bbl for
Egypt is $8.73/boe for the full year production entitlement (2022:
$6.43/boe).
Administrative expenses
Administrative expenses in 2023 of
$9.0m (2022: $10.0m) were lower than prior year. After adjusting
for the non-cash items under IFRS2 Share Based Payments of $0.9m
(2022: $1.3m) and project costs associated with new commercial
opportunities of $0.4m (2022: $nil), the underlying administrative
expense is $7.7m (2022: $8.7m).
Operating (loss)/profit
Operating profit from continuing
operations for the year was $47.3m
(2022: $72.3m) excluding the net
impairment charge of $65.4m (2022: $27.9m net impairment reversal),
reflecting the combined impact of a lower commodity price
environment throughout the year and a decrease in production
volumes.
Other/restructuring expenses, loss on disposal and
(loss)/gain on fair value movement of financial
asset
Other/restructuring expenses for
the year of $0.6m (2022: $0.8m) were due to changes in the best
estimate of the adjustment relating to the interim period between
the economic date of 1 July 2020 and the completion date of the
disposal of 55% interest in the Egypt concessions. 2022 included
restructuring costs for both the head office in London and the
Egypt office in Cairo ($0.1m). In addition, for 2022, there was a
$0.7m charge relating to the premium on the transfer of the lease
on the London office.
Loss on disposal in 2022 of $6.6m
is related to the farm-down transaction, where 55% of the Group's
operated interest in each of our Egyptian Concessions, El Fayum and
North Beni Suef, acquired by IPR on 21 March 2022.
Pharos is entitled to contingent
consideration depending on the average Brent price each year from
2022 to the end of 2025 (with floor and cap at $62/bbl and
c.$90/bbl respectively). The contingent consideration is calculated
yearly and is capped at a maximum total payment of $20.0m (please
refer to Note 14 for further details). From 2023, the variance of
the contingent consideration is booked under (loss)/gain on fair
value movement of financial asset.
The loss on fair value movement of
financial assets for the year of $0.3m (2022: $0.3m gain)
is due to $0.4m revision of the contingent
consideration, partially offset by $0.1m reduction in contingent
liability (assignment fee).
Finance costs
Finance costs decreased to $10.2m
(2022: $12.7m), mainly related to a charge of $2.7m following a
change in estimated future cash flows following the December 2023
RBL redetermination and amortisation of capitalised borrowing costs
of $(1.4)m (2022: charge of $2.6m and amortisation of capitalised
borrowing costs of $1.5m). There was interest expense payable and
similar fees of $6.4m charged on the RBL and NBE (2022: $6.1m),
unwinding of discount on Vietnam decommissioning provisions of
$2.0m (2022: $1.3m) and foreign exchange losses of $0.5m (2022:
$1.2m) primarily driven by devaluation of EGP against
USD.
Cash operating cost per barrel*
|
2023
$m
|
2022
$m
|
Cost of sales
|
111.2
|
116.8
|
Less
|
|
|
Depreciation, depletion and
amortisation
|
(55.4)
|
(55.1)
|
Production based taxes
|
(10.5)
|
(14.7)
|
Export duty
|
-
|
(3.2)
|
Inventories
|
(4.0)
|
1.8
|
Trade Receivable risk factor
provision
|
(2.2)
|
(1.5)
|
Other cost of sales
|
(1.8)
|
(1.3)
|
Cash operating costs
|
37.3
|
42.8
|
Production (BOEPD)
|
6,508
|
7,166
|
Cash operating cost per BOE
($)
|
15.70
|
16.36
|
DD&A per barrel*
|
2023
$m
|
2022
$m
|
Depreciation, depletion and
amortisation
|
55.4
|
55.1
|
Production (BOEPD)
|
6,508
|
7,166
|
DD&A per BOE ($)
|
23.32
|
21.07
|
* Cash
operating cost per barrel and DD&A per barrel are alternative
performance measures. See pages 39 and 40.
Cash operating cost per barrel by Segment
|
Vietnam
$m
|
Egypt
Total
$m
|
Total
$m
|
Cost of sales
|
95.6
|
15.6
|
111.2
|
Less
|
|
|
|
Depreciation, depletion and
amortisation
|
(51.0)
|
(4.4)
|
(55.4)
|
Production based taxes
|
(10.4)
|
(0.1)
|
(10.5)
|
Inventories
|
(3.9)
|
(0.1)
|
(4.0)
|
Trade Receivable risk factor
provision
|
-
|
(2.2)
|
(2.2)
|
Other cost of sales
|
(1.5)
|
(0.3)
|
(1.8)
|
Cash operating costs
|
28.8
|
8.5
|
37.3
|
Production (BOEPD)
|
5,127
|
1,381
|
6,508
|
Cash operating cost per BOE
($)
|
15.39
|
16.86
|
15.70
|
DD&A per barrel by Segment
|
Vietnam
$m
|
Egypt
$m
|
Total
$m
|
Depreciation, depletion and
amortisation
|
51.0
|
4.4
|
55.4
|
Production (BOEPD)
|
5,127
|
1,381
|
6,508
|
DD&A per BOE ($)
|
27.25
|
8.73
|
23.32
|
Movements in Property, Plant and Equipment
|
2023
$m
|
2022
$m
|
|
As at 1 January
|
|
381.8
|
399.8
|
|
Capital spend
|
|
12.1
|
23.2
|
|
Transfer from intangible
assets
|
|
2.9
|
-
|
|
Revision in decommissioning
assets
|
|
(2.5)
|
(13.9)
|
|
Recognition of right-of-use
assets
|
|
-
|
0.8
|
|
DD&A - Oil and gas
properties
|
|
(55.4)
|
(55.1)
|
|
DD&A - Other assets
|
|
(0.2)
|
(0.1)
|
|
Impairment (charge)/reversal -
PP&E
|
|
(58.9)
|
27.1
|
|
As at 31 December
|
|
279.8
|
381.8
|
|
Property, Plant and
Equipment
|
|
279.3
|
381.0
|
|
Right-to-use-Asset (IFRS 16
Impact)
|
|
0.5
|
0.8
|
|
As at 31 December
|
|
279.8
|
381.8
|
|
Taxation
The overall net tax charge of
$19.8m (2022: $56.2m) relates to tax charges in Vietnam of $36.0m
less the deferred tax credit on net impairment charges of $16.2m
(2022: Vietnam tax charges of $47.9m plus the deferred tax charge
on impairment reversal of $8.3m).
The Group's effective tax rate
approximates to the statutory tax rate in Vietnam of 50%, after
adjusting for non-deductible expenditure and tax losses not
recognised.
The Egypt concessions are subject
to corporate income tax at the standard rate of 40.55%, however
responsibility for payment of corporate income taxes falls upon
EGPC on behalf of PEF. The Group records a tax charge, with a
corresponding increase in revenue, for the tax paid by EGPC on its
behalf. However, this is only valid if PEF is in a tax paying
position and no such tax has been recorded this year.
One of the Group's companies
entered into commodity zero cost collars designated as cash flow
hedges. In accordance with IAS 12, a deferred tax asset has not
been recognised in relation to the hedging losses of $0.2m (2022:
$22.5m) recorded in the year as it is unlikely that the UK tax
group will generate sufficient taxable profit in the future,
against which the deductible temporary differences can be
utilised.
(Loss)/profit post-tax
The post-tax loss for the year of
$48.8m (2022: $24.4m post-tax profit) included $53.8m of disposals,
re-measurements and impairments (2022: $14.9m). Business
performance post-tax profit for the year was $5.0m (2022:
$39.3m).
Disposals, re-measurements and
impairments are comprised of the following:
Financial Statements Impact:
|
2023
$m
|
2022
$m
|
|
Revenue
|
(0.2)
|
(22.5)
|
Realised hedging losses
|
Cost of sales
|
(2.2)
|
(1.5)
|
Trade receivable risk factor
provision
|
Impairment (charge)/reversal -
Intangible assets
|
(6.5)
|
0.8
|
|
Impairment (charge)/reversal -
Property, plant and equipment
|
(58.9)
|
27.1
|
|
Other/restructuring
expenses
|
(0.6)
|
(0.1)
|
Revision of carry with IPR. In
2022, Egypt restructuring and release of end of service
provision
|
Loss on disposal
|
-
|
(6.6)
|
Egypt farm-out
|
(Loss)/gain on fair value movement
of financial asset
|
(0.3)
|
0.3
|
Revision of contingent
consideration in relation to Egypt farm-out
|
Finance costs
|
(1.3)
|
(4.1)
|
Adjustment and amortisation of
capitalised borrowing costs
|
Income tax
credit/(charge)
|
16.2
|
(8.3)
|
Deferred tax on impairment
charge/(reversal)
|
Total
|
(53.8)
|
(14.9)
|
|
Cash flow
Operating cash flow (before
movements in working capital) was $103.8m (2022: $128.8m). After
tax charges of $44.3m (2022: $54.7m), restructuring and exceptional
expenses $nil (2022: $2.7m), working capital adjustments of $15.0m
(2022: $18.1m) and interest received of $0.4m (2022: $0.1m), the
cash generated from operations was $44.9m (2022:
$53.4m).
Cash generated from operations,
after tax charges, exceptional expenses and working capital
movements, is the basis of our dividend framework.
Operating cash flow (before
movements in working capital) adjusted for the impact of the
hedging positions of $0.2m loss (2022: $22.5m loss) gives an
underlying operational performance $104.0m (2022: $151.3m), which
is consistent with the reduction in commodity prices and the
production decrease year on year.
The increase in receivables was
$19.1m (2022: increase in receivables of $7.7m). The movement in
2023 is primarily driven by $11.4m increase from Egypt, due to EGPC
receivables. Since 2Q 2022, the Group has opted not to accept the
payment of PEF's receivables balance in EGP unless required for
operations, such as funding of ongoing expenditures upon expiry of
the carry with IPR. PEF is entitled under contract to be paid for
hydrocarbon sales in US dollars. The progressive devaluation of EGP
against USD means that it is preferable to continue to hold USD
denominated receivables.
In the space of two weeks, the
Egyptian Government has: (i) announced a landmark agreement with
ADQ (an Abu Dhabi sovereign wealth fund), whereby the latter will
invest $35 billion for the development of the new coastal city of
Ras El Hekma (the first $10 billion of which were immediately paid
to Egypt); (ii) on 6 March 2024, raised all main interest rates by
600 basis points; signed a significantly expanded new loan from the
IMF ($8 billion, including the original $3 billion secured in
December 2022, which should facilitate additional $12 billion from
other institutional lenders including the World Bank and the
European Union); and let the Egyptian pound (EGP) fully
float.
It is also widely expected that
the flotation of the EGP will trigger an acceleration in the
Egyptian Government's privatisation plan.
The Group is optimistic that its
receivables position with EGPC will improve during 2024, through a
combination of payments in USD and some EGP revenues or
settlements, as needed, to fund our share of operational
expenditure.
There was also an increase in
Vietnam trade receivables of $7.4m (2022: decrease in receivables
of $6.9m) due to three cargoes being lifted in December 2023.
Payments for these cargoes were received in January
2024.
Capital expenditure on continuing
operations for the year was lower at $26.7m (2022: $31.9m).
On Block 16-1 - TGT Field, no new development
wells were drilled in the year. During 2022, two development wells
were drilled. On Block 9-2 - CNV Field, one development well,
CNV-2PST1, completed in February 2023 and performed strongly,
producing in excess of pre-drill estimates. In El Fayum, three
wells were put on production and injection in 2023 and, on NBS, the
first exploration commitment well, NBS-SW1X, was declared a
commercial discovery and put on production in December
2023.
Net cash outflows from financing
activities of $50.1m (2022: $19.8m outflow) included outflows in
relation to the RBL of $22.4m in June 2023 and $12.6m in December
2023 (2022: $0.2m in June 2022 and $12.9m in December 2022)
following the half year and year end redetermination processes. The
amount drawn stood at $30.0m at year end.
The RBL facility, which is secured
only over the Group's interest in the Vietnam producing assets,
matures in July 2025. The facility amount is amortised by $14.2m,
every redetermination, from 1 July 2022. The facility amount
decreased to $43.0m from 1 January 2024 and will decrease further
to $28.8m from 1st July 2024. The Group is able to
dividend up from the Vietnam RBL zone to the Company twice a year
in January and July following approval of the redetermination. The
Debt Service Reserve Account (DSRA) was put in funds of $12.5m on
the first business day of 2024 to service the principal repayment
due in July 2024 plus interest.
There was no net outflow from NBE
revolving credit facility (2022: $2.7m). This facility allows PEF
to draw down 60% of the value of each El Fayum invoice in USD. The
amount drawn under the NBE facility as at 31 December 2023 was
$9.2m (2022: $9.2m).
Financing activities also included
$2.8m outflow (2022: $2.9m) in relation to the $3m extension of the
share buyback programme initiated in January 2023 and there was
$5.6m outflow (2022: $nil) following payment of the final dividend
for the 2022 financial year approved by shareholders at the AGM in
May 2023.
Tax strategy and total tax contribution
Tax is managed proactively and
responsibly with the goal of ensuring that the Group is compliant
in all countries in which it holds interests. Any tax planning
undertaken is commercially driven and within the spirit as well as
the letter of the law.
This approach forms an integral
part of the Group's sustainable business model.
The Group's Code of Business
Conduct and Ethics seeks to build open, cooperative and
constructive relationships with tax authorities and governmental
bodies in all territories in which it operates. The Group supports
greater transparency in tax reporting to build and maintain
stakeholder trust. We have a number of overseas subsidiaries which
were set up some time ago and the Group is now proactively planning
to bring these into the UK tax net to ensure greater transparency
and comparability. No additional taxes are expected to be due as a
result of this exercise.
During 2023, the total payments to
governments for the Group amounted to $188.0m (2022: $245.3m), of which
$166.5m or
89% (2022: $211.5m or
86%) was related to the Vietnam producing licence areas, of which
$110.8m (2022:
$140.7m) was for indirect taxes based on production entitlement. In
Egypt, payments to government totalled $19.3m (2022: $31.3m), of which
$18.4m (2022:
$28.8m) related to indirect taxes based on production
entitlement.
Balance sheet
Intangible assets increased during
the period to $18.2m (2022: $16.5m). Additions for the year related
to Blocks 125 & 126 in Vietnam $3.1m (2022: $3.1m), Egypt $8.0m
(2022: $1.0m) and $nil (2022: $0.2m) for the Israeli bid round
licence fee. The first exploration well on NBS (NBS-SW1X) was
declared a commercial discovery in December 2023 and exploration
costs of $2.9m (2022: $nil) relating to the development lease were
transferred to property, plant and equipment. There were total
Exploration and evaluation expenditure impairment charges of $6.5m
in the year (2022: $0.2m).
The movements in the Property,
Plant and Equipment asset class are shown above.
Impairment (charges)/reversals
As a result of previously
recognised impairment losses, combined with the ongoing oil price
volatility, economic uncertainty leading to high inflation globally
and discount rates, and movements in 2P reserves, we have tested
each of our oil and gas producing properties for impairment. The
results of these impairment tests are summarised below. For each
producing property, the recoverable amount has been determined
using the value in use method. The recoverable amount is calculated
using a discounted cash flow valuation of the 2P production
profile.
Summary of Impairments - Oil and Gas
properties
|
TGT
$m
|
CNV
$m
|
El Fayum
$m
|
NBS
$m
|
Total
$m
|
2023
|
|
|
|
|
|
Pre-tax impairment
(charge)/credit
|
(46.3)
|
0.3
|
(11.0)
|
(1.9)
|
(58.9)
|
Deferred tax
credit/(charge)
|
16.5
|
(0.3)
|
-
|
-
|
16.2
|
Post-tax impairment charge
|
(29.8)
|
-
|
(11.0)
|
(1.9)
|
(42.7)
|
|
|
|
|
|
|
Reconciliation of carrying amount:
|
|
|
|
|
|
As at 1 January 2023
|
242.4
|
76.4
|
62.5
|
-
|
381.3
|
Additions
|
1.3
|
3.0
|
7.6
|
-
|
11.9
|
Transfer from intangible
assets
|
-
|
-
|
-
|
2.9
|
2.9
|
Changes in decommissioning
asset 1
|
-
|
(2.5)
|
-
|
-
|
(2.5)
|
DD&A
|
(38.8)
|
(12.2)
|
(4.4)
|
-
|
(55.4)
|
Impairment
(charge)/reversal
|
(46.3)
|
0.3
|
(11.0)
|
(1.9)
|
(58.9)
|
As at 31 December 2023
|
158.6
|
65.0
|
54.7
|
1.0
|
279.3
|
|
TGT
$m
|
CNV
$m
|
El Fayum
$m
|
NBS
$m
|
Total
$m
|
2022
|
|
|
|
|
|
Pre-tax impairment
reversal
|
19.7
|
3.6
|
3.8
|
-
|
27.1
|
Deferred tax charge
|
(6.9)
|
(1.4)
|
-
|
-
|
(8.3)
|
Post-tax impairment reversal
|
12.8
|
2.2
|
3.8
|
-
|
18.8
|
|
|
|
|
|
|
Reconciliation of carrying amount:
|
|
|
|
|
|
As at 1 January 2022
|
266.0
|
84.2
|
49.2
|
-
|
399.4
|
Additions
|
7.0
|
3.2
|
13.6
|
-
|
23.8
|
Changes in decommissioning
asset 1
|
(11.1)
|
(2.8)
|
-
|
-
|
(13.9)
|
DD&A
|
(39.2)
|
(11.8)
|
(4.1)
|
-
|
(55.1)
|
Impairment reversal
|
19.7
|
3.6
|
3.8
|
-
|
27.1
|
As at 31 December 2022
|
242.4
|
76.4
|
62.5
|
-
|
381.3
|
1 Changes in decommissioning asset for TGT is due to a change
in discount rate only, whereas CNV reflects the change in field
abandonment plan and discount rate (2022: change in discount rate
and the field abandonment plan for TGT; change in discount rate
only for CNV)
Cash is set aside into abandonment
funds for both TGT and CNV. These abandonment funds are controlled
by PetroVietnam and, as the Group retains the legal rights to the
funds pending commencement of abandonment operations, they are
treated as other non-current assets in the Financial
Statements.
Oil inventory was $3.3m at 31
December 2023 (2022: $7.2m), of which $3.1m related to Vietnam and
$0.2m to Egypt. Trade and other receivables increased to $62.3m
(2022: $60.9m) of which $19.0m (2022: $11.4m) relates to Vietnam
and $42.7m (2022: $49.0m) relates to Egypt. For Egypt, the closing
balance includes $4.9m of carry (2022: $20.9m), which reflects the
remaining disproportionate funding contribution from IPR to
compensate for net cash flows since the economic date of the farm
down transaction, 1 July 2020, and the completion date of 21 March
2022. The carry decreases every month by the cash calls received
from IPR. In addition, Egypt trade receivables include $33.4m from
EGPC, after expected credit loss provision of $4.0m recognised
under IFRS 9, where collection has been delayed by the devaluation
of EGP and ongoing restrictions on outgoing USD transfers by the
Central Bank of Egypt previously highlighted (2022: trade
receivable from Egypt $22.4m after risk factor provision of
$1.8m).
Cash and cash equivalents at the
end of the year were $32.6m (2022: $45.3m) and the decrease was
mainly driven by $35.0m net repayment of borrowings (2022: $10.4m)
and cash flows from operating activities of $45.3m (2022: $53.4m)
as a result of reduced commodity prices during the year and lower
production.
Trade and other payables were
marginally higher at $14.2m (2022: $14.0m), of which $7.9m (2022:
$6.6m) relates to Egypt net JV payables in relation to operations
and Stratton royalty obligation. $2.2m (2022: $4.8m) relates to
Vietnam payables, $nil (2022: $0.5m) net hedging liability and
$4.1m (2021: $1.9m) Head Office payables, inclusive of $1.7m
interim dividend paid in January 2024. Tax payables increased to
$5.8m (2022: $5.2m) which is linked to the timing of cargoes from
TGT.
Borrowings were $40.5m (2022:
$74.2m), a decrease of $33.7m with $35.0m related to repayments
following the RBL redeterminations in June and December, partially
offset by $1.3m amortisation of capitalised borrowing costs and
one-off charges in relation to the redeterminations. The movement
on the NBE revolving credit facility was $nil for the year, so the
balance on the facility as at 31 December 2023 remained consistent
at $9.2m (2022: $9.2m).
Long-term provisions comprise the
Group's decommissioning obligations for the Vietnam fields. The
decommissioning provision decreased from $54.3m at 2022 year end to
$53.8m at 31 December 2023 mainly due to a lower CNV obligation
following finalisation of the revised abandonment plan in April
2023 and an increase in discount rate from 3.83% to 3.87% as a
result of an increase in prevailing risk-free market rates. The
amounts set aside into the abandonment funds total $53.7m (2022:
$50.2m). No decommissioning obligation exists under the El Fayum
Concession.
Own shares
The Pharos Employee Benefit Trust
holds ordinary shares of the Company for the purposes of satisfying
long-term incentive awards for senior management. At the end of
2023, the trust held 2,126,857 (2022: 2,126,857), representing
0.49% (2022: 0.48%) of the issued share capital.
In addition, as at 31 December
2023, the Company held 9,122,268 (2022: 9,122,268) treasury shares,
representing 2.11% (2022: 2.06%) of the issued share capital. All
shares purchased under the on-market buyback programme originally
announced in July 2022 and extended in January 2023 and December
2023 have been or will be cancelled rather than retained in
treasury.
Share buyback and dividend framework
Following a period of improved
commodity prices and a strengthening of the Group's liquidity
position, the Company committed to shareholder returns in the form
of share buybacks and dividends. The Company announced the
continuation of a further $3m share buyback programme in January
2023 (the First Programme Extension), of which $2.8m had been
incurred by the end of December 2023. On 6 December 2023, the
Company announced that it intended to continue the share buyback
programme in 2024 through its commitment of a further $3m
(excluding stamp duty and expenses). This further extension of the
programme commenced following completion of the First Programme
Extension in early 2024.
In September 2022, we announced a
clear sustainable policy for the recommencement of regular dividend
payments. This policy is to return no less than 10% of OCF each
year in two tranches
- An interim dividend of 33% of
the previous year's total dividend, payable in January of the
following year; and
- A final dividend payable in July
of the following year.
A final dividend of 1.00 pence per
share, $5.6m equivalent, was recommended by the Board in respect of
the year ended 31 December 2022. This was approved by shareholders
at the Company's 2023 AGM in May and paid in full on 12 July 2023
to shareholders on the register at the close of business on 16 June
2023. No interim dividend was paid in respect of the year ended 31
December 2022. On 6 December 2023, an interim dividend of 0.33
pence per share, $1.7m equivalent, was declared by the Board in
respect of the year ended 31 December 2023 and paid on 24 January
2024 to shareholders on the register at the close of business on 22
December 2023.
The Board have recommended a final
dividend in respect of the year ended 31 December 2023 of 0.77
pence per share subject to approval of the shareholders at the
Company's 2024 AGM. Subject to this approval, the final dividend
will be paid in full on 19 July 2024 in Pounds Sterling to ordinary
shareholders on the register at the close of business on 14 June
2024, with an ex-dividend date of 13 June 2024. This would take the
2023 full year dividend to 1.10 pence per share, an increase of 10%
on the prior year.
Going concern
Pharos continuously monitors its
business activities, financial position, cash flows and liquidity
through detailed forecasts. Scenarios and sensitivities are also
regularly presented to the Board, including changes in commodity
prices and in production levels from the existing assets, plus
other factors that could affect the Group's future performance and
position.
A base case forecast has been
considered that utilises oil prices of $81.5/bbl in 2024 and
$79/bbl in 2025. The key assumptions and related sensitivities
include a "Reasonable Worst Case" (RWC) scenario, where the Board
has taken into account the risk of an oil price crash broadly
similar to what occurred in 2020. It assumes the Brent oil price
down by a third to $54.3/bbl in April 2024 and gradually recovers
to base price in next 12 months, concurrent with 5% reductions in
Vietnam and Egypt production compared to our base case from April
2024. Both the base case and RWC take into account effect of
hedging that has already been put in place at 31 December 2023 and
subsequent hedges placed in 2024, now covering 28% for the full
year 2024 and 12% of 1H 2025. We have therefore secured an average
floor price and ceiling price of c. $63.5/bbl and c. $89/bbl,
respectively, for the entire hedged volumes. Under the RWC
scenario, we have identified appropriate mitigating actions, which
could look to defer uncommitted expenditure as required.
In addition, we have conducted a
reverse stress test sensitivity analysis that indicates the
magnitude of oil price decline required to breach our financial
headroom, assuming all other variables remain unchanged.
Our business in Vietnam remains
robust, with a low breakeven oil price. In TGT we have 2 wells
planned to be drilled in 2H 2024. The majority of our debt ($30m as
of 31 December 2023) is secured against the Vietnam producing
assets under the RBL, which will be repaid by July 2025.
In Egypt, we have limited capital
expenditure, low cost recompletions and waterflood in El-Fayum and
development drilling in NBS in 2H 2024. As of 31 December 2023
$9.2m drawn on an uncommitted revolving credit facility on the
Egypt revenue invoices.
On the basis of the forecasts
provided above, the Group is expected to have sufficient financial
headroom for the 12 months from the date of approval of the 2023
Financial Statements. Based on this analysis, the Directors have a
reasonable expectation that the Group has adequate resources to
continue its operations in the foreseeable future. Therefore, the
Financial Statements have been prepared using the going concern
basis of accounting.
Financial outlook
We have a great deal to look
forward to as we move forward in 2024 and beyond.
· A
strong and stable balance sheet, improved liquidity, improved
fiscal terms in Egypt, stable production with a solid USD cash flow
from our Vietnam portfolio and a reduced cost base throughout the
Group
· Continued development drilling across our
portfolio
· Reducing debt and getting to a net cash position early in the
year
· Significantly improving economic situation in Egypt, which
could start to unlock our receivables position there
Further returns to shareholders
are expected in 2024, with the announcement in January of an
additional $3m committed to an extension of the Company's ongoing
share buyback programme, and a 10% increase in full year dividends
subject to approval of the final dividend at the 2024
AGM.
Sue Rivett
Chief Financial Officer
Review of
Operations
Vietnam
Vietnam Production in
2023
Production in 2023 from the TGT
and CNV fields net to the Group's working interest averaged 5,127
boepd (2022: 5,418 boepd). This is in line with the production
guidance for Vietnam announced in January 2023 of 4,700 - 5,700
boepd net.
TGT production averaged 12,341
boepd gross and 3,661 boepd net to the Group (2022: 13,784 boepd
gross and 4,089 boepd net). CNV production averaged 5,861 boepd
gross and 1,466 boepd net to the Group (2022: 5,317 boepd gross and
1,329 boepd net).
Vietnam Development and Operations
in 2023
TGT & CNV Fields
On Block 16-1 - TGT Field,
operational activities were focused on adding low-cost production
through well intervention and production optimisation opportunities
(surface and subsurface) in absence of new wells drilling. The TGT
RFDP was approved by MOIT on 9 January 2024.
On Block 9-2 - CNV Field, the
field saw strong performance from its first new lateral well, which
was delivered on time, under budget, and put on production in 1Q
2023. The CNV RFDP for additional drilling was submitted to
partners for approval in 2023, and discussions are
ongoing.
The Company has continued to
receive positive feedback from Petrovietnam and MOIT on the
applications for five-year extensions to the petroleum contracts
for the TGT and CNV fields.
Vietnam Exploration in
2023
Blocks 125 & 126
On Blocks 125 & 126, a
two-year PSC extension was granted by MOIT on 13 June 2023,
extending the first exploration period of the PSC to 8 November
2025. This approval shows the encouraging level of support from the
Vietnamese Government and discussions with a number of interested
parties to secure a farm-in partner are progressing.
An independent CPR for Block 125
was published on 20 July 2023, confirming a range of gross unrisked
prospective oil resources of between 1,178 MMstb (1U) and 29,785
MMstb (3U) with a Mean value of 13,328 MMstb. The report supports
the Group's internal assessments and paves the way for further work
to develop new leads and mature leads to prospects.
The ongoing interpretation of 3D
seismic data has highlighted greater prospectivity in the deeper
water section of Block 125. In order to drill one of these deeper
water prospects as the commitment exploration well under the
current exploration phase of the PSC, a Drillship or
Dynamically-Positioned (DP) Semi-Submersible Rig is
needed.
2024 Work Programme
TGT & CNV Fields
· Vietnam production guidance for 2024 is 3,900 - 5,000 boepd
net.
· Planning is well-advanced for a two-well TGT drilling
programme in 2H 2024.
· Continued engagement with partners and regulators to finalise
the five-year licence extensions for TGT and CNV.
Blocks 125 & 126
· Ongoing discussions with another operator to secure a well
drilling slot during their multi-well drilling programme in the
region.
· Progressing parallel discussions with several potential
farm-in partners for Blocks 125 & 126. Securing a rig slot will
positively impact the farm-out discussions.
.
Egypt
Egypt Production in
2023
Production for 2023 from the El
Fayum Concession averaged 3,069 bopd gross and 1,381 bopd net to
the Group. This is in line with the 2023 production guidance
announced in January 2023 of 1,350 - 1,800 bopd net.
Egypt Development and Operations
in 2023
El Fayum
Three new wells in El Fayum (2
producers and 1 injector) were put on production and injection in
2023, in line with pre-drill expectations.
North Beni Suef
On NBS, the first exploration
commitment well (NBS-SW1X) was declared a commercial discovery and
put on production in December 2023. A new 20-year development lease
for NBS-SW1X was awarded by EGPC in September 2023, opening up a
new area for production and development.
Two workover rigs remain on field
to contribute to production through low-cost well repairs,
recompletions, and deployment of water injection.
Egypt Exploration in
2023
El Fayum exploration
On El Fayum, there was exploration
success with the first commitment well in the Abu Roash G and Upper
Bahariya formations in July 2023. The well is set up for re-entry
and testing in 2024.
North Beni Suef (NBS) exploration
On NBS, all technical commitments
of the initial exploration period have been fulfilled with 3D
seismic survey acquired on time and on budget in 2H 2023, and the
completion of two exploration commitment wells. As noted above, in
September 2023, NBS-SW1X was declared a commercial discovery.
Production from the well commenced in December 2023, following the
grant of the first development lease on the Concession. The second
and final exploration commitment well for the first phase of the
NBS exploration period (NBS-5X) was drilled in the Abu Roash G
formation at a deeper depth and failed to encounter oil-bearing
sands. The result of this well does not hinder other mapped
prospects in the Concession.
2024 Work Programme
El Fayum & NBS
· Egypt production guidance for 2024 is 1,300 - 1,500 bopd
net.
· Continuation of modest and measured approach to capital
allocation and drilling in El Fayum and NBS, with potential to ramp
up activity this year and beyond in response to the improving
economic environment.
· Focus for this year's work programme in El Fayum is low-cost
recompletions and waterflood.
· Development drilling in the NBS SW field is planned to start
in 2H 2024.
· Processing and interpretation of c.130km2 of 3D
seismic data on NBS is underway and expected to be completed in 2H
2024.
Group Reserves and
Contingent Resources
The Group Reserves Statistics
table below summarises our reserves and contingent resources based
on the Group's unitised net working interest in each field. Gross
reserves and contingent resources have been independently audited
by RISC Advisory Pty Ltd (RISC) for Vietnam and McDaniel &
Associates Consultants Ltd. (McDaniel) for Egypt.
Group Reserves Statistics
Net working interest,
mmboe
|
TGT
|
CNV
|
Vietnam3
|
El Fayum
|
NBS
|
Egypt4
|
Group
|
Oil and Gas 2P Commercial
Reserves1,2
|
|
|
|
|
As at 1 January 2023
|
8.8
|
3.4
|
12.2
|
15.0
|
-
|
15.0
|
27.2
|
Production
|
(1.3)
|
(0.5)
|
(1.8)
|
(0.5)
|
-
|
(0.5)
|
(2.3)
|
Revision
|
(1.2)
|
(0.1)
|
(1.3)
|
(0.9)
|
-
|
(0.9)
|
(2.2)
|
Discoveries
|
-
|
-
|
-
|
-
|
0.8
|
0.8
|
0.8
|
2P Commercial Reserves as at 31 December
2023
|
6.3
|
2.8
|
9.1
|
13.6
|
0.8
|
14.4
|
23.5
|
|
|
|
|
|
|
|
|
Oil and Gas 2C Contingent
Resources1,2
|
|
|
|
|
As at 1 January 2023
|
7.4
|
3.4
|
10.8
|
8.9
|
-
|
8.9
|
19.7
|
Revision
|
(1.1)
|
2.2
|
1.1
|
0.7
|
-
|
0.7
|
1.8
|
2C Contingent Resources as at 31 December
2023
|
6.3
|
5.6
|
11.9
|
9.6
|
-
|
9.6
|
21.5
|
|
|
|
|
|
|
|
|
Total of 2P Reserves and 2C Contingent Resources as at 31
December 2023
|
12.6
|
8.4
|
21.0
|
23.2
|
0.8
|
24.0
|
45.0
|
1) Reserves and Contingent
Resources are categorised in line with 2018 SPE/WPC/AAPG/SPEE /SWLA
Petroleum Resource Management System.
2) Assumes an oil equivalent
conversion factor of 6,000 standard cubic feet per barrel of oil
equivalent.
3) Reserves and Contingent
Resources have been independently audited by RISC.
4) Reserves and Contingent
Resources have been independently audited by McDaniel.
Vietnam Reserves and Contingent Resources
In accordance with the
requirements of its RBL, the company commissioned RISC to provide
an independent audit of gross (100% field) reserves and contingent
resources for TGT and CNV as of 31 December 2023.
Vietnam Reserves Statistics
Net working interest,
mmboe
|
TGT
|
CNV
|
Vietnam
|
Oil and Gas 2P Commercial
Reserves1,2,3
|
As at 1 January 2023
|
8.8
|
3.4
|
12.2
|
Production
|
(1.3)
|
(0.5)
|
(1.8)
|
Revision
|
(1.2)
|
(0.1)
|
(1.3)
|
2P Commercial Reserves as at 31 December
2023
|
6.3
|
2.8
|
9.1
|
|
|
|
|
Oil and Gas 2C Contingent
Resources1,2,3
|
As at 1 January 2023
|
7.4
|
3.4
|
10.8
|
Revision
|
(1.1)
|
2.2
|
1.1
|
2C Contingent Resources as at 31 December
2023
|
6.3
|
5.6
|
11.9
|
|
|
|
|
Total of 2P Reserves and 2C Contingent Resources as at 31
December 2023
|
12.6
|
8.4
|
21.0
|
1) Reserves and Contingent
Resources are categorised in line with 2018 SPE/WPC/AAPG/SPEE /SWLA
Petroleum Resource Management System.
2) Assumes oil equivalent
conversion factor of 6,000 scf/boe.
3) Reserves and Contingent
Resources have been independently audited by RISC.
On TGT, 2P reserves were revised
downwards due to a 9-month delay in drilling of the two infill
wells, lower expected benefit from well activities as the field
becomes more mature and a slow production ramp-up following the
annual maintenance shutdown in the last quarter of the year. 2C
contingent resources were revised accordingly.
On CNV, the 2P reserves were
largely in line with the previous year. 2C contingent resources
were revised upwards due to the inclusion of one additional lateral
side-track well.
In Vietnam, the Group has applied
for an extension to the petroleum contracts for the TGT and CNV
fields. We expect changes to the discovered resources upon
receiving approval from the government.
Egypt Reserves and Contingent Resources
Egypt Reserves Statistics
Net working interest,
mmboe
|
El
Fayum
|
NBS
|
Egypt
|
Oil and Gas 2P Commercial
Reserves1,2
|
As at 1 January 2023
|
15.0
|
-
|
15.0
|
Production
|
(0.5)
|
-
|
(0.5)
|
Revision
|
(0.9)
|
-
|
(0.9)
|
Discoveries
|
-
|
0.8
|
0.8
|
2P Commercial Reserves as at 31 December
2023
|
13.6
|
0.8
|
14.4
|
|
|
|
|
Oil and Gas 2C Contingent
Resources1,2
|
As at 1 January 2023
|
8.9
|
-
|
8.9
|
Revision
|
0.7
|
-
|
0.7
|
2C Contingent Resources as at 31 December
2023
|
9.6
|
-
|
9.6
|
|
|
|
|
Total of 2P Reserves and 2C Contingent Resources as at 31
December 2023
|
23.2
|
0.8
|
24.0
|
1) Reserves and Contingent
Resources are categorised in line with 2018 SPE/WPC/AAPG/SPEE /SWLA
Petroleum Resource Management System.
2) Reserves and Contingent
Resources have been independently audited by McDaniel.
On El Fayum, the delay in the
execution of the field development plan have resulted in a downward
revision of the 2P reserves, pushing some volumes into the
contingent resources category.
North Beni Suef is included in the
reserves assessment for the first time, following a successful
exploration well and granting of the Development Lease. Initial
reserves are granted based on a limited development of two producer
wells offset to the discovery well. The full development programme
will be incorporated following the interpretation of the new 3D
seismic acquired during 2023.
Group's Net Working Interest Reserves and Contingent
Resources
TGT Field at 31 December 2023 (mmboe) (net to Group's working
interest)
Reserves2
|
1P
|
2P
|
3P
|
Oil
|
4.8
|
5.9
|
7.1
|
Gas1
|
0.2
|
0.4
|
0.6
|
Total
|
5.0
|
6.3
|
7.7
|
|
|
|
|
Contingent
Resources2
|
1C
|
2C
|
3C
|
Oil
|
3.3
|
6.1
|
9.0
|
Gas1
|
0.1
|
0.2
|
0.4
|
Total
|
3.4
|
6.3
|
9.4
|
|
|
|
|
Sum of Reserves and Contingent
Resources3
|
1P &
1C
|
2P &
2C
|
3P &
3C
|
Oil
|
8.1
|
12.0
|
16.1
|
Gas1
|
0.3
|
0.6
|
1.0
|
Total
|
8.4
|
12.6
|
17.1
|
1) Assumes oil equivalent
conversion factor of 6,000 standard cubic feet per barrel of oil
equivalent.
2) Reserves and Contingent
Resources have been audited independently by RISC.
3) The summation of Reserves and
Contingent Resources has been prepared by the Company.
CNV Field at 31 December 2023 (mmboe) (net to Group's working
interest)
Reserves2
|
1P
|
2P
|
3P
|
Oil
|
1.3
|
1.7
|
2.1
|
Gas1
|
0.8
|
1.1
|
1.3
|
Total
|
2.1
|
2.8
|
3.4
|
|
|
|
|
Contingent
Resources2
|
1C
|
2C
|
3C
|
Oil
|
1.8
|
3.5
|
5.2
|
Gas1
|
1.1
|
2.1
|
3.2
|
Total
|
2.9
|
5.6
|
8.4
|
|
|
|
|
Sum of Reserves and Contingent
Resources3
|
1P &
1C
|
2P &
2C
|
3P &
3C
|
Oil
|
3.1
|
5.2
|
7.3
|
Gas1
|
1.9
|
3.2
|
4.5
|
Total
|
5.0
|
8.4
|
11.8
|
1) Assumes oil equivalent
conversion factor of 6,000 standard cubic feet per barrel of oil
equivalent.
2) Reserves and Contingent
Resources have been audited independently by RISC.
3) The summation of Reserves and
Contingent Resources has been prepared by the Company.
El Fayum Concession at 31 December 2023 (mmboe) (net to
Group's working interest)
Reserves1
|
1P
|
2P
|
3P
|
Oil
|
6.8
|
13.6
|
17.9
|
|
|
|
|
Contingent
Resources1
|
1C
|
2C
|
3C
|
Oil
|
3.6
|
9.6
|
19.2
|
|
|
|
|
Sum of Reserves and Contingent
Resources2
|
1P &
1C
|
2P &
2C
|
3P &
3C
|
Total
|
10.4
|
23.2
|
37.1
|
1) Reserves and Contingent
Resources have been audited independently by McDaniel.
2) The summation of Reserves and
Contingent Resources has been prepared by the Company.
North Beni Suef Concession at 31 December 2023 (mmboe) (net
to Group's working interest)
Reserves1
|
1P
|
2P
|
3P
|
Oil
|
0.2
|
0.8
|
0.9
|
|
|
|
|
Contingent
Resources1
|
1C
|
2C
|
3C
|
Oil
|
-
|
-
|
-
|
|
|
|
|
Sum of Reserves and Contingent
Resources2
|
1P &
1C
|
2P &
2C
|
3P &
3C
|
Total
|
0.2
|
0.8
|
0.9
|
1) Reserves and Contingent
Resources have been audited independently by McDaniel.
2) The summation of Reserves and
Contingent Resources has been prepared by the Company.
Condensed consolidated
income statement
|
|
|
|
for the year to 31 December
2023
|
|
|
|
|
|
|
|
|
|
|
|
2023
|
2022
|
|
|
|
|
|
|
|
Notes
|
$ million
|
$ million
|
|
Continuing
operations
|
|
|
|
|
|
|
|
Revenue
|
|
|
|
|
|
3
|
167.9
|
199.1
|
|
Cost of sales
|
|
|
|
|
4
|
(111.2)
|
(116.8)
|
|
Gross profit
|
|
|
|
|
|
56.7
|
82.3
|
|
|
|
|
|
|
|
|
|
|
|
Administrative expenses
|
|
|
|
|
(9.0)
|
(10.0)
|
|
Pre-licence costs
|
|
|
|
|
(0.4)
|
-
|
|
Impairment (charge)/reversal -
Intangibles assets
|
3,
9
|
(6.5)
|
0.8
|
|
Impairment (charge)/reversal -
Property, plant and equipment
|
|
3,
10
|
(58.9)
|
27.1
|
|
|
|
|
|
|
|
|
|
Operating (loss)/profit
|
|
|
|
|
(18.1)
|
100.2
|
|
|
|
|
|
|
|
|
|
|
|
Other/restructuring
expense
|
|
|
|
|
5
|
(0.6)
|
(0.8)
|
|
Loss on disposal
|
|
|
|
|
14
|
-
|
(6.6)
|
|
(Loss)/gain on fair value movement
of financial asset
|
14
|
(0.3)
|
0.3
|
|
Investment revenue
|
|
|
|
|
|
0.2
|
0.2
|
|
Finance costs
|
|
|
|
|
6
|
(10.2)
|
(12.7)
|
|
(Loss)/profit before tax
|
|
|
|
|
3
|
(29.0)
|
80.6
|
|
Income tax charge
|
|
|
|
|
7
|
(19.8)
|
(56.2)
|
|
(Loss)/profit for the year
|
|
(48.8)
|
24.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss)/profit per share (cents)
|
8
|
|
|
|
Basic
|
|
|
|
|
|
(11.4)
|
5.6
|
|
Diluted
|
|
|
|
|
|
(11.4)
|
5.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensed consolidated
statement of comprehensive income
|
|
for the year to 31 December
2023
|
|
|
|
|
|
|
|
|
|
|
|
|
2023
|
2022
|
|
|
|
|
|
|
|
|
$ million
|
$ million
|
|
|
|
|
|
|
|
|
|
|
|
(Loss)/Profit for the
year
|
|
|
|
|
(48.8)
|
24.4
|
|
Items that may be subsequently
reclassified to profit or loss:
|
|
|
|
Fair value gain/(loss) arising on
hedging instruments during the
year
|
0.6
|
(18.9)
|
|
Less: Loss arising on hedging
Instruments reclassified to profit or
loss
11
|
0.2
|
22.5
|
|
Total comprehensive (loss)/income for the
year
|
|
(48.0)
|
28.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The above
condensed consolidated income statement and condensed consolidated
statement of comprehensive income should
be read
in conjunction with the accompanying notes.
CONDENSED CONSOLIDATED
Balance sheet
|
|
|
|
|
|
|
|
|
Group
|
|
|
Company
|
|
|
|
|
|
|
2023
|
2022
|
|
2023
|
2022
|
|
|
|
|
|
Notes
|
$ million
|
$ million
|
|
$ million
|
$ million
|
Non-current assets
|
|
|
|
|
|
|
|
|
|
Intangible assets
|
|
|
|
9
|
18.2
|
16.5
|
|
-
|
-
|
Property, plant and
equipment
|
|
|
10
|
279.3
|
381.0
|
|
-
|
-
|
Right-of-use assets
|
|
|
|
0.5
|
0.8
|
|
-
|
-
|
Investments
|
|
|
|
|
-
|
-
|
|
294.3
|
335.5
|
Loan to subsidiaries
|
|
-
|
-
|
|
16.8
|
23.0
|
Other assets
|
|
|
|
|
58.6
|
59.1
|
|
-
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
356.6
|
457.4
|
|
311.1
|
358.5
|
|
|
|
|
|
|
|
|
|
|
|
Current assets
|
|
|
|
|
|
|
|
|
|
Inventories
|
|
|
|
|
|
3.3
|
7.2
|
|
-
|
-
|
Trade and other
receivables
|
|
|
|
62.3
|
60.9
|
|
0.4
|
0.4
|
Tax receivables
|
|
|
|
|
2.2
|
2.1
|
|
0.2
|
0.1
|
Cash and cash
equivalents
|
|
|
|
32.6
|
45.3
|
|
1.7
|
8.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
100.4
|
115.5
|
|
2.3
|
9.3
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
|
|
|
457.0
|
572.9
|
|
313.4
|
367.8
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
|
|
|
|
|
|
|
|
Trade and other
payables
|
|
|
|
(14.2)
|
(14.0)
|
|
(4.0)
|
(1.9)
|
Borrowings
|
|
|
|
(29.5)
|
(39.6)
|
|
-
|
-
|
Lease Liabilities
|
|
|
|
(0.3)
|
(0.3)
|
|
-
|
-
|
Tax payables
|
|
|
|
(5.8)
|
(5.2)
|
|
(0.9)
|
(1.2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(49.8)
|
(59.1)
|
|
(4.9)
|
(3.1)
|
|
|
|
|
|
|
|
|
|
Non-current liabilities
|
|
|
|
|
|
|
|
|
|
Other payables
|
|
|
|
|
(0.5)
|
(0.9)
|
|
-
|
-
|
Deferred tax
liabilities
|
|
|
|
|
(68.2)
|
(92.9)
|
|
-
|
-
|
Borrowings
|
|
|
|
|
(11.0)
|
(34.6)
|
|
-
|
-
|
Lease liabilities
|
|
|
|
|
(0.2)
|
(0.5)
|
|
-
|
-
|
Long term provisions
|
|
|
|
|
(53.8)
|
(54.3)
|
|
-
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(133.7)
|
(183.2)
|
|
-
|
-
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
|
|
(183.5)
|
(242.3)
|
|
(4.9)
|
(3.1)
|
Net assets
|
|
|
|
|
273.5
|
330.6
|
|
308.5
|
364.7
|
|
|
|
|
|
|
|
|
|
|
|
Equity
|
|
|
|
|
|
|
|
|
|
|
Share capital
|
|
|
|
|
33.7
|
34.3
|
|
33.7
|
34.3
|
Share premium
|
|
|
|
|
58.0
|
58.0
|
|
58.0
|
58.0
|
Other reserves
|
|
|
|
|
255.4
|
253.6
|
|
200.6
|
199.7
|
Retained (deficit) /
earnings
|
|
|
|
|
(73.6)
|
(15.3)
|
|
16.2
|
72.7
|
Total equity
|
|
|
|
|
273.5
|
330.6
|
|
308.5
|
364.7
|
The above condensed consolidated
balance sheet should be read in conjunction with the accompanying
notes.
CONDENSED consolidated
STATEMENT OF CHANGES IN EQUITY
|
Group
|
Notes
|
Called up
share capital
$ million
|
Share premium
$ million
|
Other reserves
$ million
|
Retained
earnings /(deficit)
$ million
|
Total
$ million
|
As at 1 January 2022
|
34.9
|
58.0
|
250.5
|
(39.0)
|
304.4
|
Profit for the year
|
-
|
-
|
-
|
24.4
|
24.4
|
Other comprehensive
income
|
-
|
-
|
3.6
|
-
|
3.6
|
Share buy back
|
(0.6)
|
-
|
0.6
|
(2.9)
|
(2.9)
|
Treasury shares
repurchased
|
-
|
-
|
(0.6)
|
-
|
(0.6)
|
Share-based
payments
|
-
|
-
|
1.7
|
-
|
1.7
|
Transfer relating to share-based
payments
|
-
|
-
|
(2.2)
|
2.2
|
-
|
As at 1 January 2023
|
34.3
|
58.0
|
253.6
|
(15.3)
|
330.6
|
Loss for the year
|
-
|
-
|
-
|
(48.8)
|
(48.8)
|
Other comprehensive income
|
-
|
-
|
0.8
|
-
|
0.8
|
Share buy back
|
(0.6)
|
-
|
0.6
|
(2.8)
|
(2.8)
|
Share-based payments
|
-
|
-
|
1.0
|
-
|
1.0
|
Distributions to
shareholders
12
|
-
|
-
|
-
|
(7.3)
|
(7.3)
|
Transfer relating to share-based payments
|
-
|
-
|
(0.6)
|
0.6
|
-
|
As at 31 December 2023
|
33.7
|
58.0
|
255.4
|
(73.6)
|
273.5
|
|
Company
|
|
Called up
share capital
$ million
|
Share premium
$ million
|
Other reserves
$ million
|
Retained
earnings
$ million
|
Total
$ million
|
As at 1 January 2022
|
34.9
|
58.0
|
202.4
|
12.6
|
307.9
|
Profit for the year
|
-
|
-
|
-
|
60.7
|
60.7
|
Share buy back
|
(0.6)
|
-
|
0.6
|
(2.9)
|
(2.9)
|
Share-based payments
|
-
|
-
|
1.7
|
-
|
1.7
|
Transfer relating to share-based
payments
|
-
|
-
|
(5.0)
|
2.3
|
(2.7)
|
As at 1 January 2023
|
34.3
|
58.0
|
199.7
|
72.7
|
364.7
|
Loss for the year
|
-
|
-
|
-
|
(47.0)
|
(47.0)
|
Share buy back
|
(0.6)
|
-
|
0.6
|
(2.8)
|
(2.8)
|
Share-based payments
|
-
|
-
|
1.0
|
-
|
1.0
|
Distributions to
shareholders
12
|
-
|
-
|
-
|
(7.3)
|
(7.3)
|
Transfer relating to share-based payments
|
-
|
-
|
(0.7)
|
0.6
|
(0.1)
|
As at 31 December 2023
|
33.7
|
58.0
|
200.6
|
16.2
|
308.5
|
The above condensed statements of
changes in equity should be read in conjunction with the
accompanying notes.
CONDENSED CONSOLIDATED cash
flow statements
for the year to 31 December
2023
|
|
|
Group
|
|
|
Company
|
|
Notes
|
2023
$ million
|
2022
$
million
|
|
2023
$ million
|
2022
$
million
|
Net cash from (used in) operating
activities
|
13
|
44.9
|
53.4
|
|
(8.1)
|
(11.6)
|
Investing activities
|
|
|
|
|
|
|
Purchase of intangible
assets
|
|
(9.7)
|
(4.4)
|
|
-
|
-
|
Purchase of property, plant and
equipment
|
|
(13.5)
|
(25.4)
|
|
-
|
-
|
Payment to abandonment
fund
|
|
(3.5)
|
(2.1)
|
|
-
|
-
|
Consideration in relation to farm
out of Egyptian assets1
|
|
15.6
|
18.4
|
|
-
|
-
|
Contingent consideration received
in relation to farm out of Egyptian assets
|
|
5.0
|
-
|
|
-
|
-
|
Assignment fee in relation to farm
out of Egyptian assets
|
|
(0.5)
|
(0.5)
|
|
-
|
-
|
Dividends received from subsidiary
undertakings
|
|
-
|
-
|
|
11.4
|
19.0
|
Net cash (used in) from investing
activities
|
|
(6.6)
|
(14.0)
|
|
11.4
|
19.0
|
|
|
|
|
|
|
|
Financing activities
|
|
|
|
|
|
|
Share based payments
|
|
-
|
(0.4)
|
|
-
|
-
|
Repayment of borrowings
|
|
(44.2)
|
(27.1)
|
|
-
|
-
|
Proceeds from
borrowings
|
|
9.2
|
16.7
|
|
-
|
-
|
Interest paid on
borrowings
|
|
(6.4)
|
(6.0)
|
|
-
|
-
|
Lease payments
|
|
(0.3)
|
(0.1)
|
|
-
|
-
|
Share buy back
|
|
(2.8)
|
(2.9)
|
|
(2.8)
|
(2.9)
|
Dividends paid to
shareholders
|
|
(5.6)
|
-
|
|
(5.6)
|
-
|
Funding movements with
subsidiaries
|
|
-
|
-
|
|
(2.1)
|
(1.0)
|
Net used in financing activities
|
|
(50.1)
|
(19.8)
|
|
(10.5)
|
(3.9)
|
|
|
|
|
|
|
|
Net (decrease)/ increase in cash and cash
equivalents
|
|
(11.8)
|
19.6
|
|
(7.2)
|
3.5
|
Cash and cash equivalents at beginning of
year
|
|
45.3
|
27.1
|
|
8.8
|
5.3
|
Effect of foreign exchange rate
changes
|
|
(0.9)
|
(1.4)
|
|
0.1
|
-
|
Cash and cash equivalents at end of year
|
|
32.6
|
45.3
|
|
1.7
|
8.8
|
1 During the year IPR, acting as operator and agent, was
authorised to settle its operating liabilities of $3.5m (2022:
$6.6m) and investing liabilities of $12.1m (2022: $8.8m) against
the consideration due from the associated carry debtor amounting to
$15.6m (2022: $15.4m). The Company has disclosed the underlying
cash flows as operating, investing or financing according to their
nature on the basis that, as a principal, the entity has the right
to the cash inflows and/or the obligation to settle the liability
and ensure clarity of disclosure of the operating cash costs of the
business.
The above condensed consolidated
cash flow statements should be read in conjunction with the
accompanying notes.
Notes to the condensed
consolidated financial statements
1. General information
The financial information set out
above does not constitute the Company's statutory accounts for the
years ended 31 December 2023 or 2022, but is derived from those
accounts. A copy of the statutory accounts for 2022 has been
delivered to the Registrar of Companies and those for 2023 will be
delivered following the Company's annual general meeting. The
auditors have reported on those accounts; their reports were
unqualified, did not draw attention to any matters by way of
emphasis without qualifying their report and did not contain
statements under section 498(2) or (3) of the Companies Act 2006.
Whilst the financial information included in this preliminary
announcement has been computed in accordance with International
Financial Reporting Standards (IFRS) as issued by the International
Accounting Standard Board (IASB), this announcement does not itself
contain sufficient information to comply with IFRS. The financial
statements are presented in US dollars which is the functional
currency of each of the Company's subsidiary
undertakings.
2. Material accounting policies
(a) Basis of preparation
The financial information has been
prepared in accordance with the recognition and measurement
criteria of international accounting standards in conformity with
the requirements of the Companies Act 2006 and International
Financial Reporting Standards, as issued by the International
Accounting Standard Board (IASB). The financial information has
also been prepared in accordance with the recognition and
measurement criteria of International Financial Reporting Standards
as issued by the IASB.
The financial information has also
been prepared on a going concern basis of accounting.
(b) New and amended standards adopted by
Pharos
A number of new or amended
standards became applicable for the current reporting
period.
Amendments to IAS 1 Presentation
of Financial Statements and IFRS Practice Statement 2 Making
Materiality Judgements- Disclosure of Accounting
Policies:
The Group has adopted the
amendments to IAS 1 for the first time in the current
year.
The amendments change the
requirements in IAS 1 with regard to disclosure of accounting
policies. The amendments to IAS 1 and IFRS Practice Statement 2
Making Materiality Judgements ('four-step materiality process')
provide guidance and examples to help entities apply materiality
judgements to accounting policy disclosures.
The amendments replace all
instances of the term 'significant accounting policies' with
'material accounting policy information'. Accounting policy
information is material if, when considered together with other
information included in an entity's financial statements, it can
reasonably be expected to influence decisions that the primary
users of general purpose financial statements make on the basis of
those financial statements. Accounting policy information may be
material because of the nature of the related transactions, other
events or conditions, even if the amounts are immaterial. However,
not all accounting policy information relating to material
transactions, other events or conditions is itself
material.
The amendments have had an impact
on the Group's disclosures of accounting policies, but not on the
measurement, recognition or presentation of any items in the
Group's financial statements.
The Group did not have to change
its accounting policies or make retrospective adjustments as a
result of adopting these standards.
- Insurance Contracts - IFRS 17 (including the June 2020 and
December 2021 Amendments)
- Definition of Accounting Estimates - Amendments to IAS
8
- Deferred Tax related to Assets and Liabilities arising from a
Single Transaction - Amendments to IAS 12
- International Tax Reform - Pillar Two Model Rules -
Amendments to IAS 12
(c) New standards and interpretations not yet
adopted
Certain new accounting standards
and interpretations have been published that are not mandatory for
31 December 2023 year end and have not been early adopted by the
Group. These standards are not expected to have a material impact
on the Group in the current or future reporting periods nor on
foreseeable future transactions.
3. Segment information
The Group has one principal
business activity being oil and gas exploration and production. The
Group's continuing operations are located in South East Asia and
Egypt (the Group's operating segments). There are no inter-segment
sales. South East Asia and Egypt form the basis on which the Group
reports its segment information.
|
|
|
|
|
|
|
2023
|
|
SE Asia
$ million
|
Egypt
$ million
|
Unallocated
$ million
|
Group
$ million
|
Oil and gas sales
|
149.2
|
18.9
|
-
|
168.1
|
Realised loss on commodity hedges
|
-
|
-
|
(0.2)
|
(0.2)
|
Total revenue
|
149.2
|
18.9
|
(0.2)
|
167.9
|
Depreciation, depletion and amortisation - Oil and
gas
|
(51.0)
|
(4.4)
|
-
|
(55.4)
|
Depreciation, depletion and amortisation -
Other
|
-
|
(0.2)
|
-
|
(0.2)
|
Pre-licence costs
|
-
|
(0.4)
|
-
|
(0.4)
|
Impairment charge - Intangibles
|
-
|
(6.5)
|
-
|
(6.5)
|
Impairment charge - PP&E
|
(46.0)
|
(12.9)
|
-
|
(58.9)
|
Loss on fair value movement of financial
asset
|
-
|
(0.3)
|
-
|
(0.3)
|
Profit/(loss) before tax1
|
5.6
|
(18.4)
|
(16.2)
|
(29.0)
|
Tax charge on operations
|
(36.0)
|
-
|
-
|
(36.0)
|
Tax credit on impairment charge
|
16.2
|
-
|
-
|
16.2
|
|
|
|
|
|
|
|
|
|
|
|
2022
|
|
SE Asia
$ million
|
Egypt
$ million
|
Unallocated
$ million
|
Group
$ million
|
Oil and gas sales
|
184.8
|
36.8
|
-
|
221.6
|
Realised loss on commodity
hedges
|
-
|
-
|
(22.5)
|
(22.5)
|
Total revenue
|
184.8
|
36.8
|
(22.5)
|
199.1
|
Depreciation, depletion and
amortisation - Oil and gas
|
(51.0)
|
(4.1)
|
-
|
(55.1)
|
Depreciation, depletion and
amortisation - Other
|
-
|
(0.1)
|
-
|
(0.1)
|
Impairment reversal/(charge) -
Intangibles2
|
1.0
|
-
|
(0.2)
|
0.8
|
Impairment reversal -
PP&E
|
23.3
|
3.8
|
-
|
27.1
|
Loss on disposal
|
-
|
(6.6)
|
-
|
(6.6)
|
Gain on fair value movement of
financial asset
|
-
|
0.3
|
-
|
0.3
|
Profit/(loss) before
tax1
|
108.3
|
16.9
|
(44.6)
|
80.6
|
Tax charge on
operations
|
(47.9)
|
-
|
-
|
(47.9)
|
Tax charge on impairment
reversal
|
(8.3)
|
-
|
-
|
(8.3)
|
|
|
|
|
|
|
|
1 Unallocated amounts included in profit/(loss) before tax
comprise corporate costs not attributable to an operating segment,
investment revenue, other gains and losses and finance
costs.
2 Includes $1.0m reversal of impairment of Block 125&126
tax receivable (other receivable - current), offset by $(0.2)m
write-off of seismic costs relating to Israel exploration Zones A
and C.
The accounting policies of the
reportable segments are the same as the Group's accounting
policies.
Included in revenues arising from
South East Asia and Egypt are revenues of $149.2m and $18.9m which
arose from the Group's two largest customers, who contributed more
than 10% to the Group's oil and gas revenue (2022: $182.5m and
$36.8m in South East Asia and Egypt from the Group's three largest
customers).
Geographical information
The Group's oil and gas revenue
and non-current assets (excluding other receivables) by
geographical location are separately detailed below where they
exceed 10% of total revenue or non-current assets,
respectively:
Revenue
All of the Group's oil and gas
revenue is derived from foreign countries. The Group's oil and gas
revenue by geographical location is determined by reference to the
final destination of oil or gas sold.
|
2023
$ million
|
2022
$ million
|
Vietnam
|
149.2
|
97.1
|
Egypt
|
18.9
|
36.8
|
China
|
-
|
87.7
|
|
168.1
|
221.6
|
Non-current
assets
|
2023
$ million
|
2022
$ million
|
Vietnam
|
240.4
|
332.5
|
Egypt
|
57.6
|
65.8
|
|
298.0
|
398.3
|
Excludes other assets.
4. Cost of sales
|
|
|
|
|
|
|
|
|
2023
|
|
|
2022
|
|
|
|
|
|
$ million
|
|
|
$
million
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and
amortisation
|
55.4
|
|
|
55.1
|
Production based taxes
|
|
|
|
|
|
10.5
|
|
|
14.7
|
Export duty
|
|
|
|
|
|
-
|
|
|
3.2
|
Production operating
costs
|
|
|
|
|
|
41.3
|
|
|
45.6
|
Inventories
|
|
|
|
|
|
4.0
|
|
|
(1.8)
|
|
|
|
|
|
111.2
|
|
|
116.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5. Other/restructuring expense
|
|
|
|
|
|
|
|
|
2023
|
|
|
2022
|
|
|
|
|
|
$ million
|
|
|
$
million
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Redundancy costs
|
|
|
|
|
|
-
|
|
|
0.1
|
Other
|
|
|
|
|
|
0.6
|
|
|
-
|
Premium - lease
transfer
|
|
|
|
|
|
-
|
|
|
0.7
|
|
|
|
|
|
0.6
|
|
|
0.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In 2023, other expenses of $0.6m
were due to changes in the best estimate of the adjustment relating
to the interim period between the economic date of 1 July 2020 and
the completion date of the disposal of 55% interest in the Egypt
concessions.
In 2022, $0.7m relates to the
transfer of the London office lease to a third party, at which
point the Company derecognised the right of use asset and
associated lease liability. In 2020, $1.2m was transferred to an
escrow account held by a third party (recorded within prepayments).
The amount was released to the income statement over 21 months on
the condition the new tenant paid the rent to the landlord. In
2022, the remaining balance of $0.7m was released from the escrow
account and paid to the new tenant.
6. Finance costs
|
2023
$ million
|
2022
$ million
|
Unwinding of discount on
provisions
|
2.0
|
1.3
|
Interest expense payable and
similar fees
|
6.4
|
6.0
|
RBL modification charge and
amortisation of capitalised borrowing costs
|
1.3
|
4.1
|
Net foreign exchange
losses
|
0.5
|
1.3
|
|
10.2
|
12.7
|
In 2023, $2.0m relates to the
unwinding of discount on the provisions for decommissioning (2022:
$1.3m). The provisions are based on the net present value of the
Group's share of the expenditure which may be incurred at the end
of the producing life of TGT and CNV (currently estimated to be 7 -
8 years) in the removal and decommissioning of the facilities
currently in place.
Following the June and December
2023 redeterminations and the $35.0m repayment of principal in
relation to the Group's reserve based lending facility, there was a
change in estimated future cash flows. As a result, a charge of
$2.7m (2022: $2.6m) was recognised in profit and loss, offset by an
amortisation adjustment of $(1.4)m (2022: amortised cost of
$1.5m).
7. Tax
|
2023
$ million
|
2022
$ million
|
Current tax charge
|
44.5
|
54.5
|
Deferred tax credit on
operations
|
(8.5)
|
(6.6)
|
Deferred tax (credit)/charge on
impairment
|
(16.2)
|
8.3
|
Total tax charge
|
19.8
|
56.2
|
The Group's corporation tax is
calculated at 50% (2022: 50%) of the estimated assessable profit
for the year in Vietnam. In Egypt, under the terms of the
concession, any local taxes arising are settled by EGPC.
During 2023 and 2022, both current and deferred taxation have
arisen in overseas jurisdictions only.
The charge for the year can be
reconciled to the (loss)/profit per the income statement as
follows:
|
2023
$ million
|
2022
$ million
|
(Loss)/ Profit before
tax
|
(29.0)
|
80.6
|
(Loss)/ Profit before tax at 50%
(2022: 50%)
|
(14.5)
|
40.3
|
|
|
|
Effects of:
|
|
|
Non-taxable income
|
-
|
(3.3)
|
Non-deductible expenses
|
18.0
|
5.6
|
Tax losses not
recognised
|
16.5
|
13.8
|
Adjustments to tax charge in
respect of previous periods
|
(0.2)
|
(0.2)
|
Tax charge for the year
|
19.8
|
56.2
|
The prevailing tax rate in
Vietnam, where the Group produces oil and gas, is 50%. The tax
charge in future periods may also be affected by the factors in the
reconciliation above.
In 2022, non-taxable income
relates to Vietnam impairment reversal of $(3.3)m. Non-deductible
expenses primarily relate to Vietnam impairment charges of $6.8m
and Vietnam DD&A charges for costs previously capitalised,
which are non-deductible for Vietnamese tax purposes of $10.4m
(2022: $5.6m). A further $0.8m (2022: $nil) relates to
non-deductible corporate costs including share scheme
incentives.
The Egypt concessions are subject
to corporate income tax at the standard rate of 40.55%, however
responsibility for payment of corporate income taxes falls upon
EGPC on behalf of our local subsidiary Pharos El Fayum (PEF). The
Group records a tax charge, with a corresponding increase in
revenues, for the tax paid by EGPC on its behalf. However, this is
only valid if PEF is in a historic profit making position and no
such tax has been recorded this year.
The effect from tax losses not
recognised relates to costs, primarily of the Company, deductible
for tax in the UK but not expected to be utilised in the
foreseeable future. For 2023, it also includes losses arising in
Egypt for which no future benefit can be obtained under the terms
of the concession agreement. During 2022, Egypt concessions
recorded a net profit before tax of $16.9m (profit after tax impact
of $8.5m) which has been offset against tax losses not recognised,
as Egypt is in a historic loss making position. The group did not
recognise deferred tax assets in relation to historical tax losses
available to offset future taxable profits of $18m on the basis
that there will be no future benefits arising from these losses as
any taxes in the future will be paid by EGPC on behalf of the
group.
8. Earnings per share
The calculation of the basic and
diluted earnings per share is based on the following
data:
|
Group
|
2023
$ million
|
2022
$ million
|
(Loss) /Gain for the purposes of
basic profit/(loss) per share
|
(48.8)
|
24.4
|
Effect of dilutive potential
ordinary shares - Cash settled share awards and options
|
-
|
(0.3)
|
(Loss)/ Gain for the purposes of
diluted profit/(loss) per share
|
(48.8)
|
24.1
|
|
Number
of shares (million)
|
2023
|
2022
|
Weighted average number of
ordinary shares
|
427.2
|
439.3
|
Effect of dilutive potential
ordinary shares - Share awards and options
|
-
|
0.9
|
Weighted average number of
ordinary shares for the purpose of diluted profit/(loss) per
share
|
427.2
|
440.2
|
In accordance with IAS 33 "Earnings
per Share", the effects of 2.9m antidilutive potential shares have
not been included when calculating dilutive earnings per share for
the year ended 31 December 2023, as the Group was loss
making.
9. Intangible assets
Intangible assets at 2023 year end
comprise the Group's exploration and evaluation projects which are
pending determination. Included in the additions is Blocks 125
& 126 in Vietnam $3.1m (2022: $3.1m) and Egypt $8.0m (2022:
$1.0m), of which $6.7m (2022: $0.9m) relates to North Beni
Suef.
At June 2020 and December 2020 an
impairment indicator of IFRS 6 was triggered following the Group's
decision to defer all non-essential investment in Vietnam and Egypt
at this point. No substantive expenditure for its exploration areas
in Vietnam and Egypt was either budgeted or planned in the near
future. Exploration costs including costs associated with Blocks
125 & 126 in Vietnam of $17.9m and costs associated with Egypt
projects in the amount of $5.3m ($2.4m share post-farm out) were
written off in the income statement in accordance with the Group's
accounting policy on oil and gas exploration and evaluation
expenditure.
During 2023, approval was received
from the Vietnamese Government in June for the two-year extension
to Phase One of the Exploration Period under Blocks 125 & 126
PSC to 8 November 2025. On 20 July 2023, the Company published an
independent assessment by ERCE for Block 125, which confirmed a
range of gross unrisked prospective oil resources of between 1,178
MMstb (1U) and 29,785 MMstb (3U) with a Mean value of 13,328 MMstb
for the Prospects in the North West area of Block 125 currently
covered fully or partially by 3D seismic. These resources do not
include Leads already identified in Blocks 125 & 126 but not
yet covered by 3D seismic. Work is ongoing to progress well
planning and discussions are ongoing to secure a partner ahead of
drilling the commitment well in 2025. Whilst ongoing costs for
exploration are therefore forecast and funds available for future
exploration, there is insufficient certainty of full recovery to
justify the reversal of the previous impairment charges in 2020.
The accumulated impairment charges against Vietnam exploration and
evaluation expenditure at 31 December 2023 therefore remains at
$17.9m (2022: $17.9m).
In Egypt, as part of the planned
work programme for 2023, an exploration well was drilled on El
Fayum in July 2023. It was the first commitment well in the Abu
Roash G and Upper Bahariya formations and the well is set-up for
re-entry and testing in 2024. During 2023, as no further
substantive exploration or evaluation is planned or budgeted for
the El Fayum Batran-1X well drilled in 2021, the asset of $1.6m has
been impaired in full.
On NBS, the first exploration
commitment well (NBS-SW1X) was declared a commercial discovery in
September 2023 and put on production in December 2023. As a result,
exploration costs of $2.9m relating to the development lease were
reclassified to property, plant and equipment. A further dry-hole
well of $0.8m (NBS-SW5X) was impaired in full, leaving $4.1m
(post-2020 impairment charge of $1.2m) in exploration and
evaluation expenditure. No substantive expenditure is budgeted or
planned in the future in relation to the NBS exploration acreage
and the remaining balance of $4.1m has been fully
impaired.
The accumulated impairment charges
against Egypt exploration and evaluation expenditure at 31 December
2023 stands at $8.9m (2022: $2.4m).
10. Property, plant and equipment
As a result of previously
recognised impairment losses, combined with the ongoing oil price
volatility, economic uncertainty leading to high inflation globally
and discount rates, and movements in 2P reserves, we have tested
each of our oil and gas producing properties for impairment. The
results of these impairment tests are summarised below. For each
producing property, the recoverable amount has been determined
using the value in use method. The recoverable amount is calculated
using a discounted cash flow valuation of the 2P production
profile.
Summary of Impairments - Oil and Gas
Properties
|
|
|
|
|
2023
|
2023
|
TGT
$ million
|
CNV
$ million
|
El Fayum
$ million
|
NBS
$ million
|
Total
$ million
|
Pre-tax impairment
(charge)/credit
|
(46.3)
|
0.3
|
(11.0)
|
(1.9)
|
(58.9)
|
Deferred tax
credit/(charge)
|
16.5
|
(0.3)
|
-
|
-
|
16.2
|
Post-tax impairment charge
|
(29.8)
|
-
|
(11.0)
|
(1.9)
|
(42.7)
|
|
|
|
|
|
|
Reconciliation of carrying amount:
|
|
|
|
|
|
As at 1 January 2023
|
242.4
|
76.4
|
62.5
|
-
|
381.3
|
Additions
|
1.3
|
3.0
|
7.6
|
-
|
11.9
|
Transfer from intangible
assets
|
-
|
-
|
-
|
2.9
|
2.9
|
Changes in decommissioning asset
1
|
-
|
(2.5)
|
-
|
-
|
(2.5)
|
DD&A
|
(38.8)
|
(12.2)
|
(4.4)
|
-
|
(55.4)
|
Impairment
(charge)/reversal
|
(46.3)
|
0.3
|
(11.0)
|
(1.9)
|
(58.9)
|
As at 31 December 2023
|
158.6
|
65.0
|
54.7
|
1.0
|
279.3
|
|
|
|
|
|
2022
|
2022
|
TGT
$ million
|
CNV
$ million
|
El Fayum
$ million
|
NBS
$ million
|
Total
$ million
|
Pre-tax impairment
reversal
|
19.7
|
3.6
|
3.8
|
-
|
27.1
|
Deferred tax charge
|
(6.9)
|
(1.4)
|
-
|
-
|
(8.3)
|
Post-tax impairment reversal
|
12.8
|
2.2
|
3.8
|
-
|
18.8
|
|
|
|
|
|
|
Reconciliation of carrying amount:
|
|
|
|
|
|
As at 1 January 2022
|
266.0
|
84.2
|
49.2
|
-
|
399.4
|
Additions
|
7.0
|
3.2
|
13.6
|
-
|
23.8
|
Changes in decommissioning
asset1
|
(11.1)
|
(2.8)
|
-
|
-
|
(13.9)
|
DD&A
|
(39.2)
|
(11.8)
|
(4.1)
|
-
|
(55.1)
|
Impairment reversal
|
19.7
|
3.6
|
3.8
|
-
|
27.1
|
As at 31 December 2022
|
242.4
|
76.4
|
62.5
|
-
|
381.3
|
1 Changes in decommissioning asset for CNV is due to revision
of field abandonment plan and discount rate, whereas TGT reflects
an immaterial change in discount rate only (2022: Changes in
decommissioning asset for TGT is due to changes in discount rate
and the field abandonment plan, whereas CNV reflects the change in
discount rate only).
Vietnam
The key assumptions to which the
recoverable amount is most sensitive are oil price, discount rate
and 2P reserves (2022: oil price, discount rate and 2P reserves).
In 2023, for TGT, there was a downwards technical revision of 2P
reserves and the production profile compared to prior year. For
CNV, there was upwards revision of the production profile following
strong performance from the new lateral well. As at 31 December
2023, the fair value of the assets are estimated based on a
post-tax nominal discount rate of 12.6% (2022: 13.3%) and a Brent
oil price of $81.5/bbl in 2024, $79.0/bbl in 2025, $79.2/bbl in
2026, $76.3/bbl in 2027 plus inflation of 2.0% thereafter (2022: an
oil price of $88.3/bbl in 2023, $84.8/bbl in 2024, $79.4/bbl in
2025, $74.5/bbl in 2026 plus inflation of 2.0%
thereafter).
Testing of sensitivity cases
indicated that a $5/bbl reduction in long-term oil price used when
determining the value in use method would result in post-tax
impairments charge (compared to new NBV) of $15.1m on TGT and $3.1m
on CNV. A 1% increase in discount rate would result in post-tax
impairments of $2.4m on TGT and $0.8m on CNV.
We have also run sensitivities
utilising the IEA (International Energy Agency) scenarios described
as being consistent with achieving the COP26 agreement goal to
reach net zero by 2050 (the "Net Zero price scenario"). The nominal
Brent prices used in this scenario were as follows; $81.5/bbl in
2024, $79.0/bbl in 2025, $79.2/bbl in 2026, $72.2/bbl in 2027,
$64.8/bbl in 2028, $57.2/bbl in 2029, $49.2/bbl in 2030 and
$49.2/bbl in 2031. Using these prices and a 12.6% discount rate
would result in additional post-tax impairments of $10.3m on TGT
and $4.0m on CNV.
The impairment tests for TGT and
CNV assume that production ceases in 2029 and 2030 respectively,
assuming the licences are extended by at least three years
reflecting past practice and a commercial assessment (and
consistent with the reserves estimates independently audited by
RISC Advisory Pty Ltd.) that it is highly probable given the
economic circumstances and current discussions. The current
negotiations over terms are for a longer duration than that assumed
and would be expected to improve the value in use
calculated.
Egypt
The key assumptions to which the
recoverable amount is most sensitive are oil price, discount rate,
capital spend and 2P reserves (2022: oil price, discount rate,
capital spend and 2P reserves). In 2023, there was a downwards
technical revision of El Fayum 2P reserves and production profile
compared to prior year and NBS 2P reserves were recognised for the
first time following commencement of production in December
2023. As at 31 December 2023, the fair value of the assets
are estimated based on a post-tax nominal discount rate of 18.0%
(2022: 15.9%) and a Brent oil price of $81.5/bbl in 2024, $79.0/bbl
in 2025, $79.2/bbl in 2026, $76.3/bbl in 2027 plus inflation of
2.0% thereafter (2022: an oil price of $88.3/bbl in 2023, $84.8/bbl
in 2024, $79.4/bbl in 2025, $74.5/bbl in 2026 plus inflation of
2.0% thereafter).
Testing of sensitivity cases
indicated that a $5/bbl reduction in long term oil price used when
determining the value in use method would result in impairment
charges (compared to new NBV) of $7.1m for El Fayum and $0.9m for
NBS. A 1% increase in discount rate would result in impairment
charges of $2.1m on El Fayum and $0.1m on NBS. We have also run a
sensitivity using 18.0% discount rate and the Net Zero price
scenario which would result in an additional impairment of $23.5m
on El Fayum and $1.0m on NBS.
Other considerations
It is not considered possible to
provide meaningful sensitivities in relation to 2P reserves for any
of the Group's oil and gas producing properties, as the impact of
any changes in 2P reserves on recoverable amount would depend on a
variety of factors, including the timing of changes in production
profile and the consequential effect on the expenditure required to
both develop and extract the reserves.
Other fixed assets comprise office
fixtures and fittings and computer equipment.
11. Hedge transactions
During 2023, Pharos entered into
zero cost collar hedges to protect the Brent component of forecast
oil sales and to ensure future compliance with its obligations
under the RBL over the producing assets in Vietnam.
The commodity hedges run until
June 2025 and are settled monthly. For 2023, 36% of the Group's
total production was hedged, securing average floor and ceiling
prices for the hedged volumes at $64.5/bbl and $100.8/bbl,
respectively. The Group's RBL requires the Company to hedge at
least 35% of Vietnam RBL production volumes and the current hedging
programme meets this requirement through to December 2024, leaving
72% of Group production unhedged as at 31 December 2023 (2022: 30%
of the Group's total production was hedged, securing a minimum
price for these hedged volumes of $67.9 per barrel).
A summary of hedges outstanding as
at 31 December 2023 is presented below, which are all zero cost
collar.
|
|
1Q24
|
2Q24
|
3Q24
|
4Q24
|
1Q25
|
2Q25
|
Production hedge per quarter -
000/bbls
|
|
120
|
120
|
150
|
120
|
60
|
60
|
Min. Average value of hedge -
$/bbl
|
|
63.00
|
63.00
|
64.40
|
63.00
|
64.00
|
64.00
|
Max. Average value of hedge -
$/bbl
|
|
91.50
|
87.88
|
88.66
|
89.00
|
90.00
|
90.00
|
|
|
|
|
|
|
|
|
|
Pharos has designated the zero
cost collars as cash flow hedges. This means that the effective
portion of unrealised gains or losses on open positions will be
reflected in other comprehensive income. Every month, the realised
gain or loss will be reflected in the revenue line of the income
statement. For the year end 31 December 2023, a loss of $0.2m was
realised (2022: loss of $22.5m). The outstanding unrealised gain on
open position as at 31 December 2023 amounts to $0.1m (2022: loss
of $0.7m).
The carrying amount of the zero
cost collars is based on the fair value determined by a financial
institution. As all material inputs are observable, they are
categorised within Level 2 in the fair value hierarchy. It is
presented in "Trade and other receivables" or "Trade and other
payables" in the consolidated statement of financial position. The
receivable position as of December 2023 was $0.1m (2022: liability
position $1.1m).
12. Distribution to Shareholders
|
|
|
Amounts recognised as distributions to equity holders in the
year:
|
2023
$ million
|
2022
$ million
|
Final dividend for the year ended
31 December 2022 of 1.00 pence per share, paid in the
year
|
5.6
|
-
|
Interim dividend for the year
ended 31 December of 2023 of 0.33 pence per share, declared in
year
|
1.7
|
-
|
|
7.3
|
-
|
|
|
|
Proposed final dividend for the
year ended 31 December 2023 of 0.77 pence per share
|
4.2
|
-
|
|
|
|
|
The proposed final dividend for
the year ended 31 December 2023 of 0.77 pence per share takes the
2023 full-year dividend to 1.10 pence per share, in excess of the
minimum 10% of Operating Cash Flow (OCF) per the Company's dividend
policy.
The final dividend of 1.00 pence
per ordinary share in respect of the year ended 31 December 2022
($5.6m) was paid on 12 July 2023. The interim dividend of 0.33
pence per ordinary share was paid on 24 January 2024. The proposed
final dividend of 0.77 pence per ordinary share in respect of the
year ended 31 December 2023, subject to approval of shareholders at
the Company's 2024 AGM in May, is payable on 19 July 2024 to all
shareholders on the register at the close of business on 14 June
2024.
13. Reconciliation of operating profit/(loss) to
operating cash flows
|
|
|
Group
|
|
|
Company
|
|
|
2023
$ million
|
2022
$
million
|
|
2023
$ million
|
2022
$
million
|
Operating (loss)/profit
|
|
(18.1)
|
100.2
|
|
(58.6)
|
44.2
|
Share-based payments
|
|
0.9
|
1.3
|
|
0.9
|
1.3
|
Depletion, depreciation and
amortisation
|
|
55.6
|
55.2
|
|
-
|
-
|
Impairment
charge/(reversal)
|
|
65.4
|
(27.9)
|
|
49.4
|
(53.9)
|
Operating cash flows before movements in working
capital
|
|
103.8
|
128.8
|
|
(8.3)
|
(8.4)
|
|
|
|
|
|
|
|
Decrease/(increase) in
inventories
|
|
3.9
|
(0.9)
|
|
-
|
-
|
(Increase)/decrease in receivables
1
|
|
(19.1)
|
(7.7)
|
|
(0.2)
|
1.2
|
Increase/(decrease) in
payables
|
|
0.2
|
(9.5)
|
|
0.1
|
(1.8)
|
Cash generated by (used in) operations
|
|
88.8
|
110.7
|
|
(8.4)
|
(9.0)
|
|
|
|
|
|
|
|
Interest received
|
|
0.4
|
0.1
|
|
0.3
|
0.1
|
Other/restructuring expense
outflow
|
|
-
|
(2.7)
|
|
-
|
(2.7)
|
Income taxes paid
|
|
(44.3)
|
(54.7)
|
|
-
|
-
|
Net cash from (used in) operating activities
|
|
44.9
|
53.4
|
|
(8.1)
|
(11.6)
|
1 Includes $2.2m (2022: $1.5m) increase in risk factor
provision in respect of Egypt trade receivables.
During the year a total of $3.2m
of trade receivables due from EGPC in Egypt were settled by way of
non-cash offset, out of which $2.2m relates to a second instalment
of assignment bonus due to EGPC in relation to the IPR Farm out,
$0.5m relates to a bonus due to EGPC for the NBS development lease
and $0.5m relates to training bonuses and fees paid to EGPC for
participation in a bid round process.
During 2022, a total of $4.6m of
trade receivables due from EGPC in Egypt were settled by way of
non-cash offset, out of which $1.0m relates to 3rd Amendment
signature bonus, $1.1m was set against trade payables, $2.0m
Assignment bonus settled on behalf of the Farm out partner, IPR,
and $0.5m Group's share of NBS Concession assignment
bonus.
14. Disposal of 55% interest in Egypt Concessions and fair
value movement
Following the completion of the
farm-out transaction of Egyptian assets to IPR, the accounting for
the assets reflect the following:
The economic date of the
transaction was 1 July 2020, with completion on 21 March
2022.
Pharos owned and managed the
business up to completion. On completion, an adjustment to
compensate for net cash flows since the economic date has been
adjusted for in the level of carry to be provided by IPR to
Pharos.
In the financial statements, for
the period post completion, Pharos 45% share of field costs -
capex, opex and G&A - are accounted for as incurred by Pharos,
although all such costs are paid by IPR and set off against the
carry.
All revenues earned are paid
direct to Pharos.
The firm consideration was
received in two tranches, $2.0m in September 2021 and $3.0m on 30
March 2022.
The carry of $35.9m is
disproportionate funding contribution from IPR adjusted for working
capital and interim period adjustments from the effective economic
date of 1 July 2020 and completion date.
Disposal of asset held for sale:
|
2022
$ million
|
Intangible assets
|
(2.3)
|
Property, plant and
equipment
|
(54.4)
|
Inventories
|
(5.9)
|
Trade and other
receivables
|
(2.3)
|
Trade and other
payables
|
8.3
|
Disposal of 55% of El Fayum and NBS
|
(56.6)
|
|
|
Firm consideration received - IPR
Cash Receipts
|
5.0
|
Other receivable -
Carry
|
36.3
|
Other receivable - contingent
consideration
|
13.6
|
Other receivable with
IPR
|
0.5
|
Consideration received and to be received
|
55.4
|
Assignment fees payable to EGPC
|
(3.7)
|
Success fees paid on completion
|
(1.7)
|
Loss on disposal
|
(6.6)
|
$0.4m reduction in the amount
classified as the carry element from $36.3m to $35.9m following a
change in the best estimate of the adjustment relating to the
interim period between the economic date of 1 July 2020 and the
completion date was charged to the income statement as part of
"Other/restructuring expense" during 2023.
The fair value movement of $0.3m
was charged to the income statement during 2023. This is due to
$0.4m revision of the contingent consideration, partially offset by
$0.1m reduction in contingent liability (assignment fee). The fair
value movement of $0.3m relating to revision of the contingent
consideration and credited to the income statement during 2022 was
reclassified from "Loss on disposal" to "(Loss)/Gain on fair value
movement of financial asset" to be consistent with 2023
presentation.
15. Subsequent events
EGPC Trade Receivables
On 26 March 2024, following
announcements from the Egyptian government of increased liquidity
in-country, the Group received notification from EGPC that $10m
will be paid as partial settlement of outstanding trade receivables
following payment delays through 2023. The funds will clear on 27
March 2024, according to the swift confirmation
received.
16. Preliminary results announced
Copies of the announcement will be
available to download from www.pharos.energy. The Annual Report and
Accounts, together with notice of the 2024 AGM, will be posted to
shareholders in due course.
Non-IFRS measures
The Group uses certain measures of
performance that are not specifically defined under IFRS or other
generally accepted accounting principles. These non-IFRS measures
include cash operating costs per barrel, DD&A per barrel,
gearing, free cash flow and operating cash per share.
For the RBL covenant compliance, three Non-IFRS measures are
included: Net debt, EBITDAX and Net debt/EBITDAX.
Cash-operating costs per barrel
Cash operating costs are defined
as cost of sales less DD&A, production based taxes, movement in
inventories and certain other immaterial cost of sales.
Cash operating costs for the
period is then divided by barrels of oil equivalent produced. This
is a useful indicator of cash operating costs incurred to produce
oil and gas from the Group's producing assets.
|
|
|
|
|
|
|
|
|
2023
|
|
|
2022
|
|
|
|
|
|
$ million
|
|
|
$
million
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of sales
|
111.2
|
|
|
116.8
|
Less:
|
|
|
|
|
Depreciation, depletion and
amortisation
|
(55.4)
|
|
|
(55.1)
|
Production based taxes
|
(10.5)
|
|
|
(14.7)
|
Export duty
|
-
|
|
|
(3.2)
|
Inventories
|
(4.0)
|
|
|
1.8
|
Trade receivable risk factor
provision
|
(2.2)
|
|
|
(1.5)
|
Other cost of sales
|
|
|
|
|
(1.8)
|
|
|
(1.3)
|
Cash operating costs
|
|
|
|
|
37.3
|
|
|
42.8
|
Production (BOEPD)
|
|
|
|
|
6,508
|
|
|
7,166
|
Cash operating cost per BOE ($)
|
|
|
|
|
15.70
|
|
|
16.36
|
Cash-operating costs per barrel by Segment
(2023)
|
|
|
|
|
|
|
|
|
|
Vietnam
|
|
Egypt
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
$ million
|
|
$ million
|
|
$ million
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of sales
|
|
|
|
|
|
|
95.6
|
|
15.6
|
|
111.2
|
|
Less:
Depreciation, depletion and
amortisation
|
(51.0)
|
|
(4.4)
|
|
(55.4)
|
|
Production based taxes
|
(10.4)
|
|
(0.1)
|
|
(10.5)
|
|
Inventories
|
(3.9)
|
|
(0.1)
|
|
(4.0)
|
|
Trade receivable risk factor
provision
|
-
|
|
(2.2)
|
|
(2.2)
|
|
Other cost of sales
|
(1.5)
|
|
(0.3)
|
|
(1.8)
|
|
|
|
|
|
|
|
Cash operating costs
|
|
|
|
|
|
28.8
|
|
8.5
|
|
37.3
|
Production (BOEPD)
|
|
|
|
|
|
5,127
|
|
1,381
|
|
6,508
|
Cash operating cost per BOE ($)
|
|
|
|
|
|
15.39
|
|
16.86
|
|
15.70
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortisation costs per
barrel
DD&A per barrel is calculated
as net book value of oil and gas assets in production, together
with estimated future development costs over the remaining 2P
reserves. This is a useful indicator of ongoing rates of
depreciation and amortisation of the Group's producing
assets.
|
|
|
|
|
|
|
|
|
2023
|
|
|
2022
|
|
|
|
|
|
$ million
|
|
|
$
million
|
Depreciation, depletion and amortisation
|
(55.4)
|
|
|
(55.1)
|
Production (BOEPD)
|
|
|
|
|
6,508
|
|
|
7,166
|
DD&A per BOE ($)
|
|
|
|
|
23.32
|
|
|
21.07
|
DD&A per barrel by segment (2023)
|
|
|
|
|
|
|
|
|
Vietnam
|
|
Egypt
|
|
Total
|
|
|
|
|
|
|
|
|
|
$ million
|
|
$ million
|
|
$ million
|
Depreciation, depletion and amortisation
|
(51.0)
|
|
(4.4)
|
|
(55.4)
|
|
Production (BOEPD)
|
|
|
|
|
5,127
|
|
1,381
|
|
6,508
|
DD&A per BOE ($)
|
|
|
|
|
27.25
|
|
8.73
|
|
23.32
|
Net Debt
Net debt comprises
interest-bearing bank loans, less cash and cash
equivalents.
|
|
|
|
|
|
|
|
|
2023
|
2022
|
|
|
|
|
|
|
|
|
|
$ million
|
$
million
|
Cash and cash
equivalents
|
32.6
|
45.3
|
|
Borrowings 1
|
|
|
|
|
(39.2)
|
(74.2)
|
Net Debt
|
|
|
|
|
(6.6)
|
(28.9)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 Excludes unamortised capitalised set up costs
EBITDAX
EBITDAX is earnings from
continuing activities before interest, tax, DD&A, impairment
charge/(reversal) of PP&E and intangibles, exploration
expenditure including pre-licence costs and Other/restructuring
expense items in the current year.
|
|
|
|
|
|
|
|
|
2023
|
2022
|
|
|
|
|
|
|
|
|
|
$ million
|
$
million
|
Operating (loss)/profit
|
(18.1)
|
100.2
|
Depreciation, depletion and amortisation
|
55.6
|
55.2
|
Pre-licence costs
|
0.4
|
-
|
Impairment charge/(reversal)
|
65.4
|
(27.9)
|
EBITDAX
|
|
|
|
|
103.3
|
127.5
|
|
|
|
|
|
|
|
|
|
|
|
|
Net debt/EBITDAX
Net Debt/EBITDAX ratio expresses
how many years it would take to repay the debt, if net debt and
EBITDAX stay constant.
|
|
|
|
|
|
|
|
|
2023
|
2022
|
|
|
|
|
|
|
|
|
|
$ million
|
$
million
|
Net Debt
|
(6.6)
|
(28.9)
|
EBITDAX
|
103.3
|
127.5
|
Net Debt/EBITDAX
|
|
|
|
|
(0.06)
|
(0.23)
|
|
|
|
|
|
|
|
|
|
|
|
|
Gearing
Debt to equity ratio is calculated
by dividing interest-bearing bank loans by stockholder equity. The
debt to equity ratio expresses the relationship between external
equity (liabilities) and internal equity (stockholder
equity).
|
|
|
|
|
|
|
|
|
2023
|
2022
|
|
|
|
|
|
|
|
|
|
$ million
|
$
million
|
Total Debt 1
|
39.2
|
74.2
|
Total Equity
|
273.5
|
330.6
|
Debt to Equity
|
|
|
|
|
0.14
|
0.22
|
|
|
|
|
|
|
|
|
|
|
|
|
1 Excludes unamortised capitalised set up costs
Free cash flow
Free cash flow is calculated by
subtracting capital cash expenditure from net cash from operating
activities.
|
|
|
|
|
|
|
|
|
2023
|
2022
|
|
|
|
|
|
|
|
|
|
$ million
|
$
million
|
Net cash from operating activities
|
44.9
|
53.4
|
Capital cash expenditure
|
(26.7)
|
(31.9)
|
Free cash flow
|
|
|
|
|
18.2
|
21.5
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating cash per share
Operating cash per share is
calculated by dividing net cash from (used in) continuing
operations by number of shares in the year.
|
|
|
|
|
|
|
|
|
2023
|
2022
|
|
|
|
|
|
|
|
|
|
$ million
|
$
million
|
Net cash from operating activities
|
44.9
|
53.4
|
Weighted number of shares in the year
|
427,170,044
|
439,253,641
|
Operating cash per share
|
|
|
|
|
0.11
|
0.12
|
|
|
|
|
|
|
|
|
|
|
|
|
Glossary of Terms
AGM
Annual general meeting
bbl
Barrel
boe or BOE
Barrels of oil
equivalent
boepd or BOEPD
Barrels of oil equivalent per
day
bopd
Barrels of oil per day
BSR
Binh Son Refining and Petrochemical
JSC, the operator of the Dung Quất refinery, Quảng Ngãi Province,
Vietnam
cash
Cash, cash equivalent and liquid
investments
capex
Capital expenditure
CEO
Chief Executive Officer
CPR
Competent person's report or
equivalent (e.g. mineral expert's report)
CNV
Ca Ngu Vang field located in Block
9-2, Vietnam
Company or Pharos
Pharos Energy plc
Contingent Resources, contingent resources
or CR
Those quantities of petroleum to be
potentially recoverable from known accumulations by application of
development projects but which are not currently considered to be
commercially recoverable due to one or more
contingencies
Contractor
The party or parties identified as
being, or forming part of, the "CONTRACTOR" as defined in the El
Fayum Concession or, as the case may be, the North Beni Suef
Concession
DD&A
Depreciation, depletion and
amortisation
EBITDAX
Earnings before interest, tax,
DD&A, impairment of PP&E and intangibles, exploration
expenditure and other/restructuring items in the current
year
EGP
Egyptian Pounds, the lawful
currency of the Arab Republic of Egypt
EGPC
Egyptian General Petroleum
Corporation, an Egyptian state oil and gas company and the industry
regulator
El
Fayum or the El Fayum Concession
The concession agreement for
petroleum exploration and exploitation entered into on 15 July 2004
between the Arab Republic of Egypt, EGPC and Pharos El Fayum in
respect of the El Fayum area, Western Desert, as amended from time
to time
ERCE
ERC Equipoise Limited, an
independent energy consulting group
Financial Statements
The preliminary financial
statements of the Company and the Group for the year ended 31
December 2023
FPSO
Floating, production, storage and
offloading Vessel
G&A
General and
administration
GHG
Greenhouse gas
Group
Pharos and its direct and indirect
subsidiary undertakings
1H
The first half of a calendar
year
2H
The second half of a calendar
year
HLJOC
Hoang Long Joint Operating Company,
the operator of the TGT field on Block 16-1, Vietnam
HVJOC
Hoan Vu Joint Operating Company,
the operator of the CNV field on Block 9-2, Vietnam
IFRS
International Financial Reporting
Standards
IMF
The International Monetary
Fund
IPR or IPR Energy Group
The IPR Energy group of companies,
including IPR Lake Qarun and IPR Energy AG, or such of them as the
context may require
IPR Lake Qarun
IPR Lake Qarun Petroleum Co, an
exempted company with limited liability organised and existing
under the laws of the Cayman Islands (registration number 379306),
a wholly owned subsidiary of IPR Energy AG
JOC
Joint operating company
JV
Joint venture
km
Kilometre
km2
Square kilometre
LTI
Lost Time Injury
LTIP
Long Term Incentive Plan
m
Million (where used to describe a
monetary amount)
McDaniel
McDaniel & Associates
Consultants Ltd
mmboe
Million barrels of oil
equivalent
MMstb
Millions of stock tank
barrels
MOIT
The Vietnamese Ministry of Industry
and Trade
NAV
Net asset value
NBE
The National Bank of Egypt, the
largest Egyptian commercial bank and owned by the state of
Egypt
NBS, North Beni Suef or the
North Beni Suef
Concession
The concession agreement for
petroleum exploration and exploitation entered into on 24 December
2019 between the Arab Republic of Egypt, EGPC and Pharos El Fayum
in respect of the North Beni Suef area, Nile Valley
Net Zero Roadmap
The Group's detailed net zero
roadmap to achieve net zero GHG emissions by 2050, published in
December 2023
OCF
Operating cash flow
opex
Operational expenditure
PEF
Pharos El Fayum, a wholly owned
subsidiary of the Company holding the Group's participating
interest in El Fayum and North Beni Suef
Petrosilah
An Egyptian joint stock company
held 50/50 between EGPC and the Contractor parties under the El
Fayum Concession (being IPR Lake Qarun and PEF)
Petrovietnam
Vietnam Oil and Gas Group, the
Vietnamese state-owned integrated oil and gas company
PP&E
Property, plant and
equipment
prospect
An identified trap that may contain
hydrocarbons. A potential hydrocarbon accumulation may be described
as a lead or prospect depending on the degree of certainty in that
accumulation. A prospect generally is mature enough to be
considered for drilling
PSC
Production sharing contract or
production sharing agreement
Reserves or reserves
Reserves are those quantities of
petroleum anticipated to be commercially recoverable by application
of development projects to known accumulations from a given date
forward under defined conditions. Reserves must further satisfy
four criteria: they must be discovered, recoverable, commercial and
remaining based on the development projects applied
RBL
Reserve-based lending
facility
RFDP
Revised field development
plan
RISC
RISC Advisory Pty Ltd
TGT
Te Giac Trang field located in
Block 16-1, Vietnam
TLJOC
Thang Long Joint Operating Company,
the operator of Block 15-2/01, Vietnam, with which the HLJOC shares
access to the FPSO used for TGT production
UK
United Kingdom
USD, US dollars or $
United States dollars, the lawful
currency of the United States of America
£
UK Pound Sterling
1C
Low estimate scenario of Contingent
Resources
1P
Equivalent to proved Reserves;
denotes low estimate scenario of Reserves
1U
Low estimate scenario of gross
unrisked prospective resources
2C or 2C Contingent Resources
Best estimate scenario of
Contingent Resources
2P
Reserves or 2P Commercial Reserves
Equivalent to the sum of proved
plus probable Reserves; denotes best estimate scenario of
Reserves
3C
High estimate scenario of
Contingent Resources
3P
Equivalent to the sum of proved,
probable and possible Reserves; denotes high estimate scenario of
Reserves
3U
High estimate scenario of gross
unrisked prospective resources