TIDMPHAR
RNS Number : 8370T
Pharos Energy PLC
22 March 2023
22 March 2023
Pharos Energy plc
("Pharos" or the "Company" or, together with its subsidiaries,
the "Group")
2022 Preliminary Results
Pharos Energy plc, an independent energy company, announces its
preliminary results for the year ended 31 December 2022. A
conference call will take place at 10.00 GMT today.
Jann Brown, Chief Executive Officer, commented:
" 2022 was a year of significant change for Pharos. Amidst the
macroeconomic challenges and ongoing volatility specifically in
Egypt, we delivered crucial milestones that have allowed us to
rebuild resilience in the balance sheet, helping us to deliver on
our strategy of creating long term, sustainable value for our
shareholders via both regular cash returns and organic growth.
Pharos is in a much stronger position with the 2023 work programme
underway and a focus on sustainable cash generation with capital
discipline to deliver returns to our stakeholders.
I would like to thank our global colleagues, investors,
government and JV/JOC partners for their continued support and I
look forward to updating stakeholders as Pharos works towards a new
phase of growth in 2023."
2022 Corporate Highlights
-- Enhanced fiscal terms secured in Egypt through the signature
of the Third Amendment to the El Fayum Concession in January 2022,
increasing Contractor's share of revenue from c.42% to c.50%
-- Completion of farm-out transaction and transfer of
operatorship of Egyptian assets to IPR in March 2022, delivering a
carry of the Group's remaining 45% interest, expected to continue
into Q3 2023
-- Completion of $3m share buyback programme announced in July
2022, with a further $3m committed for 2023
-- Announcement of policy for annual dividend, based on Operating Cash Flow
-- Reshaping of Board structure and composition from 9 to 6
Directors with Jann Brown appointed as Chief Executive Officer in
March 2022
-- Commitment to achieve Net Zero GHG emissions from all our
assets by no later than 2050 announced in September 2022
-- Establishment of an Emissions Management Fund, under which we
will set aside $0.25 for each barrel sold at an oil price above
$75/bbl from 2023 to support emissions management projects
2022 Operational Highlights
-- Total Group working interest 2022 production 7,166 boepd net
(1) (2021: 8,878 boepd net, 7,533 boepd net on a comparative
basis(1) ), in line with production guidance;:
- Vietnam production 5,418 boepd net (2021: 5,560 boepd net)
- Egypt production 1,748 bopd (1) net (2021: 3,318 bopd; 1,973
bopd on a comparative basis(1) )
-- In Vietnam:
- D rilling programme for two TGT development wells completed in
H2 2022, on time and under budget
- Drilling of one CNV well started in H2 2022 and completed in
Q1 2023, on time and under budget
- Additional interpretation work on the 3D Seismic in Block 125
is continuing and showing promising results with a number of
Prospects identified
-- In Egypt:
- Commencement of the main El Fayum multi-year and multi-well
development programme in Q2 2022 after farm-down
- Seven wells put on production in 2022, plus one additional well drilled in Q4 2022
- Rig on a long-term contract secured in July 2022, providing a
stable platform for a continuous drilling campaign
- Request for a short extension on North Beni Suef (NBS) granted in Q4 2022
- Drilling commenced on the first of two NBS commitment
exploration wells in parallel with acquisition of additional 3D
seismic
2022 Financial Highlights
-- Group revenue of $221.6m (2 3) (2021: $163.8m (2 3) )
-- Cash generated from operations $110.7m (2021: $51.5m)
-- Operating cash flow $53.4m (6) (2021: $10.8m)
-- Cash operating costs of $16.36/bbl (4) (2021: $16.05/bbl (4) )
-- Cash balances as at 31 December 2022 of $45.3m (2021: $27.1m)
-- Net Debt as at 31 December 2022 of $28.9m (4,5) (2021: $57.5m (4,5) )
-- Profit for the year of $24.4m (2021: loss $4.7m)
-- Net Debt to EBITDAX of 0.23x (4) (2021: 1.00x (4) )
2023 Highlights and Outlook
-- Continuation of share buyback programme announced in January,
with a further $3m committed for 2023 so far
-- Dividend payment of 1p per share to be proposed for approval at 2023 AGM
-- Net Zero roadmap to be published in H2 2023
-- Forecast cash capex for 2023 c.$38m (c.$23m after Egyptian carry by IPR)
-- Group working interest 2023 production guidance 6,050 - 7,500 boepd net:
- Vietnam 2023 production guidance 4,700 - 5,700 boepd net
- Egypt 2023 production guidance 1,350 - 1,800 bopd net
(equivalent to gross production of 3,000 - 4,000 bopd)
-- In Vietnam
- Work on submitting Revised Field Development Plans (RFDPs) for
two wells on TGT and one on CNV is progressing, with all wells
remaining in contingent budget until approval
- Application for extensions to TGT & CNV licences submitted to partners for approval
- Application for extension to Blocks 125 & 126 licence
submitted in December 2022, as no suitable rigs were available for
drilling in 2023, and is now with the Prime Minister's office for
approval
- Discussions ongoing with a number of interested parties to
secure a farm-in partner before drilling the commitment well on
Block 125
-- In Egypt
- Multi-well development drilling in El Fayum continues in 2023,
with nine wells planned for the year
- Two commitment exploration wells expected to be drilled in the El Fayum Concession
- Drilling of first commitment exploration well on NBS underway,
with the additional commitment exploration well to follow later in
the year. An additional extension of the exploration period until
September 2023 was granted by EGPC in March 2023
- Acquisition of the c.110 km2 of additional 3D seismic at NBS has started
(1) The farm-down transaction and transfer of operatorship of
Pharos' Egyptian assets to IPR completed on 21 March 2022. Working
interest production for Egypt in 2022 is therefore reported as 100%
through to completion and 45% thereafter. The comparative basis for
2021 also assumes 100% working interest until 21 March 2021 and
then 45% for the remainder of the year.
(2) Egyptian revenues are stated post government take including
corporate taxes
(3) Stated prior to realised hedging loss of $22.5m (2021: loss
of $29.7m)
(4) See Non-IFRS measures on page 38
(5) Includes RBL and National Bank of Egypt working capital
drawdown
(6) Operating cash flow = Net cash from operating activities, as
set out in the Cash Flow Statement
Enquiries
Pharos Energy plc
Tel: 020 7747 2000
Jann Brown, Chief Executive Officer
Sue Rivett, Chief Financial Officer
Camarco Tel: 020 3757 4980
Billy Clegg | Georgia Edmonds | Rebecca Waterworth | Kirsty
Duff
Notes to editors
Pharos Energy plc is an independent energy company with a focus
on sustainable growth and returns to stakeholders, which is listed
on the London Stock Exchange. Pharos has production, development
and/or exploration interests in Egypt and Vietnam. In Egypt, Pharos
holds a 45% working interest share in the El Fayum Concession in
the Western Desert, with IPR Lake Qarun, part of the international
integrated energy business IPR Energy Group, holding the remaining
55% working interest. The El Fayum Concession produces oil from 10
fields and is located 80 km southwest of Cairo. It is operated by
Petrosilah, a 50/50 joint stock company between the contractor
parties (being IPR Lake Qarun and Pharos) and the Egyptian General
Petroleum Corporation (EGPC). Pharos also holds a 45% working
interest share in the North Beni Suef (NBS) Concession in Egypt,
which is located immediately south of the El Fayum Concession. IPR
Lake Qarun operates and holds the remaining 55% working interest in
the NBS Concession. In Vietnam, Pharos has a 30.5% working interest
in Block 16-1 which contains 97% of the Te Giac Trang (TGT) field
and is operated by the Hoang Long Joint Operating Company. Pharos'
unitised interest in the TGT field is 29.7%. Pharos also has a 25%
working interest in the Ca Ngu Vang (CNV) field located in Block
9-2, which is operated by the Hoan Vu Joint Operating Company.
Blocks 16-1 and 9-2 are located in the shallow water Cuu Long
Basin, offshore southern Vietnam. Pharos also holds a 70% interest
in, and is designated operator of, Blocks 125 & 126, located in
the moderate to deep water Phu Khanh Basin, north east of the Cuu
Long Basin, offshore central Vietnam.
Chair's Statement
"A strong culture to deliver sustainable value"
2022 has been an extraordinary year for the energy sector
globally. An extended period of volatility has driven pivotal
changes for Pharos. The Company's response to the dynamic
environment during the year has included the reshaping of its
portfolio, balance sheet, Board, and its worldwide
organisation.
As a result of strong operational performance, completion of the
IPR transaction, securing the improved fiscal terms over El Fayum,
and with the support of continuing high oil prices resulting from
the easing of pandemic restrictions, Pharos now stands in a much
stronger financial position than where we were just a year ago.
This has allowed us to commence a share buyback programme, which
has continued into 2023, and to announce a new dividend policy
focused on making sustainable annual cash returns to shareholders.
The last twelve months saw us take key steps in our effort to
transform the Company, and I strongly believe that we are now well
positioned for a positive and sustainable future, with a robust
capital structure and exciting organic opportunities in a refocused
portfolio.
Board changes
Underpinned by the financial discipline in our corporate DNA,
Pharos has remained relentlessly focused on cost control, starting
from the Board and moving throughout the organisation. In 2022, as
Non-Executive Chair of the Board, I oversaw the reshaping of the
Board from nine to six Directors and salary reductions for myself
and both of the two Executives, a decision that is commensurate
with the scale of the business and the strategic challenges ahead
of us as the Company reframes its portfolio. Following the
completion of the farm-down of our assets in Egypt to IPR on 23
March 2022, Jann Brown assumed the role of Chief Executive Officer.
On the same date, Ed Story and Dr Mike Watts resigned as Directors
of Pharos, with Ed now serving as President of the Group's Vietnam
business. Senior Non-Executive Director and Deputy Chair, Rob Gray,
also stepped down in May 2022. On behalf of the Board, I would like
to thank Ed, Mike and Rob for their long and valued service to the
Company as Directors. Going forward, I believe we now have a
reshaped Board fit for purpose, which will provide the necessary
governance and oversight to support our strategic framework.
Diversity in all forms
Across our entire business, we acknowledge the benefits of
diversity in all its dimensions and welcome people with differing
backgrounds, skills, and experiences. Our commitment to inclusion
and diversity remained strong in 2022. As at year-end, I am pleased
to report that the Company has four female Directors, representing
two thirds of the Board. We are proud that we are able to recruit
talent from diverse backgrounds and ethnicities across our entire
organisation. Most notably, our UK-based staff comprises 16 people
from 9 different nationalities, of which women accounted for c.65%.
We operate in a global industry, and it is important to ensure that
we benefit from the diverse perspectives that people bring, and we
will continue to align our Company with that ethos.
People & Culture
I would like to express my gratitude to all our colleagues whose
hard work, professionalism and dedication has ensured Pharos'
resilience, delivery and efficiency during a challenging year. 2022
saw the departure of many of our longstanding talented Egyptian
colleagues following the transfer of operatorship of our Egyptian
assets to IPR, but I am delighted that so many of them have found
new positions so quickly. The team who have stayed with us have all
risen to the challenge, and I am impressed by their commitment to
maintain open communication and trust, welcoming constructive
changes while adapting to new working practices. They have
demonstrated that the culture of our workforce is strong and
resilient. It is built on the Group's guiding principles of
openness and integrity, safety and care, and mutual trust and
respect.
The in-person feedback sessions which I conducted during the
year with staff has informed the development of our hybrid working
programme in the UK. We no longer maintain a permanent office space
in London, with UK-based staff now having access to a modest
serviced office space in central London. This arrangement, in
addition to significantly reducing costs, provides greater
flexibility in how and where employees work. We have found this
approach has contributed positively to both our cost base and our
productivity, and we will maintain an active dialogue with our
workforce to adapt to changing situations as we go forward and
ensure that this remains the case. We have also introduced
initiatives to address staff isolation and promote team building by
hosting in-person meet-ups throughout the year.
Strategy Day & Stakeholder engagement
In October 2022, the Board held a Strategy Day to focus on where
and how we can offer value to our stakeholders. On the day, we had
presentations and inputs from a number of key parties, including
shareholders. Despite the volatility we have experienced in the
global macro-economic environment, our strategy to deliver
long-term sustainable value for all our stakeholders through
regular cash returns to shareholders and organic growth, remains
unchanged. The results of our Strategy Day reinforced our
commitment to pursue a combination of growth and cash returns per
share, and the resumption of the dividend in a clear policy
framework has been particularly appreciated. We are grateful to our
shareholders who have been crucial to our growth and transformation
throughout the years, and I thank you for your encouragement and
patience as we navigate through challenging times and move towards
a new phase of growth.
Sustainability
In a year when energy security has been at the top of the agenda
for governments worldwide, I firmly believe that oil and gas will
continue to play an essential role in the global energy mix for
many years to come, and that the importance of producing this
energy in a safe, environmentally sustainable and socially
responsible way will continue to grow. During my role as Senior
Vice President of the World Petroleum Council (WPC), I witnessed
the transformational impacts of the oil and gas industry,
particularly where it replaces coal, on countries that suffer from
energy poverty. I strongly believe that there are real
opportunities in the energy transition, especially for countries
such as Egypt and Vietnam, to benefit from the responsible and
sustainable development of their natural resources. Pharos stands
ready to play our part in this transition and will continue to
support our host governments as they seek to use oil revenues to
promote sustainable, inclusive economic development, manage the
impact of climate change and achieve their COP commitments.
Sustainability has always been a key value in Pharos' purpose
and business strategy. In 2022, we brought this even more to the
foreground. In September 2022, we made a formal commitment to
achieve a Net Zero target on Scope 1 (direct) and 2 (indirect) GHG
emissions from all our existing and future assets by no later than
2050, with a detailed Net Zero roadmap to come in late 2023. We
have also established an Emissions Management Fund to provide
support for emissions management projects in line with our climate
goals. We are committed to transparency in our reporting and will
keep stakeholders updated on our progress.
Outlook
2022 was a year of change for Pharos, and I am honoured to be
the Chair of the Company at such a pivotal stage in its history.
Thanks to the effort, ingenuity and hard work of all of our
colleagues, the Company is now well-positioned to deliver
sustainable value, with a stable balance sheet and a clear strategy
underpinned by a commitment to Net Zero by 2050 and to safe and
responsible operations. We enter 2023 with a more confident
outlook. On behalf of the Board, I would like to thank our
shareholders for their support through the year, as well as our
staff, partners, suppliers and advisers, all of whom have helped to
provide stability through this period of uncertainty and
volatility.
John Martin
Non-Executive Chair
Chief Executive Officer's Statement
"Delivering value to all stakeholders"
2022 was a year of significant change for Pharos. Amidst the
challenges and ongoing volatility facing the industry, we delivered
crucial milestones that have allowed us to rebuild resilience in
the balance sheet and helped us deliver on our strategy of offering
long term, sustainable value to our shareholders via both regular
cash returns and organic growth.
-- In January 2022, the Company received presidential approval
on the El Fayum Third Amendment which increased Contractor share of
revenues from c.42% to c.50%, thus improving fiscal terms in
Egypt.
-- In March 2022, we completed the farm-out transaction and
transfer of operatorship of our Egyptian assets to IPR. The
combination of IPR's long track-record in Egypt, the enhanced
fiscal terms, the Egyptian rig secured on a long-term contract,
plus the carry over our remaining 45% interest through 2022 and
into 2H 2023, all combined to support delivery of the full
potential of these assets, despite the current challenges in the
Egyptian economy.
-- In July 2022, we initiated a $3m share buyback programme to
return value to shareholders at a time where the share price was
trading at a material discount and to enhance NAV, earnings and
dividends per share to shareholders over time. The programme took
around six months to complete and, in January of this year, we
announced its continuation with a further $3m committed.
-- In September 2022, we announced a clear policy for the
recommencement of regular dividend payments, the first of which
will be put to the AGM in May 2023 and, subject to shareholder
approval, paid in July 2023.
-- Also in September 2022, we set out a formal commitment to
achieve a Net Zero target on Scope 1 (direct) and 2 (indirect) GHG
emissions from all our existing and future assets by no later than
2050, which we recognise is a key component for stakeholders.
These key steps, combined with the operational performance set
out below, have reset the dial for Pharos. The Group now has a
refreshed portfolio, a reduced cost base, and a more resilient
balance sheet to allow us to invest in the organic growth
opportunities in the portfolio. These opportunities range from
near-term developments and exploration potential in Egypt to
world-class potential basin-opening exploration in Vietnam.
Strong operational performance in 2022 ...
In Vietnam, the Group continued to deliver high netback, stable
production. Production in 2022 from the TGT and CNV fields net to
the Group's working interest averaged 5,418 boepd, in line with
guidance. To sustain production levels, the JOCs carried out a
drilling programme comprising two development wells at TGT and one
at CNV, which was completed on time and under budget. In 2022, the
crude produced from the fields in Vietnam commanded a premium to
Brent of just over $4/bbl, achieved a netback of c.$50 per barrel
and a forecast payback period for the wells drilled of less than 12
months, making investment in these fields an attractive
proposition.
In Egypt, we completed the farm-out to IPR in March 2022, and
production from the El Fayum Concession averaged 3,128 bopd gross,
1,748 bopd net to the Group, in line with guidance announced in May
2022. A multi-well development drilling programme on El Fayum was
undertaken, with a total of seven wells drilled and put on
production in 2022. Most notably, in July 2022, the JOC
(Petrosilah) secured a rig on a long-term contract, one year firm
plus an option for a second year, from December 2022. This rig is
expected to provide a stable platform for a continuous drilling
campaign which is essential to adding new barrels to production,
subject to improving macroeconomic position in Egypt.
The health and safety of our workforce remains our number one
priority and we are committed to operating safely and responsibly
at all times. We continue to have an excellent safety record in
Vietnam, and I am pleased to report that the Company reported zero
LTIs and zero fatal incidents in Vietnam for the past 26 years.
This is thanks to the JOCs' consistent efforts to provide and
champion workers' health, safety and well-being, and we are careful
to maintain this achievement as we have done since 1996. In Egypt,
we regret to report one LTI and one environmental spill in 2022,
details of which are set out in our Corporate Responsibility report
in our Annual Report. We are working with our partner IPR and JOC
Petrosilah to investigate and address the underlying issues behind
the safety measurements and precautions in operations in order to
return to our track record of zero safety and environmental
incidents across all assets.
Our operational performance in 2022 has laid a strong foundation
for our 2023 work programme to move forward with the growth
potential of our assets, supporting delivery of our strategy.
... Helping us deliver our strategy
As we navigate the many challenges throughout the year, the
Board and senior management team maintain a clear focus on our
capital allocation goals: to balance regular returns to
shareholders with investment in our assets to generate sustainable
value and cash flow, while preserving the resilience of the balance
sheet. As the Company reshapes its portfolio and financial
position, our strategy of creating and returning value to
shareholders through a combination of annual dividends and organic
growth, underpinned by robust cash flow and strengthened balance
sheet, stays consistent through changing times. We are committed to
delivering value and invest where see near term cash flow and
longer term value per share. We keep each asset in our portfolio
under review to ensure that they are delivering the expected value
and we have a track record of monetising at the right point in the
cycle.
1. Shareholder Returns
We have established a sustainable shareholder return framework
via share buybacks and dividends. Our initial $3m share buyback
programme announced in July 2022 has completed and we have
announced a further commitment of $3 million to continue the
programme in 2023. Additionally, in September 2022, we announced
our intention to recommence dividend payments starting in 2023. Our
policy is set at returning not less than 10% of Operating Cash Flow
(OCF) and accordingly takes account of volatility in the market,
such as movements in Brent price, tax, and working capital
movements. Based on the 2022 results, where OCF of $53.4m
(GBP43.2m) was achieved, the first dividend under this policy will
amount to 1p per share, and will be put to shareholders at the AGM
in May 2023. Payment of the 2022 dividend is scheduled for July
2023, and the Board expects to pay an interim dividend based on
forecast results for 2023 in early January 2024.
2. Organic growth opportunities
We have a portfolio of organic growth opportunities in both
Vietnam and Egypt, with options continuously being explored and
development work progressed to maximise the potential of these
complementary assets. In Vietnam, 3D seismic processing is complete
on Block 125, a basin-opening frontier play with world-class
potential, and a variety of interesting Prospects have been
identified. We are in discussions with a number of parties
interested in farming in to support the funding of a commitment
well on this Block. Lastly, we are progressing work to submit
licence extension requests across our asset base to extend the
periods over which we can continue our work. In Egypt, we have
infrastructure-led exploration (ILX) opportunities in both the
North Beni Suef (NBS) and El Fayum Concessions, which are being
developed with our partner IPR in the 2023 work programme.
3. Cash flow protections
We have run cash flow projections over a number of different
scenarios and have a balance of hedged and free-floating Group
production, with 71% or forecast production unhedged at 31 December
2022, thus providing exposure to the oil price. We also operate in
two very different jurisdictions, which provides diversification
and resilience in a volatile world. Additionally, to mitigate the
impact of the current late payment issues in Egypt, we have a
working capital facility with the National Bank of Egypt (NBE) to
smooth out payment cycles there. Under this arrangement, Pharos is
able to access USD cash from the facility of up to 60% of sales
invoices outstanding, with a cap of $18m.
4. Capital allocation
We have a culture of prudent financial management, capital
allocation and capital return. We exhibit capital discipline
through a focus on cost management and control, a part of our DNA.
Capital allocation decisions are taken to make investments where
they will generate risk-adjusted full-cycle returns and it is this
approach that has allowed us to return significant amounts of
capital to shareholders in the past. We retain a flexible approach
to our portfolio and look to time acquisitions and divestments to
optimise cash flow and value per share.
Stakeholder engagement
The operational successes the Company had during the year, as
well as the strategic building blocks towards reshaping the
business, would not have been possible if not for the supportive
relationships we have with our stakeholders.
After an extended period of travel restrictions due to the
pandemic, in 2022, I was able to travel to Egypt and Vietnam to
meet with many of our colleagues and key stakeholders in-person. I
am personally very grateful to have been able to reconnect and
refresh relationships with our partners after a long period of
remote working, and have been greatly encouraged by the supportive
and open engagement with our colleagues, JV/JOC partners,
regulators, and governments. I met the Chair of EGPC, the industry
regulator and state oil company in Egypt, in H2 2022, whose support
was a crucial step towards the approval for the improvement in our
fiscal terms. In Vietnam, I had the opportunity to meet with both
our partners and the regulator to discuss the Revised Field
Development Plans and licence extensions for TGT and CNV, and the
exploration potential and licence extension for Block 125/126.
Closer to home, we also hosted an extensive delegation from Vietnam
to contribute our thoughts and experiences as they prepared to take
a new petroleum law through the National Assembly, which has now
been approved and will take effect from 1 July 2023, helping to
expedite some of the approval processes in country. Finally, in
December 2022, John Martin and I were honoured to be granted a
private audience with the Prime Minster of Vietnam to discuss the
proposed licence extensions on our assets in country, highlighting
the important benefits that these bring not just to Pharos but also
to Vietnam. Most recently, in January 2023, the Company held a
lunch to engage with analysts, both those covering and not covering
the Company, to foster open and communicative relationships with
key figures in the industry. We will continue to engage in a
personal and meaningful way with our various stakeholders in 2023
and beyond.
Sustainability & Net Zero
Sustainability is a key value in our purpose and business
strategy. We are committed to providing energy to support the
development and prosperity of the countries, communities and
families wherever we work, in line with recognised social and
environmental practices. The use of oil and gas in developing
economies, particularly where it replaces coal, can provide the
energy needed to drive GDP growth as a foundation for long-term
economic and social benefits, as long as those resources are
developed efficiently, safely and responsibly. In this way, we can
create sustainable value for all of our stakeholders: investors,
host countries, business and communities.
This year, we have taken an important step with regard to our
environmental responsibilities to society and the countries in
which we operate. In September 2022, we announced a commitment to
achieve Net Zero on our Scope 1 (direct) and Scope 2 (indirect) GHG
emissions from all our current and future assets by no later than
2050. We look to achieve this by progressing operational
efficiencies, reducing flaring and venting where possible,
replacing the power consumption of our facilities with less
impactful energy sources and eventually procuring nature-based
carbon offset projects for hard-to-abate, residual emissions. As we
develop our emissions reduction plans, we will look to accelerate
this 2050 target whenever we can. We have also established an
Emissions Management Fund in 2022 to provide support for emissions
management projects in line with our climate goals. Additionally,
we also pledge to publish a detailed Net Zero roadmap in late 2023,
to include a baseline emissions inventory for all our assets,
asset-level emission reduction frameworks, and introducing interim
targets over the short and medium term as well as the capital
expenditure and resourcing needed to achieve targets.
We recognise that the journey to Net Zero will be neither simple
nor straightforward. Nevertheless, we remain committed to
transparency in our reporting and to keeping stakeholders updated
on our progress. For more details on our Net Zero commitment,
Emissions Management Fund, our emission impact and how we deliver
value to the local community, please refer to our Corporate
Responsibility Report in our Annual Report.
Outlook
The key steps we have taken to reshape our business have taken
Pharos to a stronger place. After a year of delivery, we now have a
combination of assets which offer resilience in difficult times,
strong cash returns even at low oil prices, plus valuable organic
growth potential when investment capital is available. Having taken
over the reins at Pharos a year ago, I am confident that we have
the assets, plan, team, capital structure and financial discipline
to deliver long-term sustainable return to all stakeholders. I
would like to thank our global colleagues, investors, government
and JV/JOC partners for their continued support through these
changes as we navigated through a year of challenges and
uncertainties, and I look forward to working with all of them to
steer Pharos on a path towards a new phase of growth.
Jann Brown
Chief Executive Officer
Review of Operations
Vietnam
Vietnam Production in 2022
Production in 2022 from the TGT and CNV fields net to the
Group's working interest averaged 5,418 boepd (2021: 5,560 boepd).
This is in line with the production guidance for Vietnam announced
in January 2022.
TGT production averaged 13,784 boepd gross and 4,089 boepd net
to the Group (2021: 13,887 boepd gross and 4,120 boepd net). CNV
production averaged 5,317 boepd gross and 1,329 boepd net to the
Group (2021: 5,762 boepd gross and 1,440 boepd net).
Vietnam Development and Operations in 2022
TGT & CNV Fields
On Block 16-1 - TGT Field, the drilling programme for two
development wells completed in H2 2022, on time and under budget.
The first well, H1-35P, commenced production on 21 October 2022,
and the second well, 11XPST, commenced production on 10 November
2022.
Additionally, the JOC continues to execute an active well
intervention and data-gathering programme on TGT to further
optimise production.
On Block 9-2 - CNV Field, one development well, CNV-2PST1,
started drilling in H2 2022 and completed in Q1 2023 on time and
under budget.
Vietnam Exploration in 2022
Blocks 125 & 126
On Block 125, the 3D seismic processing was completed in
November 2022 and the ongoing interpretation of this data has
resulted in the mapping of a variety of world class Prospects in
this relatively unexplored basin.
The analysis of the 2D seismic shot in 2019 indicated
prospectivity in both the shallow and deeper water, and the ongoing
interpretation of the 3D seismic has highlighted greater
prospectivity in the deeper water section given the scale of the
Prospects identified there.
2023 Work Programme
TGT & CNV Fields
Vietnam production guidance for 2023 is 4,700 to 5,700 boepd
net.
For the 2023 work programme, the JOCs are working towards
submitting Revised Field Development Plans (RFDPs) for two wells on
TGT and one on CNV, with all wells remaining in contingent budget
until approval by partners and the Ministry of Industry and Trade
(MOIT). Production guidance has assumed no contribution from these
wells in 2023.
The official licence extension requests have been sent to
partners for approval, prior to submission to PVN for their
approval before being put to the Prime Minister for final
assent.
Blocks 125 & 126
As noted above, the ongoing interpretation of 3D seismic data
has highlighted greater prospectivity in the deeper water section
of Block 125. In order to drill one of these deeper water prospects
as the commitment exploration well under the current exploration
phase of the PSC, a Drillship or Dynamically-Positioned (DP)
Semi-Submersible Rig is needed. Due to limited regional
availability the Group has been unable to source a suitable
drilling unit for 2023 on acceptable terms. We therefore submitted
an application in December 2022 for an extension of the current
exploration phase of the PSC which is now with the Prime Minister's
office for approval.
We will use the time to optimise drilling locations and well
planning for this deeper water well, to source a Drillship or DP
Semi-Submersible Rig and other long-lead procurement items and to
find a partner to support the funding of this well. A number of
parties have been invited to review data and discussions are
ongoing.
In addition, we are now engaged in updating our 3D Hydrocarbon
Modelling of the area and in fully analysing the 3D seismic data
for amplitude anomalies - spectral decomposition for reservoir
facies distribution patterns and AVA/AVO analysis for the presence
of hydrocarbons. We have also started a detailed Peer Review study
of all our technical work with a leading Energy Subsurface
consultancy (ERCE), who will also perform an Independent Resource
assessment of our key Prospects.
Egypt
Egypt Production in 2022
The transaction with IPR and transfer of operatorship completed
on 21 March 2022. Although the economic date of the transaction was
1 July 2020, operatorship remained with Pharos until March 2022.
Accordingly, working interest production in 2022 is reported in the
Financial Statements as 100% through to completion of the farm-down
and 45% thereafter.
Production for 2022 from the El Fayum Concession averaged 3,128
bopd gross and 1,748 bopd net to the Group. This is in line with
the 2022 production guidance announced in January 2022.
Egypt Development and Operations in 2022
Following the transaction with IPR in March 2022, the main El
Fayum multi-year and multi-well development programme commenced in
Q2 2022. Seven wells were put on production in 2022 (including one
well drilled in 2021), and one additional well was drilled in Q4
2022 and completed in Q1 2023.
In July 2022, the El Fayum JOC, Petrosilah, secured a rig on a
long-term contract, one year firm plus an option for a second year,
which started drilling in December 2022. This rig is expected to
provide a stable platform for a continuous drilling campaign, which
we consider essential to adding new barrels to production.
Additionally, two workover rigs are on field to contribute to
production through low-cost well repairs, recompletions, and
deployment of water injection.
Egypt Commercial
In January 2022, the Company received approval on the Third
Amendment to the El Fayum Concession. The agreement, and the
improved fiscal terms, were retroactively effective from November
2020.
As a result of the changes introduced by the Third Amendment,
the Contractor parties' share of revenue while in full cost
recovery mode increases from c.42% to c.50% as from November 2020
(corresponding to additional net revenues to the Contractor of c.$7
million to the date of signature) significantly lowering the
development project break-even. The Third Amendment also grants
Contractor a three-and-a-half-year extension to the exploration
term of the El Fayum Concession, with an additional obligation on
Contractor to drill two exploration wells and acquire a 3D seismic
survey in the northern area of the concession.
The Group is cognisant of the current macroeconomic situation in
Egypt, and will continue to review its investment programme in
light of recovery of the receivable position.
Egypt Exploration in 2022
North Beni Suef (NBS) exploration
In Q4 2022, the Company was granted a short extension on North
Beni Suef (NBS) to allow additional time to drill high-ranked
prospects and all work programme commitments, including the first
of two commitment exploration wells, originally planned for Q4
2022. Several prospects have been identified from the existing 3D
seismic.
2023 Work Programme
El Fayum
Egypt production guidance for 2023 is 1,350 - 1,800 bopd net
(equivalent to gross production of 3,000 - 4,000 bopd).
In El Fayum, multi-well development drilling continues in 2023,
with nine wells planned for the year.
On the exploration side, two commitment exploration wells are
expected to be drilled in the El Fayum Concession as part of the
planned 2023 work programme. These two Satellite exploration wells
are planned to target two separate structures near existing
producing fields with primary reservoir targets in the Abu Roash G
and Upper Bahariya formations. We are working closely with IPR to
progress well planning and optimise drilling schedules.
The drilling of the first NBS exploration commitment well,
originally planned for Q4 2022, has started in Q1 2023. In March
2023, a further extension to the exploration period was granted by
EGPC. These two extensions, which run until September 2023, provide
additional time to fulfil the Contractor parties' commitment to
drill this commitment well. The second commitment exploration well
on NBS is planned to be drilled later in 2023, dependent on rig
availability. Several prospects have been identified from the
existing 3D seismic and acquisition of c.110 km2 of additional 3D
seismic has started in Q1 2023.
Group Reserves and Contingent Resources
The Group Reserves Statistics table below summarises our
reserves and contingent resources based on the Group's unitised net
working interest in each field. Gross reserves and contingent
resources have been independently audited by RISC Advisory Pty Ltd
(RISC) for Vietnam and McDaniel & Associates Consultants Ltd.
(McDaniel) for Egypt.
Group Reserves Statistics
Net Working Interest (mmboe) TGT CNV Vietnam(3) Egypt(4) Group
Oil & Gas 2P Commercial Reserves (1,2)
As of 1 January, 2022 10.9 4.3 15.2 37.8 53.0
------ ------ ----------- --------- -------
Production (1.5) (0.5) (2.0) (0.6) (2.6)
------ ------ ----------- --------- -------
Revision (0.6) (0.4) (1.0) (1.5) (2.5)
------ ------ ----------- --------- -------
Change in net working interest
(5) - - - (20.7) (20.7)
------ ------ ----------- --------- -------
2P Commercial Reserves as
of 31 December 2022 8.8 3.4 12.2 15.0 27.2
------ ------ ----------- --------- -------
Oil & Gas 2C Contingent Resource (1,2)
As of 1 January, 2022 7.6 3.8 11.4 18.6 30.0
------ ------ ----------- --------- -------
Revision (0.2) (0.4) (0.6) 0.5 (0.1)
------ ------ ----------- --------- -------
Change in net working interest
(5) - - - (10.2) (10.2)
------ ------ ----------- --------- -------
2C Contingent Resources as
of 31 December 2022 7.4 3.4 10.8 8.9 19.7
------ ------ ----------- --------- -------
Total Group 2P Reserves &
2C Contingent Resources (3,4)
As of 31 December 2022 16.2 6.8 23.0 23.9 46.9
------ ------ ----------- --------- -------
(1) Reserves and contingent resources are categorised in line
with 2018 SPE standards.
(2) Assumes an oil equivalent conversion factor of 6,000
standard cubic feet per barrel of oil equivalent.
(3) Reserves and Contingent Resources have been independently
audited by RISC.
(4) Reserves and Contingent Resources have been independently
audited by McDaniel.
(5) Pharos Energy net working interest in El Fayum is 45% post
completion of farm down transaction to IPR energy on 21 March
2022
Vietnam Reserves and Contingent Resources
In accordance with the requirements of its Reserve Base Lending
Facility, the company commissioned RISC to provide an independent
audit of gross (100% field) reserves and contingent resources for
TGT and CNV as of 31 December 2022 .
Vietnam Reserves Statistics
Net Working Interest (mmboe) TGT CNV Total
Vietnam
Oil & Gas 2P Commercial Reserves (1,2)
As of 1 January, 2022 10.9 4.3 15.2
------ ------ ---------
Production (1.5) (0.5) (2.0)
------ ------ ---------
Revision (0.6) (0.4) (1.0)
------ ------ ---------
2P Commercial Reserves as of
31 December 2022 8.8 3.4 12.2
------ ------ ---------
Oil & Gas 2C Contingent Resource (1,2)
As of 1 January, 2022 7.6 3.8 11.4
------ ------ ---------
Revision (0.2) (0.4) (0.6)
------ ------ ---------
2C Contingent Resources as
of 31 December 2022 7.4 3.4 10.8
------ ------ ---------
Total Vietnam 2P Reserves &
2C Contingent Resources (3)
As of 31 December 2022 16.2 6.8 23.0
------ ------ ---------
(1) Reserves and contingent resources are categorised in line
with 2018 SPE standards.
(2) Assumes an oil equivalent conversion factor of 6,000
standard cubic feet per barrel of oil equivalent.
(3) Reserves and contingent resources have been independently
audited by RISC.
On TGT, 2P reserves were revised downwards due to lower than
expected performance from one of the new infill wells and a slow
production ramp-up following the annual maintenance shutdown. 2C
contingent resources were revised as volumes from two future infill
wells were moved into the reserves category.
On CNV, the 2P reserves and 2C contingent resources were revised
downwards due to lower performance from the existing wells and
delayed dewatering of well 5PST2.
Egypt Reserves and Contingent Resources
Egypt Reserves Statistics
Net Working Interest (mmboe) Egypt
Oil 2P Commercial Reserves (1)
As of 1 January, 2022 37.8
-------
Production (0.6)
-------
Revision (1.5)
-------
Change in net working interest
(3) (20.7)
-------
2P Commercial Reserves as
of 31 December 2022 15.0
-------
Oil 2C Contingent Resource (1)
As of 1 January, 2022 18.6
-------
Revision 0.5
-------
Change in net working interest
(3) (10.2)
-------
2C Contingent Resources as
of 31 December 2022 8.9
-------
Total Egypt 2P Reserves &
2C Contingent Resources (2)
As of 31 December 2022 23.9
-------
(1) Reserves and contingent resources are categorised in line
with 2018 SPE standards.
(2) Reserves and Contingent Resources have been independently
audited by McDaniel.
(3) Pharos Energy net working interest in El Fayum is 45% post
completion of farm down transaction to IPR energy on 21 March
2022
On El Fayum, the delay in the execution of the field development
plan has resulted in a downward revision of the 2P reserves,
pushing some volumes into the contingent resources category.
Group's Net Working Interest Reserves and Contingent Resources
El Fayum Fields at 31 December 2022 (mmboe)
--------------------------------------------------------------------------
Reserves 1P 2P 3P
----------------------------------------------- ------- ------- -------
Oil 7.3 15.0 20.0
----------------------------------------------- ------- ------- -------
Contingent Resources 1C 2C 3C
----------------------------------------------- ------- ------- -------
Oil 3.3 8.9 18.0
----------------------------------------------- ------- ------- -------
Sum of Reserves and Contingent Resources (1,2) 1P & 1C 2P & 2C 3P & 3C
----------------------------------------------- ------- ------- -------
Total 10.6 23.9 38.0
----------------------------------------------- ------- ------- -------
(1) Reserves and Contingent Resources have been audited
independently by McDaniel.
(2) The summation of Reserves and Contingent Resources has been
prepared by the Company.
TGT Field at 31 December 2022 (mmboe) (net to Group's working interest)
--------------------------------------------------------------------------------
Reserves(3) 1P 2P 3P
--------------------------------------------------- -------- -------- -------
Oil 6.7 8.1 9.2
--------------------------------------------------- -------- -------- -------
Gas(1) 0.4 0.7 0.9
--------------------------------------------------- -------- -------- -------
Total 7.1 8.8 10.1
--------------------------------------------------- -------- -------- -------
Contingent Resources(3) 1C 2C 3C
--------------------------------------------------- -------- -------- -------
Oil 4.7 7.1 9.0
--------------------------------------------------- -------- -------- -------
Gas(1) 0.1 0.3 0.5
--------------------------------------------------- -------- -------- -------
Total 4.8 7.4 9.5
--------------------------------------------------- -------- -------- -------
Sum of Reserves and Contingent Resources(2) 1P & 1C 2P & 2C 3P & 3C
--------------------------------------------------- -------- -------- -------
Oil 11.4 15.2 18.2
--------------------------------------------------- -------- -------- -------
Gas(1) 0.5 1.0 1.4
--------------------------------------------------- -------- -------- -------
Total 11.9 16.2 19.6
--------------------------------------------------- -------- -------- -------
(1) Assumes oil equivalent conversion factor of 6,000 standard
cubic feet per barrel of oil equivalent.
(2) The summation of Reserves and Contingent Resources has been
prepared by the Company.
(3) Reserves and Contingent Resources have been audited
independently by RISC.
CNV Field at 31 December 2022 (mmboe) (net to Group's working interest)
--------------------------------------------------------------------------------
Reserves(3) 1P 2P 3P
--------------------------------------------------- -------- -------- -------
Oil 1.8 2.1 2.5
--------------------------------------------------- -------- -------- -------
Gas(1) 1.1 1.3 1.5
--------------------------------------------------- -------- -------- -------
Total 2.9 3.4 4.0
--------------------------------------------------- -------- -------- -------
Contingent Resources(3) 1C 2C 3C
--------------------------------------------------- -------- -------- -------
Oil 1.3 2.1 3.0
--------------------------------------------------- -------- -------- -------
Gas(1) 0.8 1.3 1.8
--------------------------------------------------- -------- -------- -------
Total 2.1 3.4 4.8
--------------------------------------------------- -------- -------- -------
Sum of Reserves and Contingent Resources(2) 1P & 1C 2P & 2C 3P & 3C
--------------------------------------------------- -------- -------- -------
Oil 3.1 4.2 5.5
--------------------------------------------------- -------- -------- -------
Gas(1) 1.9 2.6 3.3
--------------------------------------------------- -------- -------- -------
Total 5.0 6.8 8.8
--------------------------------------------------- -------- -------- -------
(1) Assumes oil equivalent conversion factor of 6,000 standard
cubic feet per barrel of oil equivalent.
(2) The summation of Reserves and Contingent Resources has been
prepared by the Company.
(3) Reserves and Contingent Resources have been audited
independently by RISC.
Chief Financial Officer's Statement
I am pleased to report the strengthening of our balance sheet
and a considerable improvement in the liquidity of the business.
The steps we took in previous periods to streamline our business
are showing results, with improved fiscal terms in Egypt and
reduced costs throughout the Group. Our finance strategy continues
to underpin our business model and our commitment to building
shareholder value through organic growth and sustainable returns to
shareholders. We have continued with our infield development
programme in Vietnam, allowing us to sustain production levels in
these highly attractive fast payback wells. The successful
completion of the farm down in Egypt in March brought in a small
initial cash payment on completion, but more significantly allowed
us to benefit from a full carry of all contractor costs for
G&A, opex and the capital programme into 2023. This activity
has all been supported by improved oil prices and has allowed us to
deliver strong positive cash flow and growth in value. As a direct
result, we were able to announce returns to shareholders with the
$3m share buyback programme in July and also announce our proposal
to recommence regular dividend payments, the first based on 2022
Operating Cash Flow.*
(*Subject to shareholder approval at 2023 AGM)
Operating performance
Revenues
Group revenues were up 35% at $221.6m prior to realised hedging
loss of $22.5m (2021: $163.8m prior to realised hedging loss of
$29.7m).
Revenues for Vietnam of $184.8m (2021: $131.0m) increased
significantly year on year. The average realised crude oil price
was $106.44/bbl (2021: $72.61/bbl), a 47% increase year on year,
and the premium to Brent was over $4/bbl on average (2021: just
under $2/bbl). Production was largely flat at 5,418 boepd (2021:
5,560 boepd).
The revenue for Egypt of $36.8m (2021: $32.8m) increased largely
due to an additional $7m following the improvement in the fiscal
terms with the Third Amendment to the El Fayum Concession,
increasing cost recovery oil from 30% to 40% from November 2020.
This was combined with higher average realised crude oil price, up
47% to $96.03/bbl (2021: $65.12/bbl), though offset by reduced
production of 1,748 bopd from 3,318 bopd, following the farm-down
of 55% interest and transfer of operatorship of the Group's
Egyptian assets to IPR completed on 21 March 2022 . There are two
discounts applied to the El Fayum crude production - a general
Western Desert discount and one related specifically to El Fayum.
Both are set by EGPC and combined stayed consistent at over $5/bbl
for the year.
Hedging
A number of hedges were put in place in 2021 for the 2022 year
to support our stress testing for going concern and the working
capital test required for the prospectus for the Egyptian farm
down. We were hedged more than required under our RBL and higher
than we would normally commit to in order to support this. For full
year 2022, Pharos entered into different commodity (swap and zero
collar) hedges to protect the Brent component of forecast oil sales
and to ensure future compliance with its obligations under the
reserve based lending facility (RBL) over the producing assets in
Vietnam. The commodity hedges run until December 2023 and are
settled monthly. The majority of hedged production volumes (61%)
were in H1 2022, leading to realised losses of $17.3m out of total
realised losses of $22.5m for the year, in order to meet
requirements under the RBL and also going concern and working
capital tests in relation to the Egypt farm out deal.
For 2022, 30% of the Group's total production was hedged,
securing an average realised price for the hedged volumes of
$73.1/bbl. The Group's RBL requires the Company to hedge at least
35% of Vietnam RBL production volumes and the current hedging
programme meets this requirement through to December 2023, leaving
71% of Group production unhedged as at 31 December 2022.
Please see below a summary of hedges outstanding as at 31
December 2022, which are all zero cost collar.
1Q23 2Q23 3Q23 4Q23
============================ ======= ======= ======= =======
Production hedge per
quarter - 000/bbls 180 180 180 45
================================ ======= ======= ======= =======
Min. Average value
of hedge - $/bbl 65.33 65.33 63.33 63.33
================================ ======= ======= ======= =======
Max. Average value
of hedge - $/bbl 102.88 102.88 102.23 107.80
================================ ======= ======= ======= =======
Operating costs
Group cash operating costs, defined in the Non-IFRS measures
section on page 38, were $42.8m (2021: $52.0m). Vietnam increased
marginally by 2% from $31.0m to $31.7m in 2022, which equates to
$16.03/bbl (2021: $15.28/bbl). The increase is due to higher costs
relating to the FPSO as a result of lower Thang Long Joint
Operating Company (TLJOC) production (TLJOC has 14.5% cost share in
2022 compared to 22.7% in 2021) throughout, which increased the
HLJOC's share of the costs.
Cash operating costs in Egypt were $11.1m in 2022 (2021:
$21.0m), which equates to $17.40/bbl (2021: $17.34/bbl). Cash
operating costs from 1 January 2022 up to 20 March 2022 are 100%
share and from 21 March 2022 includes the Group's remaining 45%
share. The increase in cash operating costs relates largely to
higher variable costs as a result of an upsurge in the fuel price,
offset by the significant devaluation of EGP against the US dollar
during the year.
DD&A
Group DD&A associated with producing assets increased to
$55.1m (2021: $51.0m) driven by a higher depreciating cost base
following 2021 and June 2022 impairment reversals taken on both
Vietnam and Egypt, partially offset by the decrease in group
production year on year. DD&A per bbl is currently $25.79/boe
for Vietnam (2021: $21.19/boe). DD&A per bbl for Egypt is
$6.43/boe for the full year production entitlement, as the Company
had 100% share of Egypt production for the period through to
completion of the farm-down, 1 January 2022 to 20 March 2022, and
then 45% share for the remainder of the year. At 31 December 2021,
55% of El Fayum property, plant and equipment (PP&E) was
re-categorised to assets classified as held for sale. The remaining
45% PP&E cost base was depreciated over 45% share of production
for the period through to completion of the farm-down, giving a
comparable DD&A per bbl of $7.98/boe (2021: $6.61/boe), which
reflects the impairment reversals previously noted.
Administrative Expenses
Administrative expenses in 2022 of $10.0m (2021: $13.2m) are
substantially lower than prior year due to our restructuring
efforts. After adjusting for the non-cash items under IFRS 2 Share
Based Payments of $1.3m (2021: $2.2m), the administrative expense
is $8.7m (2021: $11.0m). Following completion of the farm down to
IPR in March 2022 and the AGM in May 2022, the Board was reduced
from 9 to 6 Directors. The remaining non-executives' fees were
restated to the levels prior to the reductions taken during 2020
and 2021. As previously noted in the 2021 Annual Report &
Accounts, the incoming CEO took a 21% reduction in base salary on
assuming the role. The Egypt office was also restructured following
the farm down.
Operating Profit
Operating profit from continuing operations for the year was
$72.3m (2021 : $6.3m) excluding the net impairment reversal of
$27.9m (2021: $42.0m net impairment reversal), reflecting the
higher commodity price environment throughout the year, offset by
19% reduction in production volumes.
Other/Restructuring Expenses and Loss on Disposal
Other/restructuring expenses for the year totalled $0.8m (2021:
$3.3m) and included restructuring costs for both the head office in
London and the Egypt office in Cairo ($0.1m). In addition, there
was $0.7m charge relating to the premium on the transfer of the
lease on the London office.
Loss on disposal for the year totalled $6.3m (2021: $nil) and
related to the farm-down transaction, where 55% of the Group's
operated interest in each of our Egyptian Concessions, El Fayum and
North Beni Suef, were acquired by IPR on 21 March 2022. Pharos is
entitled to contingent consideration depending on the average Brent
Price each year from 2022 to the end of 2025 (with floor and cap at
$62/bbl and c.$90/bbl respectively). The contingent consideration
is calculated yearly and is capped at a maximum total payment of
$20.0m (please refer to Note 14 for further details). The first
payment of the contingent consideration, being $5 million in
respect of the Brent price during 2022, is due from IPR in June
2023.
Finance Costs
Finance costs increased to $12.7m (2021: $6.4m), mainly relating
to a one-off charge of $2.6m following a change in estimated future
cash flows following the December 2022 RBL redetermination and
amortisation of capitalised borrowing costs of $1.5m (2021: $2.4m
gain due to changes in future cash flows), interest expense payable
and similar fees of $6.1m primarily due to higher interest rates
charged on the RBL and NBE (2021: $3.8m), unwinding of discount on
provisions of $1.3m (2021: $0.8m) and foreign exchange losses of
$1.2m primarily driven by the devaluation of EGP against USD (2021:
foreign exchange gains of $0.6m).
Cash operating cost per
barrel* 2022 2021
$m $m
----------------------------- ------ ------
Cost of sales 116.8 114.6
----------------------------- ------ ------
Less
----------------------------- ------ ------
Depreciation, depletion
and amortisation (55.1) (51.0)
----------------------------- ------ ------
Production based taxes (14.7) (10.1)
----------------------------- ------ ------
Export duty (3.2) -
----------------------------- ------ ------
Inventories 1.8 0.1
----------------------------- ------ ------
Trade Receivable risk factor
provision (1.5) -
----------------------------- ------ ------
Other cost of sales (1.3) (1.6)
----------------------------- ------ ------
Cash operating costs 42.8 52.0
----------------------------- ------ ------
Production (BOEPD) 7,166 8,878
----------------------------- ------ ------
Cash operating cost per
BOE ($) 16.36 16.05
----------------------------- ------ ------
DD&A per barrel* 2022 2021
$m $m
------------------------ ------ ------
Depreciation, depletion
and amortisation (55.1) (51.0)
------------------------ ------ ------
Production (BOEPD) 7,166 8,878
------------------------ ------ ------
DD&A per BOE ($) 21.07 15.74
------------------------ ------ ------
* Cash operating cost per barrel and DD&A per barrel are
alternative performance measures. See page 38.
Cash operating cost Vietnam Egypt Egypt Egypt Total
per barrel by Segment
Up to From Total
20/03/22 21/03/22
(1) to 31/12/22
(1)
$m
$m $m $m $m
------------------------ -------- ---------- ------------- ------- ------
Cost of sales 99.6 4.9 12.3 17.2 116.8
------------------------ -------- ---------- ------------- ------- ------
Less
------------------------ -------- ---------- ------------- ------- ------
Depreciation, depletion
and amortisation (51.0) (0.6) (3.5) (4.1) (55.1)
------------------------ -------- ---------- ------------- ------- ------
Production based taxes (14.5) - (0.2) (0.2) (14.7)
------------------------ -------- ---------- ------------- ------- ------
Export duty (3.2) - - - (3.2)
------------------------ -------- ---------- ------------- ------- ------
Inventories 1.6 - 0.2 0.2 1.8
------------------------ -------- ---------- ------------- ------- ------
Trade Receivable risk
factor provision - (0.5) (1.0) (1.5) (1.5)
------------------------ -------- ---------- ------------- ------- ------
Other cost of sales (0.8) (0.2) (0.3) (0.5) (1.3)
------------------------ -------- ---------- ------------- ------- ------
Cash operating costs 31.7 3.6 7.5 11.1 42.8
------------------------ -------- ---------- ------------- ------- ------
Production (BOEPD) 5,418 2,857 1,441 1,748 7,166
------------------------ -------- ---------- ------------- ------- ------
Cash operating cost
per BOE ($) 16.03 15.94 18.21 17.40 16.36
------------------------ -------- ---------- ------------- ------- ------
(1) movements from 1 January 2022 up to 20/03/22 are 100% share
and from 21/03/22 includes the Group's remaining 45% share. 100%
cash operating costs for period from 21/03/22 to 31/12/22 amounts
to $16.7m.
Cash flows and accounting for Egypt
Following the completion of the farm-out transaction of Egyptian
assets to IPR, the accounting for the assets reflect the
following:
The effective date of the transaction was 1 July 2020, with
completion on 21 March 2022.
The Group, through its subsidiary PEF, owned and managed the
business up to completion. On completion an adjustment to
compensate IPR for 55% of net cash flows, revenue offset by costs
since the effective date has been adjusted for in the level of
carry to be provided by IPR to Pharos.
In the Financial Statements, for the period post completion, the
Group's 45% share of field costs - capex, opex and G&A - are
accounted for as incurred by the Group, although all such costs are
paid by IPR and set off against the carry. Please see Note 14 for
more details on the disposal of asset held for sale.
All revenues earned are paid direct to the Group.
DD&A per barrel by Segment Vietnam Egypt Total
$m $m $m
--------------------------- ------- ----- -----
Depreciation, depletion
and amortisation 51.0 4.1 55.1
--------------------------- ------- ----- -----
Production (BOEPD) 5,418 1,748 7,166
--------------------------- ------- ----- -----
DD&A per BOE ($) * 25.79 6.43 21.07
--------------------------- ------- ----- -----
* Calculation based on full production entitlement for the year.
Actual DD&A charges were calculated on 45% share of production
for the full year, giving a revised DD&A per bbl metric of
$7.98/boe.
Movements in Property,
Plant and Equipment 2022 2021
$m $m
------------------------------ ------ -------
As at 1 Jan 399.8 435.8
------------------------------ ------ -------
Capital spend 23.2 24.7
------------------------------ ------ -------
Revision in decommissioning
assets (13.9) (1.9)
------------------------------ ------ -------
Recognition of right-of-use
assets 0.8 -
------------------------------ ------ -------
Re-classification of
assets held for sale - (62.0)
------------------------------ ------ -------
DD&A- Oil and gas properties (55.1) (51.0)
------------------------------ ------ -------
DD&A - Other assets (0.1) (0.4)
------------------------------ ------ -------
Impairment reversal/(charge)
- PP&E 27.1 54.6
------------------------------ ------ -------
As at 31 Dec 381.8 399.8
------------------------------ ------ -------
Property, Plant and
Equipment 381.0 399.8
------------------------------ ------ -------
Right-to-use-Asset
(IFRS 16 Impact) 0.8 -
------------------------------ ------ -------
As at 31 Dec 381.8 399.8
------------------------------ ------ -------
Taxation
The overall net tax charge of $56.2m (2021: $43.3m) relates to
tax charges in Vietnam of $47.9m plus the deferred tax charge on
impairment reversal of $8.3m (2021: Vietnam tax charges of $24.8m
plus the deferred tax charge on impairment reversal of $18.5m).
The Group's effective tax rate approximates to the statutory tax
rate in Vietnam of 50%, after adjusting for non-deductible
expenditure and tax losses not recognised.
The Egypt concessions are subject to corporate income tax at the
standard rate of 40.55%, however responsibility for payment of
corporate income taxes falls upon EGPC on behalf of PEF. The Group
records a tax charge, with a corresponding increase in revenue, for
the tax paid by EGPC on its behalf. However, this is only valid if
PEF is in a tax paying position and no such tax has been recorded
this year.
One of the Group's companies entered into commodity swaps
designated as cash flow hedges. In accordance with IAS 12, a
deferred tax asset has not been recognised in relation to the
hedging losses of $22.5m recorded in the year as it is unlikely
that the UK tax group will generate sufficient taxable profit in
the future, against which the deductible temporary differences can
be utilised.
Profit/(loss) post-tax
The post-tax profit for the year from continuing operations and
prior to the impairment reversal of $27.9m, impairment tax charge
of $8.3m, exceptional costs of $0.8m and loss on disposal of $6.3m
was $11.9m (2021: post tax loss for the year of $24.9m from
continuing operations and prior to the impairment reversal of
$42.0m, impairment tax charge of $18.5m and exceptional costs of
$3.3m). The overall profit for the year was $ 24.4m (2021: $ 4.7m
loss).
Cash flow
Operating cash flow (before movements in working capital) was
$128.8m (2021: $60.1m). After tax charges of $54.7m (2021: $39.9m),
restructuring and exceptional expenses $2.7m (2021: $0.7m) and
working capital adjustments of $18.1m (2021: $8.6m), the cash
generated from operations was $53.4m (2021: $10.8m). Cash generated
from operations, after tax charges, exceptional expenses and
working capital movements, will form the basis of our dividend
framework going forward.
Operating cash flow (before movements in working capital)
adjusted for the impact of the hedging positions of $22.5m loss
(2021: $29.7m loss) gives an underlying operational performance of
$151.3m (2021: $89.8m), which is consistent with the significant
improvement seen in commodity prices offset by the production
decrease year on year.
The increase in receivables was $7.7m (2021: increase in
receivables of $7.2m). The movement in 2022 is primarily driven by
$16.1m increase from Egypt, which was mainly due to the increase in
EGPC receivables inclusive of $7m catch-up invoice for improved
fiscal terms under the Third Amendment to the El Fayum Concession
and the lack of hard currency in country. As noted in previous
updates to the market, the Group has opted not to accept the
payment of PEF's receivables balance in EGP unless required for
operations. PEF is entitled under contract to be paid for
hydrocarbon sales in US dollars. The progressive devaluation of EGP
against USD means that it is preferable to continue to hold USD
denominated receivables. The International Monetary Fund (IMF)
recently announced that its Executive Board had approved the
provision of a $3 billion, 46-month extended fund facility to
Egypt, which the IMF expects to catalyse additional financing of
approximately $14 billion from Egypt's international and regional
partners. In addition, Egypt is seeking access to up to a further
$1 billion from the IMF's newly created resilience and
sustainability facility to support climate-related policy goals.
Taken together, these developments are widely anticipated to
improve Egypt's FX reserves and overall liquidity in the first half
of 2023. The Company therefore remain optimistic that outstanding
receivables with EGPC will start to be recovered during 2023. The
increase in Egypt receivables was partially offset by timing
differences on the Vietnam cargoes, leading to a decrease in
receivables of $6.9m despite higher commodity prices.
Capital expenditure on continuing operations for the year was
lower at $31.9m (2021: $41.8m). On Block 16-1 - TGT Field, the
drilling programme for two development wells completed in H2 2022,
on time and under budget. The first well, H1-35P, commenced
production on 21 October 2022, and the second well, 11XPST,
commenced production on 10 November 2022. On Block 9-2 - CNV Field,
one development well, CNV-2PST1, commencing in H2 2022 and has now
been completed. In El Fayum, seven wells were put on production in
2022 (including one well drilled in 2021), and one additional well
drilled in Q4 2022 is due for completion in Q1 2023.
Net cash outflows from financing activities of $19.8m (2021:
$31.1m inflow) included outflows in relation to the RBL of $0.2m in
June 2022 and $12.9m in December following the half year and year
end redetermination processes and the amount drawn stood at $65.0m
at year end.
The RBL loan, which is secured over only the existing Vietnam
producing assets, matures in July 2025. The facility amount is
amortised by $14.2m every re-determination from 1 July 2022, with a
facility amount as at 31 December 2022 of $85.75m, which decreased
to $71.5m from 1 January 2023 and will decrease further to $57.3m
from 1 July 2023. The Group is able to dividend up from the Vietnam
RBL zone to the Company twice a year in January and July following
approval of the redetermination.
Financing activities also included net $2.7m outflow in relation
to the NBE revolving credit facility, which allows PEF to draw down
60% of the value of each El Fayum invoice in USD. The amount drawn
under the NBE facility as at 31 December 2022 was $9.2m. A further
$2.9m outflow was due to the share buyback programme that was
initiated in July 2022. The first phase of that programme,
completed in January 2023, resulted in a total of 10.3 million
shares being purchased, at a daily average price of 24.4p.
Tax strategy and total tax contribution
Tax is managed proactively and responsibly with the goal of
ensuring that the Group is compliant in all countries in which it
holds interests. Any tax planning undertaken is commercially driven
and within the spirit as well as the letter of the law.
This approach forms an integral part of the Group's sustainable
business model.
The Group's Code of Business Conduct and Ethics seeks to build
open, cooperative and constructive relationships with tax
authorities and governmental bodies in all territories in which it
operates. The Group supports greater transparency in tax reporting
to build and maintain stakeholder trust. We have a number of
overseas subsidiaries which were set up some time ago and the Group
is now proactively planning to bring these into the UK tax net to
ensure greater transparency and comparability. No additional taxes
are expected to be due as a result of this exercise.
During 2022, the total payments to governments for the Group
amounted to $ 245.3 m (2021: $198.2m), of which $ 211.5 m or 86 %
(2021: $151.9m or 77%) was related to the Vietnam producing licence
areas, of which $ 140.7 m (2021: $102.6m) was for indirect taxes
based on production entitlement. In Egypt payments to government
totalled $ 31.3 m (2021: $44.7m), of which $ 28.8 m (2021: $44.1m)
related to indirect taxes based on production entitlement.
Balance sheet
Intangible assets increased during the period to $16.5m (2021:
$12.4m). Additions for the year related to Blocks 125 & 126 in
Vietnam $3.1m (2021: $10.6m), Egypt $1.0m (2021: $3.9m) and $0.2m
(2021: $0.7m) for the Israeli bid round licence fee. The Group has
written off $0.2m (2021: $2.2m) relating to the Israel asset as no
substantive expenditure has been identified under IFRS 6. In 2021,
$2.1m of intangible assets relating to the Egypt concessions were
re-classified as assets held for sale.
The movements in the Property, Plant and Equipment asset class
are shown above.
Impairment reversals
As a result of previously recognised impairment losses, combined
with ongoing oil price volatility, economic uncertainty leading to
an increase in inflation and discount rates, and movements in 2P
reserves, we have tested each of our oil and gas producing
properties for impairment. The results of these impairment tests
are summarised below. For each producing property, the recoverable
amount has been determined using the value in use method which
constitutes a level 3 valuation within the fair value hierarchy.
The recoverable amount is supported by the fair value derived from
a discounted cash flow valuation of the 2P production profile.
Summary of Impairments TGT CNV Egypt Total
- Oil and Gas properties $m $m $m $m
---------------------------- ------ ------ ----- ------
2022
---------------------------- ------ ------ ----- ------
Pre-tax impairment reversal 19.7 3.6 3.8 27.1
---------------------------- ------ ------ ----- ------
Deferred tax charge (6.9) (1.4) - (8.3)
---------------------------- ------ ------ ----- ------
Post-tax impairment reversal 12.8 2.2 3.8 18.8
---------------------------- ------ ------ ----- ------
Reconciliation of carrying
amount: (1)
---------------------------- ------ ------ ----- ------
As at 1 Jan 2022 266.0 84.2 49.2 399.4
---------------------------- ------ ------ ----- ------
Additions 7.0 3.2 13.6 23.8
---------------------------- ------ ------ ----- ------
Changes in decommissioning
asset (2) (11.1) (2.8) - (13.9)
---------------------------- ------ ------ ----- ------
DD&A (39.2) (11.8) (4.1) (55.1)
---------------------------- ------ ------ ----- ------
Impairment reversal 19.7 3.6 3.8 27.1
---------------------------- ------ ------ ----- ------
As at 31 Dec 2022 242.4 76.4 62.5 381.3
---------------------------- ------ ------ ----- ------
2021
---------------------------- ------ ------ ------ ------
Pre-tax impairment reversal 49.1 3.8 1.7 54.6
---------------------------- ------ ------ ------ ------
Deferred tax charge (17.1) (1.4) - (18.5)
---------------------------- ------ ------ ------ ------
Post-tax impairment reversal 32.0 2.4 1.7 36.1
---------------------------- ------ ------ ------ ------
Reconciliation of carrying
amount: (1)
---------------------------- ------ ------ ------ ------
As at 1 Jan 2021 239.3 91.2 104.1 434.6
---------------------------- ------ ------ ------ ------
Additions 11.4 0.3 12.9 24.6
---------------------------- ------ ------ ------ ------
Reclassified as assets held
for sale - - (1.4) (1.4)
---------------------------- ------ ------ ------ ------
Changes in decommissioning
asset (2) (1.0) (0.9) - (1.9)
---------------------------- ------ ------ ------ ------
DD&A (32.8) (10.2) (8.0) (51.0)
---------------------------- ------ ------ ------ ------
Impairment reversal 49.1 3.8 1.7 54.6
---------------------------- ------ ------ ------ ------
Sub-total 266.0 84.2 109.3 459.5
---------------------------- ------ ------ ------ ------
Reclassified as assets held
for sale - - (60.1) (60.1)
---------------------------- ------ ------ ------ ------
As at 31 Dec 2021 266.0 84.2 49.2 399.4
---------------------------- ------ ------ ------ ------
(1) Eg ypt carrying value reflects 45% share (2021: 100%).
(2) Changes in decommissioning asset for TGT is due to changes
in discount rate and the field abandonment plan, whereas CNV
reflects the change in discount rate only (2021: change in discount
rate only for both TGT and CNV)
It should be noted that the TGT impairment reversal for full
year 2022 has been restricted to reflect the remaining balance of
historic impairment charges previously recorded against the field.
Further details of these impairment charges, including key
assumptions in relation to oil price and discount rate are provided
in Note 10 of the preliminary financial statements.
Cash is set aside into abandonment funds for both TGT and CNV.
These abandonment funds are controlled by PetroVietnam and, as the
Group retains the legal rights to the funds pending commencement of
abandonment operations, they are treated as other non-current
assets in the Financial Statements.
Oil inventory was $7.2m at 31 December 2022 (2021: $5.9m), of
which $7.0m related to Vietnam and $0.2m to Egypt. Trade and other
receivables increased to $60.9m (2021: $28.1m) of which $11.4m
(2021: $18.2m) relates to Vietnam and $49.0m (2021: $8.5m) relates
to Egypt. For Egypt, the closing balance includes $20.9m of carry
(2021: $nil), which reflects the remaining disproportionate funding
contribution from IPR to compensate for net cash flows since the
economic date of the farm down transaction, 1 July 2020, and the
completion date of 21 March 2022. The carry decreases every month
by the cash calls received from IPR. In addition, Egypt trade
receivables include $24.2m from EGPC where collection has been
delayed by the devaluation of EGP and ongoing restrictions on
outgoing USD transfers by the Central Bank of Egypt previously
highlighted.
Cash and cash equivalents at the end of the year were $45.3m
(2021: $27.1m) mainly driven by net cash flows from operating
activities of $53.4m (2021: $10.8m) as a result of higher commodity
prices during the year, offset by lower production.
Trade and other payables were $14.0m (2021: $30.6m), of which
$6.3m (2021: $14.5m) relates to the Egypt payables, inclusive of
Stratton royalty obligation and following re-classification of
Petrosilah working capital balances to joint venture receivables
following the farm-down transaction. $4.8m (2021: $4.8m) relates to
Vietnam payables, $0.5m (2021: $6.5m) net hedging liability and
$1.9m (2021: $4.4m) Head Office payables. Tax payables decreased to
$5.2m (2021: $5.4m) which is linked to the timing of cargoes from
TGT.
Borrowings were $74.2m (2021: $80.5m), a decrease of $6.3m with
$13.1m related to repayments following the RBL redeterminations in
June and December, partially offset by $4.1m amortisation of
capitalised borrowing costs and one-off charges in relation to the
redeterminations. This was offset by a net increase in the NBE
credit facility of $2.7m during the year.
Long-term provisions comprise the Group's decommissioning
obligations and, for 2021, the royalty over the El Fayum asset. In
Vietnam, the decommissioning provision decreased from $66.9m at
2021 year-end to $54.3m at 2022 mainly due to an increase in
discount rate from 1.51% to 3.83% as a result of an increase in
prevailing risk-free market rates, partially offset by the TGT
infill wells programme completed during the year. The amounts set
aside into the abandonment funds total $50.2m (2021: $48.1m). No
decommissioning obligation exists under the El Fayum
Concession.
The royalty provision relates to a historical arrangement
granting a 3% royalty on PEF's share of profit oil and excess cost
recovery from El Fayum in Egypt. At 31 December 2022, the long-term
provision was $nil (2021: $2.2m) and the amount disclosed in
current payables is $2.5m (2021: $3.4m)
Own shares
The Pharos Employee Benefit Trust ("EBT") holds ordinary shares
of the Company for the purposes of satisfying long-term incentive
awards for senior management. At the end of 2022, the trust held
2,126,857 (2021: 1,767,757), representing 0.48% (2021: 0.40%) of
the issued share capital.
In addition, as at 31 December 2022, the Company held 9,122,268
(2021: 9,122,268) treasury shares, representing 2.06% (2021: 2.02%)
of the issued share capital. All shares purchased under the
on-market buyback programme originally announced in July 2022 and
extended in January 2023 have been or will be cancelled rather than
retained in treasury.
Dividend Framework
The Company intends to recommence dividend payments starting in
2023. Our policy is now set at returning no less than 10% of
Operating Cash Flow (OCF).
OCF has been selected as the most appropriate measure as it
automatically takes account of:
-- movements in Brent price;
-- tax, which is the main form of government take in Vietnam; and
-- working capital movements.
The first dividend will therefore be a final dividend for the
2022 financial year. The Board have recommended a final dividend of
1.00 pence per share (based on a minimum 10% OCF of $5.34m at the
average rate of exchange for 2022) subject to approval of the
shareholders at the Company's 2023 AGM. The final dividend will be
paid in full on 12 July 2023 in Pounds Sterling to ordinary
shareholders on the register at the close of business on 16 June
2023. Going forward, we expect the payment pattern will move to a
conventional pattern of an interim and a final dividend. As is
normally the case with interim dividends, and unlike the final
dividend for 2022 to be proposed at the 2023 AGM, the interim
dividend will not be conditional on separate shareholder
approval.
Going concern
Pharos continuously monitors its business activities, financial
position, cash flows and liquidity through detailed forecasts.
Scenarios and sensitivities are also regularly presented to the
Board, including changes in commodity prices and in production
levels from the existing assets, plus other factors which could
affect the Group's future performance and position.
A base case forecast has been considered that utilises oil
prices of $88.3/bbl in 2023 and $84.8/bbl in 2024. The key
assumptions and related sensitivities include a "Reasonable Worst
Case" (RWC) scenario, where the Board has taken into account the
risk of an oil price crash broadly similar to what occurred in
2020. It assumes the Brent oil price down by a third to $59/bbl in
May 2023 and gradually recovers to base price in next 12 months,
concurrent with 5% reductions in Vietnam and Egypt production
compared to our base case from June 2023. Both the base case and
RWC take into account effect of hedging that has already been put
in place at 31 December 2022 and subsequent hedges placed in 2023,
now covering c.33% for the full year 2023 and 6% of Q1 2024. We
have therefore secured an average floor price and ceiling price of
c.$64/bbl and c. $100/bbl, respectively, for the entire hedged
volumes. Under the RWC scenario, we have identified appropriate
mitigating actions, which could look to defer capital expenditure
programme as required.
In addition, we have conducted a reverse stress test sensitivity
analysis that indicates the magnitude of oil price decline required
to breach our financial headroom, assuming all other variables
remain unchanged.
Our business in Vietnam remains robust, with breakeven price of
c.$30/bbl. We have limited capital expenditure in Vietnam which
includes the delay of CNV 2PST1 well. The cash flows have also been
tested in the unlikely event that an extension for the 125/126 is
not secured. The majority of our debt is secured against the
Vietnam assets under the RBL, only $9.2m drawn on an uncommitted
revolving credit facility on the Egypt revenue invoices.
In Egypt, we have 9 wells in 2023 and the Base case assumes a
full investment scenario.
On the basis of the forecasts provided above, the Group is
expected to have sufficient financial headroom for the 12 months
from the date of approval of the 2022 Accounts. Based on this
analysis, the Directors have a reasonable expectation that the
Group has adequate resources to continue its operations in the
foreseeable future. Therefore, the Financial Statements have been
prepared using the going concern basis of accounting.
Financial outlook
We have a lot to look forward to as we move forward in 2023 and
beyond.
-- A strong and stable balance sheet, improved liquidity,
improved fiscal terms in Egypt, stable production with a solid USD
cash flow from our Vietnam portfolio and a reduced cost base
throughout the Group.
-- Continued development drilling and carry in Egypt, extra $5m
contingent consideration payment in 2023 and potentially for the
next 3 years (oil price dependent). We are encouraged by the
intervention from the IMF and hope to see an improved position in
our Egyptian receivables.
-- Strong support from our RBL lenders over the Vietnam assets
as we continue in 2023 to pay down this facility and a renewal of
our uncommitted revolving credit facility with the National Bank of
Egypt.
Further returns to shareholders are anticipated in 2023, with
the announcement in January of an additional $3m committed to an
extension of the Company's on-market share buyback programme, and
the resumption of sustainable dividends based on OCF to be proposed
at the 2023 AGM.
Sue Rivett
Chief Financial Officer
Condensed consolidated income statement
for the year to 31 December 2022
2022 2021
Notes $ million $ million
---------- ------------
Continuing operations
Revenue 3 199.1 134.1
Cost of sales 4 (116.8) (114.6)
---------- ------------
Gross profit 82.3 19.5
Administrative expenses (10.0) (13.2)
Impairment reversal/(charge)
Intangibles 3, 9 0.8 (2.2)
Impairment reversal
PP&E 3, 10 27.1 54.6
Impairment charge
- Assets classified
as held for sale 3, 14 - (10.4)
---------- ------------
Operating profit 100.2 48.3
Other/restructuring
expense 5 (0.8) (3.3)
Loss on disposal 14 (6.3) -
Investment revenue 0.2 -
Finance costs 6 (12.7) (6.4)
---------- ------------
Profit before tax 3 80.6 38.6
Tax (56.2) (43.3)
---------- ------------
Profit/(loss) for the year 24.4 (4.7)
---------- ------------
Profit/(loss) per share (cents) 8
Basic 5.6 (1.1)
Diluted 5.4 (1.1)
Condensed consolidated statements of comprehensive income
for the year to 31 December
2022
2022 2021
$ million $ million
---------- ------------
Profit/(loss) for
the year 24.4 (4.7)
Items that may be subsequently reclassified to
profit or loss:
Fair value loss arising on hedging instruments
during the year (18.9) (27.7)
Less: Loss arising on hedging Instruments reclassified
to profit or loss 22.5 29.7
Total comprehensive gain/(loss) for the
year 28.0 (2.7)
---------- ------------
The above condensed consolidated income statement and condensed
consolidated statements of comprehensive income should
be read in conjunction with the accompanying notes.
CONDENSED CONSOLIDATED Balance sheet
Group Company
---------- ---------- ---------- ----------
2022 2021 2022 2021
Notes $ million $ million $ million $ million
---------- ---------- ---------- ----------
Non-current assets
Intangible assets 9 16.5 12.4 - -
Property, plant and
equipment 10 381.0 399.8 - -
Right-of-use assets 0.8 - - -
Investments - - 335.5 278.7
Loan to subsidiaries - - 23.0 27.4
Other assets 59.1 48.1 - -
---------- ----------
457.4 460.3 358.5 306.1
---------- ---------- ---------- ----------
Current assets
Inventories 7.2 10.7 - -
Trade and other receivables 60.9 28.1 0.4 1.4
Tax receivables 2.1 1.5 0.1 0.4
Cash and cash equivalents 45.3 27.1 8.8 5.3
Assets classified
as held for sale 14 - 62.0 - -
---------- ---------- ----------
115.5 129.4 9.3 7.1
---------- ---------- ---------- ----------
Total assets 572.9 589.7 367.8 313.2
Current liabilities
Trade and other payables (14.0) (30.6) (1.9) (4.3)
Borrowings (39.6) (33.3) - -
Lease Liabilities (0.3) - - -
Tax payables (5.2) (5.4) (1.2) (1.0)
Liabilities directly associated
with assets classified as
held for sale 14 - (8.5) - -
---------- ---------- ---------- ----------
(59.1) (77.8) (3.1) (5.3)
---------- ---------- ----------
Non-current liabilities
Other payables (0.9) - - -
Deferred tax liabilities (92.9) (91.2) - -
Borrowings (34.6) (47.2) - -
Lease liabilities (0.5) - - -
Long term provisions (54.3) (69.1) - -
---------- ---------- ---------- ----------
(183.2) (207.5) - -
Total liabilities (242.3) (285.3) (3.1) (5.3)
---------- ---------- ---------- ----------
Net assets 330.6 304.4 364.7 307.9
---------- ---------- ---------- ----------
Equity
Share capital 34.3 34.9 34.3 34.9
Share premium 58.0 58.0 58.0 58.0
Other reserves 253.6 250.5 199.7 202.4
Retained (deficit)
/ earnings (15.3) (39.0) 72.7 12.6
---------- ---------- ---------- ----------
Total equity 330.6 304.4 364.7 307.9
---------- ---------- ---------- ----------
The above condensed consolidated balance sheet should be read in
conjunction with the accompanying notes.
CONDENSED consolidated STATEMENTs OF CHANGES IN EQUITY
Group
---------------------------------------------------------------------------
Called
up Retained
earnings
share capital Share premium Other reserves /(deficit) Total
$ million $ million $ million $ million $ million
--------------- -------------- --------------- ------------ -----------
As at 1 January 2021 31.9 55.4 243.0 (36.6) 293.7
Loss for the year - - - (4.7) (4.7)
Other comprehensive income - - 2.0 - 2.0
Share issued 3.0 2.6 5.3 - 10.9
Share-based payments - - 2.5 - 2.5
Transfer relating to share-based
payments - - (2.3) 2.3 -
--------------- -------------- --------------- ------------ -----------
As at 1 January 2022 34.9 58.0 250.5 (39.0) 304.4
Profit for the year - - - 24.4 24.4
Other comprehensive income - - 3.6 - 3.6
Share buy back (0.6) - 0.6 (2.9) (2.9)
Treasury shares repurchased - - (0.6) - (0.6)
Share-based payments - - 1.7 - 1.7
Transfer relating to share-based
payments - - (2.2) 2.2 -
As at 31 December 2022 34.3 58.0 253.6 (15.3) 330.6
--------------- -------------- --------------- ------------ -----------
Company
---------------------------------------------------------------------
Called
up Retained
share capital Share premium Other reserves earnings Total
$ million $ million $ million $ million $ million
-------------- ------------- -------------- ---------- ----------
As at 1 January 2021 31.9 55.4 197.6 6.9 291.8
Profit for the year - - - 1.9 1.9
Shares issued 3.0 2.6 5.3 - 10.9
Currency exchange translation
differences - - 0.1 1.5 1.6
Share-based payments - - 2.5 - 2.5
Transfer relating to share-based
payments - - (3.1) 2.3 (0.8)
-------------- ------------- -------------- ---------- ----------
As at 1 January 2022 34.9 58.0 202.4 12.6 307.9
Profit for the year - - - 60.7 60.7
Share buy back (0.6) - 0.6 (2.9) (2.9)
Share-based payments - - 1.7 - 1.7
Transfer relating to share-based
payments - - (5.0) 2.3 (2.7)
As at 31 December 2022 34.3 58.0 199.7 72.7 364.7
-------------- ------------- -------------- ---------- ----------
The above condensed statements of changes in equity should be
read in conjunction with the accompanying notes.
CONDENSED CONSOLIDATED cash flow statements
for the year to 31 December 2022
Group Company
----------- ---------- ----------- ----------
2022 2021 2022 2021
Notes $ million $ million $ million $ million
----------- ---------- ----------- ----------
Net cash from (used in) operating
activities 13 53.4 10.8 (11.6) (7.1)
----------- ---------- ----------- ----------
Investing activities
Purchase of intangible assets (4.4) (15.2) - -
Purchase of property, plant
and equipment (25.4) (24.4) - -
Consideration in relation to
farm out of Egyptian assets(1) 18.4 2.0 - -
Assignment fee in relation to
farm out of Egyptian assets (0.5) - - -
Payment to abandonment fund (2.1) (2.2) - -
Other investment in subsidiary
undertakings - - - (8.4)
Dividends received from subsidiary
undertakings - - 19.0 6.1
Net cash (used in) from investing
activities (14.0) (39.8) 19.0 (2.3)
Financing activities
Share based payments (0.4) - - -
Repayment of borrowings (27.1) (12.5) - -
Proceeds from borrowings 16.7 39.9 - -
Interest paid on borrowings (6.0) (6.8) - -
Lease payments (0.1) (0.4) - -
Net proceeds from issue of share
capital - 10.9 - 10.9
Share buy back (2.9) - (2.9) -
Funding movements with subsidiaries - - (1.0) -
----------- ---------- ----------- ----------
Net cash (used in) from financing
activities (19.8) 31.1 (3.9) 10.9
----------- ---------- ----------- ----------
Net increase in cash and cash
equivalents 19.6 2.1 3.5 1.5
Cash and cash equivalents at
beginning of year 27.1 24.6 5.3 3.5
Effect of foreign exchange rate
changes (1.4) 0.4 - 0.3
Cash and cash equivalents at
end of year 45.3 27.1 8.8 5.3
----------- ---------- ----------- ----------
(1) During the year IPR, acting as operator and agent, was
authorised to settle its operating liabilities of $6.6m and
investing liabilities of $8.8m against the consideration due from
the associated carry debtor (Note 14) amounting to $15.4m. The
Company has disclosed the underlying cash flows as operating,
investing or financing according to their nature on the basis that,
as a principal, the entity has the right to the cash inflows and/or
the obligation to settle the liability and ensure clarity of
disclosure of the operating cash costs of the business.
The above condensed consolidated cash flow statements should be
read in conjunction with the accompanying notes.
Notes to the condensed consolidated financial statements
1. General information
The financial information set out above does not constitute the
Company's statutory accounts for the years ended 31 December 2022
or 2021, but is derived from those accounts. A copy of the
statutory accounts for 2021 has been delivered to the Registrar of
Companies and those for 2022 will be delivered following the
Company's annual general meeting. The auditors have reported on
those accounts; their reports were unqualified, did not draw
attention to any matters by way of emphasis without qualifying
their report and did not contain statements under section 498(2) or
(3) of the Companies Act 2006. Whilst the financial information
included in this preliminary announcement has been computed in
accordance with International Financial Reporting Standards (IFRS)
as issued by the International Accounting Standard Board (IASB),
this announcement does not itself contain sufficient information to
comply with IFRS. The financial statements are presented in US
dollars which is the functional currency of each of the Company's
subsidiary undertakings.
2. Significant accounting policies
(a) Basis of preparation
The financial information has been prepared in accordance with
the recognition and measurement criteria of international
accounting standards in conformity with the requirements of the
Companies Act 2006 and International Financial Reporting Standards,
as issued by the International Accounting Standard Board (IASB).
The financial information has also been prepared in accordance with
the recognition and measurement criteria of International Financial
Reporting Standards as issued by the IASB.
The financial information has also been prepared on a going
concern basis of accounting.
(b) New and amended standards adopted by Pharos
A number of new or amended standards became applicable for the
current reporting period. The Group did not have to change its
accounting policies or make retrospective adjustments as a result
of adopting these standards.
- Property, Plant and Equipment: Proceeds before Intended Use - Amendments to IAS 16
- Onerous Contracts - Cost of Fulfilling a Contract - Amendments to IAS 37
- Annual Improvements to IFRS Standards 2018-2020
- Reference to the Conceptual Framework - Amendments to IFRS 3
(c) New standards and interpretations not yet adopted
Certain new accounting standards and interpretations have been
published that are not mandatory for 31 December 2022 year end and
have not been early adopted by the Group. These standards are not
expected to have a material impact on the Group in the current or
future reporting periods nor on foreseeable future
transactions.
3. Segment information
The Group has one principal business activity being oil and gas
exploration and production. The Group's continuing operations are
located in South East Asia and Egypt (the Group's operating
segments). There are no inter-segment sales. South East Asia and
Egypt form the basis on which the Group reports its segment
information.
2022
---------- ---------- ----------- ----------
SE Asia Egypt Unallocated Group
$ million $ million $ million $ 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) - Intangibles(2) 1.0 - (0.2) 0.8
---------- ---------- ----------- ----------
Impairment reversal - PP&E 23.3 3.8 - 27.1
---------- ---------- ----------- ----------
Loss on disposal (Note 14) - (6.3) - (6.3)
---------- ---------- ----------- ----------
Profit (loss) before tax(1) 108.3 16.9 (44.6) 80.6
---------- ---------- ----------- ----------
Tax charge on operations (47.9) - - (47.9)
---------- ---------- ----------- ----------
Tax charge on impairment reversal (8.3) - - (8.3)
---------- ---------- ----------- ----------
2021
---------- ---------- ----------- ----------
SE Asia Egypt Unallocated Group
$ million $ million $ million $ million
---------- ---------- ----------- ----------
Oil and gas sales 131.0 32.8 - 163.8
---------- ---------- ----------- ----------
Realised loss on commodity hedges - - (29.7) (29.7)
---------- ---------- ----------- ----------
Total revenue 131.0 32.8 (29.7) 134.1
---------- ---------- ----------- ----------
Depreciation, depletion and amortisation
- Oil and gas (43.0) (8.0) - (51.0)
---------- ---------- ----------- ----------
Depreciation, depletion and amortisation
- Other - (0.4) - (0.4)
---------- ---------- ----------- ----------
Impairment charge - Intangibles - - (2.2) (2.2)
---------- ---------- ----------- ----------
Impairment reversal - PP&E 52.9 1.7 - 54.6
---------- ---------- ----------- ----------
Impairment charge - Assets classified
as held for sale - (10.4) - (10.4)
---------- ---------- ----------- ----------
Profit (loss) before tax(1) 98.8 (10.1) (50.1) 38.6
---------- ---------- ----------- ----------
Tax charge on operations (24.8) - - (24.8)
---------- ---------- ----------- ----------
Tax charge on impairment reversal (18.5) - - (18.5)
---------- ---------- ----------- ----------
(1) Unallocated amounts included in profit/(loss) before tax
comprise corporate costs not attributable to an operating segment,
investment revenue, other gains and losses and finance costs.
(2) Includes $1.0m reversal of impairment of Block 125&126
tax receivable (other receivable - current), offset by $(0.2)m
write-off of seismic costs relating to Israel exploration Zones A
and C
Included in revenues arising from South East Asia and Egypt are
revenues of $182.5m and $36.8m which arose from the Group's three
largest customers, who contributed more than 10% to the Group's oil
and gas revenue (2021: $128.3m and $32.8m in South East Asia and
Egypt from the Group's two largest customers).
Geographical information
The Group's oil and gas revenue and non-current assets
(excluding other receivables) by geographical location are
separately detailed below where they exceed 10% of total revenue or
non-current assets, respectively:
Revenue
All of the Group's oil and gas revenue is derived from foreign
countries. The Group's oil and gas revenue by geographical location
is determined by reference to the final destination of oil or gas
sold.
2022 2021
$ million $ million
----------- -----------
Vietnam 97.1 131.0
Egypt 36.8 32.8
China 87.7 -
221.6 163.8
----------- -----------
2022 2021
Non-current assets $ million $ million
----------- -----------
Vietnam 332.5 360.8
Egypt 65.8 51.4
398.3 412.2
----------- -----------
Excludes other assets.
4. Cost of sales
2022 2021
$ million $ million
---------- ----------
Depreciation, depletion and amortisation 55.1 51.0
Production based
taxes 14.7 10.1
Export duty 3.2 -
Production operating
costs 45.6 53.6
Inventories (1.8) (0.1)
116.8 114.6
---------- ----------
5. Other/restructuring expense
2022 2021
$ million $ million
---------- ----------
Redundancy costs 0.1 3.0
Premium - lease
transfer(1) 0.7 0.3
0.8 3.3
---------- ----------
(1) Relates to the transfer of the London office lease to a
third party, at which point the Company derecognised the right of
use asset and associated lease liability. In 2020, $1.2m was
transferred to an escrow account held by a third party (recorded
within prepayments). The amount was released to the income
statement over 21 months on the condition the new tenant paid the
rent to the landlord. In 2022, the remaining balance of $0.7m
(2021: $0.3m) was released from the escrow account and paid to the
new tenant.
6. Finance Cost
2022 2021
$ million $ million
----------------------------- -----------
Unwinding of discount on provisions 1.3 0.8
Interest expense payable and similar fees 6.0 3.8
Interest on lease liabilities - -
Amortisation of capitalised borrowing costs 4.1 2.4
Net foreign exchange losses/(gains) 1.3 (0.6)
----------------------------- -----------
12.7 6.4
----------------------------- -----------
In 2022, $1.3m relates to the unwinding of discount on the
provisions for decommissioning (2021: $0.8m). The provisions are
based on the net present value of the Group's share of the
expenditure which may be incurred at the end of the producing life
of TGT and CNV (currently estimated to be 8 - 9 years) in the
removal and decommissioning of the facilities currently in
place.
Following the June and December 2022 redeterminations in
relation to the Group's reserve based lending facility, there was a
change in estimated future cash flows, as a result a one off loss
of $2.6m and amortised cost of $1.5m have been recognised in profit
or loss.
7. Tax
2022 2021
$ million $ million
----------- ---------------
Current tax charge 54.5 37.6
Deferred tax credit on operations (6.6) (12.8)
Deferred tax charge on impairment reversals 8.3 18.5
----------- ---------------
Total tax charge 56.2 43.3
----------- ---------------
The Group's corporation tax is calculated at 50% (2021: 50%) of
the estimated assessable profit for the year in Vietnam. In Egypt,
under the terms of the concession any local taxes arising are
settled by EGPC. During 2022 and 2021, both current and deferred
taxation have arisen in overseas jurisdictions only.
The charge for the year can be reconciled to the profit per the
income statement as follows:
2022 2021
$ million $ million
----------- -----------
Profit before tax 80.6 38.6
Profit before tax at 50% (2021: 50%) 40.3 19.3
Effects of:
Non-taxable income (3.3) (8.0)
Non-deductible expenses 5.6 4.5
Tax losses not recognised 13.8 28.7
Adjustments to tax charge in respect of previous
periods (0.2) (1.2)
----------- -----------
Tax charge for the year 56.2 43.3
----------- -----------
The prevailing tax rate in Vietnam, where the Group produces oil
and gas, is 50%. The tax charge in future periods may also be
affected by the factors in the reconciliation above.
The effect of non-deductible exploration costs written back of
$(0.5)m in 2022 related to the partial reversal of an impairment of
exploration assets in Vietnam.
Non-taxable income principally relates to Vietnam impairment
reversal of $(3.3)m (2021: $(8.0)m). Non-deductible expenses
primarily relate to Vietnam DD&A charges for costs previously
capitalised, which are non-deductible for Vietnamese tax purposes
of $5.6m (2021: $1.8m). A further $nil (2021: $2.7m) relates to
non-deductible corporate costs including share scheme
incentives.
The Egypt concessions are subject to corporate income tax at the
standard rate of 40.55%, however responsibility for payment of
corporate income taxes falls upon EGPC on behalf of our local
subsidiary Pharos El Fayum (PEF). The Group records a tax charge,
with a corresponding increase in revenues, for the tax paid by EGPC
on its behalf. However, this is only valid if PEF is in a historic
profit making position and no such tax has been recorded this
year.
The effect from tax losses not recognised relates to costs,
primarily of the Company, deductible for tax in the UK but not
expected to be utilised in the foreseeable future. For 2021, it
also includes losses arising in Egypt for which no future benefit
can be obtained under the terms of the concession agreement. During
2022, Egypt concessions recorded a net profit before tax of $16.9m
(profit after tax impact of $8.5m) which has been offset against
tax losses not recognised, as Egypt is in a historic loss making
position. The group did not recognise deferred tax assets in
relation to historical tax losses available to offset future
taxable profits of $28m on the basis that there will be no future
benefits arising from these losses as any taxes in the future will
be paid by EGPC on behalf of the group.
8. Earnings per share
The calculation of the basic and diluted earnings per share is
based on the following data:
Group
------------------------
2022 2021
$ million $ million
----------- -----------
Gain/(loss) for the purposes of basic profit/(loss)
per share 24.4 (4.7)
Effect of dilutive potential ordinary shares -
Cash settled share awards and options (0.3) -
----------- -----------
Gain/(loss) for the purposes of diluted profit/(loss)
per share 24.1 (4.7)
----------- -----------
Number of shares (million)
----------------------------
2022 2021
------------- -------------
Weighted average number of ordinary shares 439.3 437.8
Effect of dilutive potential ordinary shares -
Share awards and options 0.9 -
Weighted average number of ordinary shares for
the purpose of diluted profit/(loss) per share 440.2 452.0
------------- -------------
In accordance with IAS 33 "Earnings per Share", the effects of
14.2m antidilutive potential shares have not been included when
calculating dilutive earnings per share for the year ended 31
December 2021, as the Group was loss making.
9. Intangible assets
Intangible assets at 2022 year-end comprise the Group's
exploration and evaluation projects which are pending
determination. Included in the additions is Blocks 125 & 126 in
Vietnam $3.1m (2021: $10.6m), Egypt $1.0m (2021: $3.9m) of which
$0.9m (2021: $0.6m) relates to North Beni Suef, and $0.2m (2021:
$0.7m) for Israel.
During 2022, $0.2m was spent in Israel on geoscience and
geophysical studies (2021: $0.7m). Following completion of the
seismic processing in order to mature prospectivity ahead of a
drilling decision, Capricorn as the operator and along with the
Company and other JV partners, informed the Ministry of Energy of
the JV's intention to relinquish the licences. The bank guarantee
of $2.7m held, as at 31 December 2021, for the Israeli offshore
exploration licenses, was released accordingly. At 31 December
2022, the Group has therefore decided to write off the $0.2m in
Israel as no substantive expenditure has been identified as
indicated in IFRS 6.
At June 2020 and December 2020 an impairment indicator of IFRS 6
was triggered following the Group's decision to defer all
non-essential investment in Vietnam and Egypt at this point. No
substantive expenditure for its exploration areas in Vietnam and
Egypt was either budgeted or planned in the near future.
Exploration costs including costs associated with Blocks 125 &
126 in Vietnam of $17.9m and costs associated with Egypt projects
in the amount of $5.3m were written off in the income statement in
accordance with the Group's accounting policy on oil and gas
exploration and evaluation expenditure.
At 31 December 2021, interpretation of the seismic data in
relation to Blocks 125 and 126 in Vietnam was ongoing and the
carrying value of Egypt exploration and evaluation expenditure was
to be reviewed following completion of the farm out of the Egypt
concessions.
At 31 December 2022, on Block 125, the 3D seismic processing was
complete and the ongoing interpretation of the data resulted in the
mapping of a variety of Prospects in the relatively unexplored deep
water basin. A commitment well was planned for 2023 with an
estimated cost of $15m, but the focus on deep water means that a
drillship is needed and the Company has been unable to source one
for 2023. An application has therefore been submitted for an
extension of the license and the Company now plans to drill a
commitment well in 2024. In Egypt, as part of the planned work
programme for 2023, two commitment wells are expected to be drilled
in the El Fayum Concession. In order to meet a commitment on North
Beni Suef, two exploration wells are expected to be drilled in
calendar year 2023.
Whilst ongoing costs for exploration are therefore forecast and
funds available for future exploration, there is insufficient
certainty of full recovery to justify the reversal of the previous
impairment charges in 2020. The accumulated impairment charges
against exploration and evaluation expenditure at 31 December 2022
stands at $25.6m (2021: $25.4m). This will be kept under review as
the exploration activity continues.
10. Property, plant and equipment
As a result of previously recognised impairment losses, combined
with the ongoing oil price volatility, economic uncertainty leading
to an increase in inflation and discount rates, and movements in 2P
reserves, we have tested each of our oil and gas producing
properties for impairment. The results of these impairment tests
are summarised below. For each producing property, the recoverable
amount has been determined using the value in use method which
constitutes a level 3 valuation within the fair value hierarchy.
The recoverable amount is supported by the fair value derived from
a discounted cash flow valuation of the 2P production profile.
Summary of Impairments - Oil and Gas
Properties 2022
---------- ---------- ---------- ----------
TGT CNV Egypt Total
2022 $ million $ million $ million $ million
---------- ---------- ---------- ----------
Pre-tax impairment reversal 19.7 3.6 3.8 27.1
---------- ---------- ---------- ----------
Deferred tax charge (6.9) (1.4) - (8.3)
---------- ---------- ---------- ----------
Post-tax impairment reversal 12.8 2.2 3.8 18.8
---------- ---------- ---------- ----------
Reconciliation of carrying amount:
(1)
---------- ---------- ---------- ----------
As at 1 Jan 2022 266.0 84.2 49.2 399.4
---------- ---------- ---------- ----------
Additions 7.0 3.2 13.6 23.8
---------- ---------- ---------- ----------
Changes in decommissioning asset (2) (11.1) (2.8) - (13.9)
---------- ---------- ---------- ----------
DD&A (39.2) (11.8) (4.1) (55.1)
---------- ---------- ---------- ----------
Impairment reversal 19.7 3.6 3.8 27.1
---------- ---------- ---------- ----------
As at 31 Dec 2022 242.4 76.4 62.5 381.3
---------- ---------- ---------- ----------
2021
---------- ---------- ---------- ----------
TGT CNV Egypt Total
2021 $ million $ million $ million $ million
---------- ---------- ---------- ----------
Pre-tax impairment reversal 49.1 3.8 1.7 54.6
---------- ---------- ---------- ----------
Deferred tax charge (17.1) (1.4) - (18.5)
---------- ---------- ---------- ----------
Post-tax impairment reversal 32.0 2.4 1.7 36.1
---------- ---------- ---------- ----------
Reconciliation of carrying amount:
(1)
---------- ---------- ---------- ----------
As at 1 Jan 2021 239.3 91.2 104.2 434.7
---------- ---------- ---------- ----------
Additions 11.4 0.3 12.9 24.6
---------- ---------- ---------- ----------
Reclassified as assets held for sale - - (1.4) (1.4)
---------- ---------- ---------- ----------
Changes in decommissioning asset (2) (1.0) (0.9) - (1.9)
---------- ---------- ---------- ----------
DD&A (32.8) (10.2) (8.0) (51.0)
---------- ---------- ---------- ----------
Impairment reversal 49.1 3.8 1.7 54.6
---------- ---------- ---------- ----------
Sub-total 266.0 84.2 109.4 459.6
---------- ---------- ---------- ----------
Reclassified as assets held for sale - - (60.2) (60.2)
---------- ---------- ---------- ----------
As at 31 Dec 2021 266.0 84.2 49.2 399.4
---------- ---------- ---------- ----------
(1) Egypt carrying value reflects 45% share (2021: 100%).
(2) Changes in decommissioning asset for TGT is due to changes
in discount rate and the field abandonment plan, whereas CNV
reflects the change in discount rate only (2021: change in discount
rate only for both TGT and CNV).
Vietnam
The key assumptions to which the fair value measurement is most
sensitive are oil price, discount rate and 2P reserves (2021: oil
price, discount rate and 2P reserves). As at 31 December 2022, the
fair value of the assets are estimated based on a post-tax nominal
discount rate of 13.3% (2021: 11.4%) and a Brent oil price of
$88.3/bbl in 2023, $84.8/bbl in 2024, $79.4/bbl in 2025, $74.5/bbl
in 2026 plus inflation of 2.0% thereafter (2021: an oil price of
$73.9/bbl in 2022, $70.2/bbl in 2023, $67.8/bbl in 2024, $68.0/bbl
in 2025 plus inflation of 2.0% thereafter).
Testing of sensitivity cases indicated that a $5/bbl reduction
in long-term oil price used when determining the value in use
method would result in post-tax impairments charge (compare to new
NBV) of $11.8m on TGT and $3.7m on CNV. A 1% increase in discount
rate would result in post-tax impairments of $4.0m on TGT and $1.0m
on CNV.
We have also run sensitivities utilising the IEA (International
Energy Agency) scenarios described as being consistent with
achieving the COP26 agreement goal to reach net zero by 2050 (the
"Net Zero price scenario"). The nominal Brent prices used in this
scenario were as follows; $88.3/bbl in 2023, $84.8/bbl in 2024,
$79.4/bbl in 2025, $72.7/bbl in 2026, $65.6/bbl in 2027, $58.3/bbl
in 2028, $50.7/bbl in 2029 and $42.7/bbl in 2030. Using these
prices and an 13.3% discount rate would result in additional
post-tax impairments of $13.8m on TGT and $5.0m on CNV.
The impairment tests for TGT and CNV assume that production
ceases in 2029 and 2030 respectively.
Egypt
The key assumptions to which the fair value measurement is most
sensitive are oil price, discount rate, capital spend and 2P
reserves (2021: oil price, discount rate, capital spend and 2P
reserves). As at 31 December 2022, the fair value of the assets are
estimated based on a post-tax nominal discount rate of 15.9% (2021:
14%) and a Brent oil price of $88.3/bbl in 2023, $84.8/bbl in 2024,
$79.4/bbl in 2025, $74.5/bbl in 2026 plus inflation of 2.0%
thereafter (2021: an oil price of $73.9/bbl in 2022, $70.2/bbl in
2023, $67.8/bbl in 2024, $68.0/bbl in 2025 plus inflation of 2.0%
thereafter).
Testing of sensitivity cases indicated that a $5/bbl reduction
in long term oil price used would result in an impairment of $7.8m
(compare to new NBV). A 1% increase in discount rate would result
in an impairment charge of $2.8m. We have also run a sensitivity
using a 15.9% discount rate and the Net Zero price scenario which
would result in an additional impairment of $25.5m.
Other considerations
It is not considered possible to provide meaningful
sensitivities in relation to 2P reserves for any of the Group's oil
and gas producing properties, as the impact of any changes in 2P
reserves on recoverable amount would depend on a variety of
factors, including the timing of changes in production profile and
the consequential effect on the expenditure required to both
develop and extract the reserves.
Other fixed assets comprise office fixtures and fittings and
computer equipment.
11. Hedge transactions
During 2022, Pharos entered into different commodity (swap and
zero cost collar) hedges to protect the Brent component of forecast
oil sales and to ensure future compliance with its obligations
under the reserve based lending facility (RBL) over the producing
assets in Vietnam. Pharos was hedged more than required under the
conditions of the RBL and higher than the Company would normally
commit to in order to support stress testing for going concern and
the working capital test required for the prospectus for the Egypt
farm down. As a result, the majority of hedged production volumes
(61%) were in H1 2022, leading to realised losses of $17.3m out of
total realised losses of $22.5m for the year in order to meet these
requirements.
The commodity hedges run until December 2023 and are settled
monthly. For 2022, 30% of the Group's total production was hedged,
securing a minimum price for the hedged volumes of $67.9/bbl. The
Group's RBL requires the Company to hedge at least 35% of Vietnam
RBL production volumes and the current hedging programme meets this
requirement through to December 2023, leaving 71% of Group
production unhedged as 31 December 2022 (2021: cover was 23% of the
Group's forecast production until December 2022, securing a minimum
price for this hedged volume of $68.2 per barrel).
A summary of hedges outstanding as at 31 December 2022 is
presented below, which are all zero cost collar.
1Q23 2Q23 3Q23 4Q23
---------------------------- ------ ------ ------ ------
Production hedge per
quarter - 000/bbls 180 180 180 45
-------------------------------- ------ ------ ------ ------
Min. Average value of
hedge - $/bbl 65.33 65.33 63.33 63.33
-------------------------------- ------ ------ ------ ------
Max. Average value of
hedge - $/bbl 102.88 102.88 102.23 107.80
-------------------------------- ------ ------ ------ ------
Pharos has designated the swaps and zero cost collars as cash
flow hedges. This means that the effective portion of unrealised
gains or losses on open positions will be reflected in other
comprehensive income. Every month, the realised gain or loss will
be reflected in the revenue line of the income statement. For the
year end 31 December 2022 a loss of $22.5m was realised (2021: loss
of $29.7m). The outstanding unrealised loss on open position as at
31 December 2022 amounts to $0.7m (2021: loss of $4.3m).
The carrying amount of the swaps and zero cost collars is based
on the fair value determined by a financial institution. As all
material inputs are observable, they are categorised within Level 2
in the fair value hierarchy. It is presented in "Trade and other
receivables" or "Trade and other payables" in the consolidated
statement of financial position. The liability position as of
December 2022 was $1.1m (2021: liability position $6.5m).
12. Distribution to Shareholders
The Board have recommended a final dividend of 1.00 pence per
share (equivalent to $5.46m at the average rate of exchange for
2022) subject to approval of the shareholders at the Company's 2023
AGM. This reflects a return to shareholders of at least 10% of
Operating Cash Flow (OCF), consistent with the revised dividend
policy after the Company withdrew dividend payments in 2021 and
2020 due to ongoing uncertainty in the macro environment. The final
dividend will be paid in full on 12 July 2023 in Pounds Sterling to
ordinary shareholders on the register at the close of business on
16 June 2023.
13. Reconciliation of operating profit/(loss) to operating cash
flows
Group Company
----------- ---------- ----------- ----------
2022 2021 2022 2021
$ million $ million $ million $ million
----------- ---------- ----------- ----------
Operating profit/(loss) 100.2 48.3 44.2 (3.6)
Share-based payments 1.3 2.4 1.3 2.4
Depletion, depreciation and
amortisation 55.2 51.4 - -
Impairment reversal (27.9) (42.0) (53.9) (7.9)
----------- ---------- ----------- ----------
Operating cash flows before
movements in working capital 128.8 60.1 (8.4) (9.1)
(Increase)/decrease in inventories (0.9) 0.8 - -
(Increase)/decrease in receivables
(1) (7.7) (7.2) 1.2 0.4
(Decrease)/increase in payables (9.5) (2.2) (1.8) 2.2
----------- ---------- ----------- ----------
Cash generated by (used in)
operations 110.7 51.5 (9.0) (6.5)
Interest received/(paid) 0.1 (0.1) 0.1 -
Other/restructuring expense
outflow (2.7) (0.7) (2.7) (0.6)
Income taxes paid (54.7) (39.9) - -
----------- ---------- ----------- ----------
Net cash from (used in) operating
activities 53.4 10.8 (11.6) (7.1)
----------- ---------- ----------- ----------
(1) Includes $1.5m (2021: $0.1m) increase in risk factor
provision in respect of Egypt trade receivables.
During the year a total of $4.6m (2021: $8.3m) of trade
receivables due from EGPC in Egypt were settled by way of non-cash
offset, out of which $1.0m relates to 3rd Amendment signature bonus
(2021: $nil), $1.1m was set against trade payables (2021: $8.3m),
$2.0m Assignment bonus settled on behalf of the Farm out partner,
IPR, and $0.5m Group's share of NBS Concession assignment
bonus.
14. Disposal of 55% interest in Egypt Concessions
In December 2021, the company classified 55% of the Group's
operated interest in each of our Egyptian Concessions, El Fayum and
North Beni Suef, as Assets classified as held for sale (Net assets
classified as held for sale as 31 December 2021: $53.5m).
An impairment of $10.4m was recognised to bring the value of the
net assets classified as held for sale down to the fair value less
costs to sell calculated as at 31 December 2021.
Following the completion of the farm-out transaction of Egyptian
assets to IPR, the accounting for the assets reflect the
following:
The economic date of the transaction was 1 July 2020, with
completion on 21 March 2022.
Pharos owned and managed the business up to completion. On
completion, an adjustment to compensate for net cash flows since
the economic date has been adjusted for in the level of carry to be
provided by IPR to Pharos.
In the financial statements, for the period post completion,
Pharos 45% share of field costs - capex, opex and G&A - are
accounted for as incurred by Pharos, although all such costs are
paid by IPR and set off against the carry.
All revenues earned are paid direct to Pharos.
The following assets and liabilities were reclassified as held
for sale in relation to the discontinued operation as at 31
December 2021:
2021
$ million
-----------
Intangible assets 2.1
Property, plant and equipment - oil and gas properties
- NBV 61.6
Impairment charge - Assets classified as held for
sale (10.4)
-----------
Property, plant and equipment - oil and gas properties
- after impairment 51.2
Property, plant and equipment - other - NBV 0.4
Inventories 6.3
Trade and other receivables 2.0
Assets classified as held for sale 62.0
-----------
Trade and other payables (8.5)
-----------
Liabilities directly associated with assets classified
as held for sale (8.5)
-----------
Net assets classified as held for sale 53.5
-----------
Disposal of asset held for sale:
2022
$ million
-----------
Intangible assets (2.3)
Property, plant and equipment (54.4)
Inventories (5.9)
Trade and other receivables (2.3)
Trade and other payables 8.3
Disposal of 55% of El Fayum and NBS (56.6)
-----------
Firm consideration received - IPR Cash Receipts 5.0
Other receivable - Carry 36.3
Other receivable - contingent consideration 13.9
Other receivable with IPR 0.5
-----------
Consideration received and to be received 55.7
-----------
Assignment fees payable to EGPC (3.7)
Success fees paid on completion (1.7)
-----------
Loss on disposal (6.3)
-----------
The firm consideration was received in two tranches, $2.0m in
September 2021 and $3.0m on 30 March 2022.
The carry of $36.3m is disproportionate funding contribution
from IPR adjusted for working capital and interim period
adjustments from the effective economic date of 1 July 2020 and
completion date.
The carry decreases every month against the cash calls received
from IPR. The total amount utilised as at 31 December 2022 amounts
to $15.4m, which has been disclosed in "Consideration received on
farm out of Egyptian assets" in the cash flow as part of investing
activities (combined with $3.0m firm consideration received on 30
March 2022). No cash outflow is required until we utilise the whole
amount.
The Group is entitled to contingent consideration depending on
the average Brent Price each year from 2022 to the end of 2025
(with floor and cap at $62/bbl and c.$90/bbl respectively). The
contingent consideration is calculated yearly and is capped at a
maximum total payment of $20.0m. As at 31 December 2022, the
contingent consideration amounts to $13.9m ($5.0m current and $8.9m
non-current). Testing of sensitivity for a $5/bbl reduction in long
term oil price used would result in $1.3m decrease in contingent
consideration to $12.6m.
The loss on disposal has increased by $0.5m from the position
stated as at 30 June 2022 in the Company's interim financial
statements. This is due primarily to a reduction of the amount
classified as the carry element of the consideration from $37.0m to
$36.3m following a change in the best estimate of the adjustment
relating to the interim period between the economic date of 1 July
2020 and the completion date. The reduction in the carry is
partially offset by an increase in the amount classified as
contingent consideration from $13.6m to $13.9m, reflecting the
Group's entitlement to the full $5 million of the first tranche of
the contingent consideration payable in respect of average Brent
price during 2022.
As at 31 December 2022, $3.7m relates to the assignment fee for
the sale of 55% of the Group's operated interest in each of our
Egyptian Concessions, El Fayum and North Beni Suef, to IPR. $0.5m
Group's share of NBS Concession assignment bonus was settled
against Trade Receivables. Out of the remaining $3.2m, $2.3m is
booked as current other payable and $0.9m as non-current other
payable.
The final consideration is still being finalised between IPR and
Pharos. The financial exposure from finalising the consideration to
Pharos, reflecting the remaining amounts still under discussion, is
considered immaterial to the financial statements.
15. Preliminary results announced
Copies of the announcement will be available to download from
www.pharos.energy. The Annual Report and Accounts, together with
notice of the 2023 AGM, will be posted to shareholders in due
course.
Non-IFRS measures
The Group uses certain measures of performance that are not
specifically defined under IFRS or other generally accepted
accounting principles. These non-IFRS measures include cash
operating costs per barrel, DD&A per barrel, gearing and
operating cash per share.
For the RBL covenant compliance, three Non-IFRS measures are
included: Net debt, EBITDAX and Net debt/EBITDAX.
Cash-operating costs per barrel
Cash operating costs are defined as cost of sales less DD&A,
production based taxes, movement in inventories and certain other
immaterial cost of sales.
Cash operating costs for the period is then divided by barrels
of oil equivalent produced. This is a useful indicator of cash
operating costs incurred to produce oil and gas from the Group's
producing assets.
2022 2021
$ million $ million
---------- ----------
Cost of sales 116.8 114.6
Less:
Depreciation, depletion and amortisation (55.1) (51.0)
Production based taxes (14.7) (10.1)
Export duty (3.2) -
Inventories 1.8 0.1
Trade receivable risk factor provision (1.5) -
Other cost of sales (1.3) (1.6)
Cash operating costs 42.8 52.0
---------- ----------
Production (BOEPD) 7,166 8,878
---------- ----------
Cash operating cost
per BOE ($) 16.36 16.05
---------- ----------
Cash-operating costs per barrel by Segment (2022)
Vietnam Egypt Total
$ million $ million $ million
----------- ---------- --- ----------
Cost of sales 99.6 17.2 116.8
Less:
Depreciation, depletion and
amortisation (51.0) (4.1) (55.1)
Production based taxes (14.5) (0.2) (14.7)
Export duty (3.2) - (3.2)
Inventories 1.6 0.2 1.8
Trade receivable risk factor
provision - (1.5) (1.5)
Other cost of sales (0.8) (0.5) (1.3)
Cash operating costs 31.7 11.1 42.8
----------- ---------- --- ----------
Production (BOEPD) 5,418 1,748 7,166
----------- ---------- --- ----------
Cash operating cost
per BOE ($) 16.03 17.40 16.36
----------- ---------- --- ----------
Depreciation, depletion and amortisation costs per barrel
DD&A per barrel is calculated as net book value of oil and
gas assets in production, together with estimated future
development costs over the remaining 2P reserves. This is a useful
indicator of ongoing rates of depreciation and amortisation of the
Group's producing assets.
2022 2021
$ million $ million
---------- ----------
Depreciation, depletion and amortisation (55.1) (51.0)
---------- ----------
Production (BOEPD) 7,166 8,878
---------- ----------
DD&A per BOE ($) 21.07 15.74
---------- ----------
DD&A per barrel by Segment (2022)
Vietnam Egypt Total
$ million $ million $ million
---------- ---------- ------------
Depreciation, depletion and amortisation (51.0) (4.1) (55.1)
---------- ---------- ----------
Production (BOEPD) 5,418 1,748 7,166
---------- ---------- ------------
DD&A per BOE ($) 25.79 6.43 21.07
---------- ---------- ------------
Net Debt
Net debt comprises interest-bearing bank loans, less cash and
cash equivalents.
2022 2021
$ million $ million
----------------- ------------
Cash and cash equivalents 45.3 27.1
Borrowings (1) (74.2) (84.6)
----------------- ------------
Net Debt (28.9) (57.5)
----------------- ------------
(1) Excludes unamortised capitalised set up costs
EBITDAX
EBITDAX is earnings from continuing activities before interest,
tax, depreciation, amortisation, impairment of PP&E and
intangibles, exploration expenditure and other/restructuring
expense items in the current year.
2022 2021
$ million $ million
------------------- ---------------------
Operating profit/(loss) 100.2 48.3
Depreciation, depletion and amortisation 55.2 51.4
Impairment reversal (27.9) (42.0)
EBITDAX 127.5 57.7
------------------- ---------------------
Net debt/EBITDAX
Net Debt/EBITDAX ratio expresses how many years it would take to
repay the debt, if net debt and EBITDAX stay constant.
2022 2021
$ million $ million
------------------- ----------
Net Debt (28.9) (57.5)
EBITDAX 127.5 57.7
Net Debt/EBITDAX (0.23) 1.00
------------------- ----------
Gearing
Debt to equity ratio is calculated by dividing interest-bearing
bank loans by stockholder's equity. The debt to equity ratio
expresses the relationship between external equity (liabilities)
and internal equity (stockholder equity)
2022 2021
$ million $ million
------------------- ----------
Total Debt (1) 74.2 84.6
Total Equity 330.6 304.4
Debt to Equity 0.22 0.28
------------------- ----------
(1) Excludes unamortised capitalised set up costs
Operating cash per share
Operating cash per share is calculated by dividing net cash from
(used in) continuing operations by number of shares in the
year.
2022 2021
$ million $ million
-------------------- ---------------------
Net cash from operating activities 53.4 10.8
Weighted number of shares in the year 439,253,641 437,512,648
Operating cash per share 0.12 0.02
-------------------- ---------------------
Glossary of Terms
AGM
Annual general meeting
bbl
Barrel
boe or BOE
Barrels of oil equivalent
boepd or BOEPD
Barrels of oil equivalent per day
bopd or BOPD
Barrels of oil per day
cash
Cash, cash equivalent and liquid investments
capex
Capital expenditure
CEO
Chief Executive Officer
CNV
Ca Ngu Vang field located in Block 9-2, Vietnam
Company or Pharos
Pharos Energy plc
Contingent Resources or contingent resources
Those quantities of petroleum to be potentially recoverable from
known accumulations by application of development projects but
which are not currently considered to be commercially recoverable
due to one or more contingencies
Contractor
The party or parties identified as being, or forming part of,
the "CONTRACTOR" as defined in the El Fayum Concession or, as the
case may be, the North Beni Suef Concession
DD&A
Depreciation, depletion and amortisation
DP Semi-Submersible
Dynamic positioning semi-submersible drilling rig
E&P
Exploration & Production
EBITDAX
Earnings before interest, tax, DD&A, impairment of PP&E
and intangibles, exploration expenditure and other/restructuring
items in the current year
EGP
Egyptian Pounds, the lawful currency of the Arab Republic of
Egypt
EGPC
Egyptian General Petroleum Corporation, an Egyptian state oil
and gas company and the industry regulator
El Fayum or the El Fayum Concession
The concession agreement for petroleum exploration and
exploitation entered into on 15 July 2004 between the Arab Republic
of Egypt, EGPC and Pharos El Fayum in respect of the El Fayum area,
Western Desert, as amended from time to time
Financial Statements
The preliminary financial statements of the Company and the
Group for the year ended 31 December 2022
FPSO
Floating, production, storage and offloading Vessel
G&A
General and administration
GDP
Gross domestic product
GHG
Greenhouse gas
Group
Pharos and its direct and indirect subsidiary undertakings
H1
The first half of a calendar year
H2
The second half of a calendar year
HLJOC
Hoang Long Joint Operating Company, the operator of the TGT
field on Block 16-1, Vietnam
HVJOC
Hoan Vu Joint Operating Company, the operator of the CNV field
on Block 9-2, Vietnam
IFRS
International Financial Reporting Standards
IMF
The International Monetary Fund
IPR or IPR Energy Group
The IPR Energy group of companies, including IPR Lake Qarun and
IPR Energy AG, or such of them as the context may require
IPR Lake Qarun
IPR Lake Qarun Petroleum Co, an exempted company with limited
liability organised and existing under the laws of the Cayman
Islands (registration number 379306), a wholly owned subsidiary of
IPR Energy AG
JOC
joint operating company
JV
joint venture
km
kilometre
km(2)
square kilometre
LTI
Lost Time Injury
LTIF
Lost Time Injury Frequency
LTIP
Long Term Incentive Plan
m
million (where used to describe a monetary amount)
McDaniel
McDaniel & Associates Consultants Ltd
mmboe
million barrels of oil equivalent
NAV
Net asset value
NBE
The National Bank of Egypt, the largest Egyptian commercial bank
and owned by the state of Egypt
NBS, North Beni Suef or the North Beni Suef Concession
The concession agreement for petroleum exploration and
exploitation entered into on 24 December 2019 between the Arab
Republic of Egypt, EGPC and Pharos El Fayum in respect of the North
Beni Suef area, Nile Valley
OCF
Operating cash flow
opex
Operational expenditure
PEF
Pharos El Fayum, a wholly owned subsidiary of the Company
holding the Group's participating interest in El Fayum and North
Beni Suef
Petrosilah
An Egyptian joint stock company held 50/50 between EGPC and the
Contractor parties (being IPR Lake Qarun and PEF following
completion of the farm-down of the El Fayum Concession)
Petrovietnam
Vietnam Oil and Gas Group, the Vietnamese state-owned integrated
oil and gas company
PP&E
Property, plant and equipment
Prospect or prospect
An identified trap that may contain hydrocarbons. A potential
hydrocarbon accumulation may be described as a lead or prospect
depending on the degree of certainty in that accumulation. A
prospect generally is mature enough to be considered for
drilling
PSC
Production sharing contract or production sharing agreement
Reserves or reserves
Reserves are those quantities of petroleum anticipated to be
commercially recoverable by application of development projects to
known accumulations from a given date forward under defined
conditions. Reserves must further satisfy four criteria: they must
be discovered, recoverable, commercial and remaining based on the
development projects applied
RBL
Reserve-based lending facility
RISC
RISC Advisory Pty Ltd
TGT
Te Giac Trang field located in Block 16-1, Vietnam
TLJOC
Thang Long Joint Operating Company, the operator of Block
15-2/01, Vietnam , with which the Group's shares access to the FPSO
used for TGT production
UK
United Kingdom
USD or US dollars
United States dollars, the lawful currency of the United States
of America
$
United States Dollar
GBP
UK Pound Sterling
1C
Low estimate scenario of Contingent Resources
1P
Equivalent to proved Reserves; denotes low estimate scenario of
Reserves
2C or 2C Contingent Resources
Best estimate scenario of Contingent Resources
2P Reserves or 2P Commercial Reserves
Equivalent to the sum of proved plus probable Reserves; denotes
best estimate scenario of Reserves
3C
High estimate scenario of Contingent Resources
3P
Equivalent to the sum of proved, probable and possible Reserves;
denotes high estimate scenario of Reserves
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END
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