TIDMPHAR
RNS Number : 9459E
Pharos Energy PLC
16 March 2022
Pharos Energy plc
("Pharos" or the "Company" or, together with its subsidiaries,
the "Group")
2021 Preliminary Results
Pharos Energy plc, an independent oil and gas exploration and
production company, announces its preliminary results for the year
ended 31 December 2021. A conference call will take place a t 0900
G MT today.
Jann Brown, Managing Director and Chief Executive Officer
Designate, commented:
"It is truly an exciting time to take over the reins at Pharos.
The completion of the deal with IPR, expected imminently, is a key
step in reshaping the portfolio and 2022 will see investments made
in both Vietnam and Egypt to deliver growth, value and cash flow.
The key focus for 2022 is cash generation, through careful cost
control, a rapid payback programme of drilling in Vietnam and in
Egypt through our carry, which covers all but our own moderate
corporate costs."
"For the first time in some years, we have capital to allocate
to an exciting work programmes in 2022, forming a clear roadmap to
cash generation and value creation in the year ahead."
2021 Operational Highlights
-- Total Group working interest 2021 production 8,878 boepd net
(2020: 11,373 boepd), in line with production guidance:
- Egypt production 3,318 bopd (2020: 5,270 bopd)
- Vietnam production 5,560 boepd net (2020: 6,103 boepd)
-- In Egypt:
- Return to drilling with Batran-1X exploration commitment well
and three-well development drilling programme
- El Fayum Phase 1B waterflood programme commenced with one
workover rig, with a second workover rig dedicated to the
maintenance programme
- Conditional agreements for the farm-down and sale of a 55%
working interest and operatorship in each of the Egyptian El Fayum
and North Beni Suef Concessions to IPR Lake Qarun Petroleum Co.
("IPR")
-- In Vietnam:
- Successful completion of Phase 1 of TGT four-well development
drilling campaign, ahead of schedule and below budget
- HLJOC management committee approval of two additional TGT
wells and 13 well interventions in November 2021
- Completion of 3D seismic acquisition programme on Block 125,
with seismic processing underway and final results expected
mid-2022
- Government approval for a 2-year extension of the initial
exploration phase under the Block 125 & 126 Production Sharing
Contract ("PSC")
2021 Financial Highlights
-- Group revenue of $163.8m* (1) (2020: $118.3m* (1) )
-- Cash generated from operations $51.5m (2020: $85.5m)
-- Cash operating costs of $16.05/bbl(2) (2020: $11.60/bbl(2) )
-- Cash balances as at 31 December 2021 of $27.1m (2020: $24.6m)
-- Net Debt as at 31 December 2021 of $57.5m (2,3) (2020: Net Debt $32.6m (2) )
-- Loss for the year of $4.7m (2020: loss $215.8m), including
non-cash net impairment reversal after tax of $23.5m (2020:
impairment charge after tax of $198.1m)
-- Net Debt to EBITDAX of 1.00x (2020: 0.48x)(2)
* Egyptian revenues are stated post government take including
corporate taxes
(1) Stated prior to realised hedging loss of $29.7m (2020: gain
of $23.7m)
(2) See Non-IFRS measures on page 35
(3) Includes RBL and National Bank of Egypt working capital
drawdown
2021 Corporate Highlights
-- Completion of equity placing, subscription and retail
offering in January 2021 which raised gross proceeds of
approximately $11.7m
-- Refinancing of the Group's RBL facility in July 2021,
providing additional liquidity through access to a committed $100m
with a further $50m available on an uncommitted "accordion" basis
and extending the tenor of the facility by 22 months
-- Signature of agreements in September 2021 for the farm-down
and sale of a 55% working interest and operatorship in the El Fayum
and North Beni Suef Concessions in Egypt to IPR, with Pharos
shareholder approval secured in December 2021
-- Reduction in salary of 50% from 1 April 2021 volunteered by
all three Executive Directors in office on that date
-- The Executive Directors also voluntarily reduce their bonus
entitlement for 2021 by 20% from 72.5% to 58%
-- Appointment of Sue Rivett to the Board as Chief Financial
Officer ("CFO") effective 1 July 2021
-- London office reorganisation and c.50% reduction in headcount completed
2022 Highlights and Outlook
-- Signature of the Third Amendment to the El Fayum Concession
Agreement, with retroactive application of the improved fiscal
terms from November 2020 and a three and a half year extension to
the exploration period
-- Modest hedging programme to capture the higher oil price environment
-- Phase Two of Task Force on Climate-related Disclosure
("TCFD") project completed in Q1 2022, with ongoing work on future
TCFD alignment
-- Appointment of Jann Brown as Chief Executive Officer ("CEO")
on completion of the transaction with IPR
-- Additional directorate changes upon completion of the
transaction with IPR and at the 2022 AGM, resulting in a reduction
in the size of the Board from nine Directors to six, with a much
lower cost base
-- In Egypt
- Pharos and EGPC have finalised all necessary documents to be
presented to the Minister of Petroleum and Natural Resources to
approve the transaction with IPR and this approval is expected
shortly
- The three-well drilling programme, which commenced in November 2021, is ongoing
- Commencement of the main El Fayum multi-year and multi-well
development programme in Q2 2022
- Production forecast for 2022 will be evaluated following
completion of the farm-down to IPR and transfer of operatorship.
Guidance will be given at the AGM
-- In Vietnam
- Vietnam 2022 production guidance : 5,000 - 6,000 boepd
- Drilling of two development wells in TGT and one in CNV to commence Q3 2022
- Processing of 3D seismic data on Block 125 ongoing
Enquiries
Pharos Energy plc Tel: 020 7747 2000
Jann Brown, Chief Executive Officer Designate
Sue Rivett, Chief Financial Officer
Camarco Tel: 020 3757 4980
Billy Clegg | Owen Roberts | Monique Perks | Rebecca
Waterworth
Notes to editors
Pharos Energy plc is an independent oil and gas exploration and
production 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, Vietnam and Israel. In Egypt, until completion of the
farm-out to IPR Energy announced on 15 September 2021 (the
"Farm-out Transaction"), Pharos holds a 100% working interest in
the El Fayum oil Concession in the Western Desert. The Concession
produces from 10 fields and is located 80 km southwest of Cairo. It
is operated by Petrosilah, a 50/50 JV between Pharos and the
Egyptian General Petroleum Corporation (EGPC). Similarly, until
completion of the Farm-Out Transaction occurs, Pharos is also an
operator with a 100% working interest in the North Beni Suef (NBS)
Concession, which is located immediately south of the El Fayum
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 (CVN) 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. In Israel, Pharos together
with Capricorn Energy PLC (formerly known as Cairn Energy PLC) and
Israel's Ratio Oil Exploration, have eight licences offshore
Israel. Each party has an equal working interest and Capricorn
Energy is the operator.
Chair's Statement
Rebalanced and focused on values
I am pleased to report that Pharos has successfully navigated
another challenging year in 2021 whilst continuing to make the
improvements necessary to rebalance our cost base, our capital
structure and our assets. We start 2022 with a clear roadmap of how
the company can drive value for all our stakeholders and we have
the right team in place to deliver that.
The backdrop of the global pandemic persisted throughout 2021
and the ongoing climate of uncertainty remained the dominant
challenge in planning, forecasting and managing capital. After the
swift and decisive actions taken in 2020 to reduce costs and
preserve liquidity, 2021 saw us take further vital steps to
strengthen the capital structure of the business, which had been
severely impacted by the loss of revenues as a result of the oil
price crash. The $11.7 million equity placing, subscription and
retail offering, completed in January 2021, was the first capital
raised from the market since 1997 and the support we received is a
testament to the strength of our existing shareholder base and the
attraction of the company to new investors. I welcome these new
investors and thank all our investors for their support. The
refinancing of our RBL over the assets in Vietnam, completed in
July 2021, provided additional liquidity while maintaining our
leverage at a comfortable level. The approval of improved fiscal
terms in Egypt reset the economics for the El Fayum Concession,
bringing down the breakeven price and improving the overall
returns. The farm-down of our Egyptian assets, a process that
started in 2020, achieved a key milestone with the signature of
conditional agreements with IPR in September. The transaction
with IPR is a key step in the realignment of our asset base to
match the levels of funding available to generate cash flow and
value. We now have a clear path to cash generation and value
creation in Vietnam, where our programme is self-funded, and in
Egypt where we will be carried through the next phase of investment
by IPR.
As part of our reshaping for the future we have driven down
costs and created a new, leaner organisational structure in the UK
and these efforts will continue in Egypt in 2022. This positions us
well to thrive in a stronger oil price environment.
Board Changes
We have long recognised that our board would need to be reshaped
following the farm-down of our assets in Egypt to IPR and the
associated transfer of operatorship. We announced the proposed
changes in January of this year and Ed Story and Mike Watts will
step down from the board once the farm-down transaction completed.
Ed will remain as President of the Vietnam business, while Mike
will be available to advise the Board during his notice period of
one year. I would like to take this opportunity to thank Ed for his
considerable contribution to Pharos over many years. We are
delighted that he will stay with us to help the management of our
relationships and activity in Vietnam. I would also like to thank
Mike for his long-term dedication to the Company and for his
important contributions during that time. Our Senior Non-Executive
Director and Deputy Chair, Rob Gray, will also step down in May of
this year at the 2022 AGM and again we thank him for his long and
valued service.
The result of these changes will be to reduce the size of the
Board from nine Directors to six, commensurate with the scale of
the business, and we have all of the skills and experience required
to provide the necessary governance and oversight of a Premium
Listed Company. Pharos' commitment to inclusion and diversity
remains strong. Following the board changes described above, both
of our executive directors will be female, with a total of four of
the six directors being women, representing two thirds of the
Board.
I am delighted Jann will be the CEO of Pharos and I look forward
to working with her, Sue and the rest of my Board colleagues into
this next phase.
Sustainability
Sustainability is an increasing focus for our entire industry.
We recognise that oil and gas will continue to play an essential
role in the provision of energy security and 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 amidst the wider energy
transition. We stand ready to play our part in this transition and
we can do that by providing transparent and comparable
sustainability disclosures, embedding sustainability considerations
in the way we operate and identifying where changes in our field
practices could make a difference in our efforts to reduce our
carbon footprint.
We have also continued to participate in various climate
disclosures. Over the past four years, we have participated in the
CDP Climate Change Questionnaire and have maintained our score (C),
which is also the industry average. 2021 also marks the first year
that the Company submitted their response to the CDP Water Security
Questionnaire, which was completed at a basic level in 2021 and we
plan to improve our level of transparency on water usage and
protection by completing the full version in 2022. More recently,
we commenced Phase 2 of the project to bring our disclosures in
line with the requirements of the Task Force on Climate-related
Financial Disclosures ("TCFD") in accordance with LR 9.8.6.
Over the years, Pharos has embedded sustainability
considerations throughout our operations. We set up an ESG
Committee at Board level and an ESG Working Group to operationalise
our approach. Climate change is now, following TCFD guidance,
recognised as a principal risk for the Company and we engage our
stakeholders regularly on all aspects of environmental, social and
economic impacts. In 2021, the Remuneration Committee has increased
the level of management incentives which attach to improvements in
our sustainability performance in order to further encourage action
on this agenda.
Following the COP26 summit in Glasgow in November 2021, we
recognise and understand the growing need to accelerate business
action on climate change. The Board welcomed the outcomes of the
Glasgow Climate Pact and is now focused on reviewing what a
possible pathway towards Net Zero entails. This will not be
straightforward, for Pharos and for the wider industry, with a lot
of solutions being currently tried and tested. But we commit to
being transparent in what can and what cannot be delivered and to
keeping stakeholders updated on the progress. During the net zero
transition, we want to ensure we do not lose sight of the role our
energy plays in driving economic development of those countries
where it is produced.
Purpose and organisation
Our purpose has been expanded to include our commitment to
sustainability; to provide the energy to support the economic
development and prosperity of the countries, communities and
families wherever we work, in line with recognised socially and
environmentally responsible practices .
Our organisation has proved itself to be resilient beyond
expectations this year. We have had difficult decisions to make on
reducing our staffing levels in the UK as part of our efforts to
manage costs. We have lost many talented colleagues and 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 challenges
of delivering what has been needed and I have every confidence that
they will continue to do so.
The culture of the workforce is strong and is built on openness,
safety and care, trust and respect for each other. Our workforce in
the UK has indicated a clear preference for retaining flexibility
in our way of working and, throughout the period of mandatory
remote working, we have built well-established channels of
communication and ways of working which can accommodate these
preferences with minimal disruption and no adverse impact on
delivery and efficiency.
Outlook
Despite the turmoil we have all experienced in the global
macro-economic environment, our strategy to deliver long-term,
sustainable value for all our stakeholders remains unchanged. We
have capital to allocate to exciting work programmes in 2022 and
our commitment to returning cash to shareholders remains a core
element of our overall allocation framework.
It is with great sadness that we note the terrible situation
that is ongoing in Ukraine. Alongside the humanitarian issues,
there are increased business risks due to the heightened volatility
in commodity price and impact on inflation. We have no direct
business in the region but we are carrying out due diligence checks
and reviewing the supply chain implications in all parts of the
business. No immediate impact has been identified but we will
continue to keep this under close review and will devise mitigating
actions if needed.
In Vietnam our status as a major investor in country plus our
track record of managing operations stand us in good stead to
deliver the next phase of value from our existing producing fields.
In Egypt, we have a period of collecting revenues with all costs
covered by the carry provided by IPR, our new partner. IPR has
proven itself to be a technically proficient, effective and
low-cost operator and are well capitalised to fund the right work
programme on both Concessions in Egypt to maximise long-term growth
and cash flow. Their long-standing in-country presence and
relationships with the Egyptian government and regulatory
authorities will support the expansion of operational activity
needed to develop the resource base. The Board firmly believes that
IPR is the right partner for Pharos in Egypt, and we look forward
to working with them in 2022 and beyond.
Thanks to the effort and hard work of all of our colleagues, the
businesses is now in significantly better shape, with funding in
place to make the investments needed to deliver value from the
assets already in the portfolio. 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.
We enter 2022 with a more confident outlook. Pharos has a unique
combination of complementary assets, a talented and diverse
workforce and capital discipline in its DNA. Most importantly, it
has a clear roadmap to cash generation and value creation for the
coming year.
John Martin
Chair
Incoming Chief Executive Officer's Statement
2021 was a critical year for Pharos and several key steps were
taken which provide the foundations for the exciting programmes,
focused on growth, cash flow generation and value, in 2022 and
beyond.
- In January, we had strong support for an equity placing,
subscription and retail offer, raising $11.7m in gross proceeds,
with net proceeds invested in the El Fayum waterflood programme to
support production levels.
- In March, we announced a reduction of our head office
headcount of c.50%, significantly reducing our ongoing annual
G&A cost. Many talented colleagues left the Company in this
reorganisation and it is a testament to the team who have stayed
with us that they have continued to deliver.
- In March we announced that we had reached agreement with EGPC,
the industry regulator and state oil company in Egypt, to various
amendments to the El Fayum Concession (known collectively as "The
Third Amendment") the most important effect of which was an
improvement in the fiscal terms backdated to November 2020. The
improved terms were subjected to parliamentary and presidential
approval, which were obtained in January 2022. As a result of this
Third Amendment, Contractor share of revenues increased by 20%,
from c.42% to c50% whilst in full cost recovery mode. Signature of
the Third Amendment was a key Condition Precedent for the transfer
of a 55% participating interest (and operatorship) in the El Fayum
and North Beni Suef Concessions to IPR.
- In July, we completed the refinancing of our Reserve Based
Lending Facility ("RBL") which provided access to a committed $100m
with a further $50m available on an uncommitted "accordion" basis
and has a four-year term that matures in July 2025. The revised RBL
facility extends the tenor of the facility by 22 months, rephases
the repayment schedule and has provided additional liquidity
without taking gearing to unacceptable levels.
- In September, we announced the signature of agreements for the
farm-down to IPR to of a 55% working interest in, and operatorship
of, both of our concessions in Egypt, full details of which
transaction are set out in the Financial Review. Pharos and EGPC
have finalised all necessary documents to be presented to the
Minister of Petroleum and Natural Resources to approve the
transaction with IPR and this approval is expected shortly. The IPR
Energy group has been present in Egypt for 40 years, currently has
eight concessions pre-acquisition, five of which are operated, and
has achieved significant growth in net production. We look forward
to working with them to deliver the full potential of these
fields.
These steps, alongside the operational activity set out below,
have reset the Group's potential. That potential was already there
in the portfolio, but we now have the access to funding to exploit
these to grow cash flow and increase shareholder value. We enter
2022 with a refreshed portfolio, cost base, and access to
capital.
Consistent operational delivery amidst ongoing global
uncertainties
In Vietnam, the Group had a busy operational year. Most notable
was the commencement of the TGT well intervention and development
drilling programme in July 2021, following the approval of the
updated FFDP and the two year extension on both the TGT and CNV
licences which was announced in 2020. Phase 1 of the campaign was
successfully completed in November 2021, ahead of schedule and
c.$20 million below the JV gross budget. In 2021, the crude
produced from the fields in Vietnam commanded a premium to Brent of
just under $2/bbl and the payback period for the wells drilled is
estimated at below 12 months, making investment in these fields an
attractive proposition.
P roduction for 2021 from the TGT and CNV fields net to the
Group's working interest averaged 5,560 boepd, in line with
guidance, and guidance for 2022 is set at 5,000 to 6,000 boepd.
In July 2021, the Company announced the completion of its 3D
seismic acquisition programme on the western part of Block 125 in
the Phu Khanh Basin, offshore Vietnam. The seismic processing work
is ongoing, with the final processed results expected in mid-2022.
In September 2021, Pharos received approval for a two-year
extension of the initial exploration phase under the Block 125
& 126 PSC, which now runs until November 2023. There is a
commitment to drill one well on these Blocks within the initial
exploration phase and, following completion of the seismic
processing, we will look to bring in an additional partner
pre-drill.
In Egypt, after an operational hiatus in 2020, Phase 1B of the
waterflood programme on El Fayum commenced, supported by the net
proceeds of the equity placing, subscription and retail offer
completed in January 2021. A three-well development drilling
programme was started in November 2021 to provide reservoir
pressure support and maintain production ahead of the multi-year,
multi-well development programme planned following completion of
the transaction with IPR. Pharos will be carried through the first
part of this programme by IPR for its retained 45% working interest
in El Fayum.
In June 2021, Pharos announced the modest discovery on the
Batran-1X exploration commitment well, which reconfirmed the
potential for additional oil on the El Fayum concession.
The Board believes that 2021 was a turning point year for
Pharos, with key building blocks now in place to move forward into
exciting programmes in both Vietnam and Egypt.
Sustainability
Sustainability has been a challenge for our industry for many
years and the focus on our activities on this front is increasing,
and rightly so. Alongside our statutory obligations in the United
Kingdom (where we are listed) and Egypt, Israel and Vietnam (where
we operate), we recognise that the expectations of all stakeholders
are growing in this respect. At Pharos, we have been diligently
preparing to ensure that our disclosures are in line with the Task
Force on Climate-related Financial Disclosures ("TCFD")
recommendations and can report that we are on track to do so,
having completed Phase Two of our alignment project with TCFD's
reporting requirements. We also continue to meet our obligations
under the Modern Slavery Act and anti-bribery legislation. As part
of local agreements, we are focused on meeting legal environmental,
social and economic obligations: that is why we provide $500,000
every year for local capability training in Vietnam and Egypt. I am
proud that we continue to achieve a zero on our Lost Time
indicators. In 2021, we paid $198.2m in taxes and royalties to host
governments, including their share of production entitlements. With
100% of production sold domestically in 2021, this has made a
valuable contribution to the host countries' socio-economic
development, energy security and access to energy.
But we go beyond what's legally required, noting the growing
expectations of all our stakeholders. As we work predominantly
through Joint Operating Companies ("JOCs") we work collaboratively
with our partners to identify what else we can do. This extends to
all our community initiatives, where our financial contribution
amounted to $265,000 in 2021 via HLHVJOC Charitable Donation
Programme. We are investigating opportunities to reduce our carbon
footprint by adopting different methods and processes to power our
operations and other carbon reduction technologies in the longer
term and will provide updates on our progress. We will not make
commitments or set targets which are vague or which rely on new
technologies or those being developed in the future, and which do
not carry the support of our partners.
Outlook - Reaping our rewards in a new phase of growth
Over the past five years, we have built a portfolio in Asia MENA
with a combination of assets which offer resilience in difficult
times, strong cash returns in better times plus valuable growth
potential when investment capital is available.
In Vietnam, the economics are attractive on all fronts - premium
commodity pricing, a low LOF Breakeven price, attractive netbacks
and rapid payback periods on new development wells - with all
planned activities funded from cash flows generated. Following the
four wells drilled on TGT in 2021, two further TGT wells are
planned for 2022 plus one on CNV. The JOC is now progressing work
on submitting licence extension requests for both TGT & CNV,
with a Revised Full Field Development Plan ("FFDP") for both fields
to be submitted by Q4 2022. This would take the licence terms out
to 2031 (TGT) and 2032 (CNV) and would add two years of reserves to
the production profiles and economics for these fields.
In Egypt, upon completion of the transaction with IPR and
transfer of operatorship which is expected imminently], we will
enter a new phase, and will benefit from IPR's experience as an
Operator plus the carry of our retained 45% working interest
through the first part of the multi-year and multi-well development
programme. With the field economics enhanced by the signing of the
Third Amendment and the Group's own economics further improved by
the carry, we consider that Egypt is now in an excellent position
to deliver on its potential.
I would like to pay tribute to my colleagues leaving the board
at this time. To Ed Story, as he ends his 25 year leadership of the
company, having taken it through many different territories and
phases, always with a focus on shareholder returns. He will be a
key part of the team in Vietnam to deliver on his long held view of
the potential there. Mike's association with Pharos has also been
formative and instrumental over the long term. Finally, Rob Gray
will step down in May from his roles as both Deputy Chair and as
Senior Non-Executive Director. All three have played an important
role in putting the company where it is today and I thank each of
them for their own unique contributions.
I would also like to thank our shareholders and wider
stakeholders for their ongoing support.
Last but not least, I would also like to express my gratitude
towards my colleagues for their efforts, continued hard work and
commitment as we have navigated through challenges and
uncertainties to build a business with a return to growth.
Jann Brown
Chief Executive Officer Designate
Review of Operations
Egypt
El Fayum Production
Production for 2021 from the El Fayum Concession averaged 3,318
bopd (2020: 5,270 bopd). This is in line with the 2021 production
guidance given in our Interim Results statement on 15 September
2021.
El Fayum Development and Operations
El Fayum Phase 1B waterflood programme commenced in H1 2021 with
one workover rig, with a second workover rig contracted in August
dedicated to the maintenance programme. Plans were put in place to
accelerate production enhancement in the second half of the year,
which included the arrival of a second workover rig and the
commencement of a three-well development drilling programme in
November 2021. This was to help provide reservoir pressure support
and maintain production ahead of the main multi-year and multi-well
development programme to be implemented following completion of the
transaction with IPR.
Petrosilah, the El Fayum joint operating company, has tendered
for a Drilling Rig and a candidate has been identified for a Q2
commencement of operations. The results of the recently drilled
wells have been encouraging and confirm our latest subsurface
modelling work.
El Fayum Exploration
The Batran-1X commitment well was drilled in May 2021 inside the
Tersa Development Lease. The well started the first phase of a long
production test through Early Production Facility (EPF) in November
by testing the single Upper Bahariya UB-1 zone to evaluate
reservoir continuity and pressure support. During the initial test
the well produced between 90 and 25 bopd and the rate of the well
continued to drop during the test. There remains the option to test
further reservoir zones at a later date following completion of the
farm-down to IPR.
El Fayum Commercial
On 20 January 2022, the Company announced that the Third
Amendment to the El Fayum Concession Agreement had been signed by
His Excellency Eng. Tarek El Molla (Minister of Petroleum &
Mineral Resources of the Arab Republic of Egypt), EGPC and the
Company . The agreement, and the improved fiscal terms, are
retroactively effective from November 2020.
While in full cost recovery mode, Contractor's share of revenue
increases from c.42% to c.50% as from November 2020 (corresponding
to additional net revenues to Contractor of c.$7 million to the
date of signature) significantly lowering the development project
break-even. The new arrangements will strongly encourage new
exploration and development investments, aimed at maintaining and
increasing production rates and optimising resources, to the mutual
benefit of Egypt and the Contractor parties.
The Third Amendment also grants Contractor a
three-and-a-half-year extension to the exploration term of the El
Fayum Concession Agreement, with an additional obligation on
Contractor to drill two exploration wells and acquire a 3D seismic
survey in the northern area of the concession.
North Beni Suef (NBS)
Interpretation of the large pre-existing 3D seismic survey on
the NBS Concession continues with several low risk drillable
prospects already identified. Following completion of the farm-down
to IPR, the partners are planning to drill two low-risk low-cost
commitment wells by end of 2022.
Farm-down transaction and transfer of operatorship
Business integration between IPR, Pharos and local JV operator
Petrosilah started as soon as the SPA was signed in September 2021.
A Transition Taskforce (TTF) team has been established to promote
the smooth transition of operatorship to IPR, transfer the
knowledge of Pharos to IPR and set up collaborative partnership
environment.
2022 Work Programme
The three-well drilling programme, which commenced in November
2021, is ongoing. Two wells have been completed and are on
production, with the third one due to spud soon.
Following award of the drilling rig contract by Petrosilah on
behalf of the Joint Venture and upon completion of the transaction
with IPR and transfer of operatorship, the Contractor parties
expect to commence the main El Fayum multi-year and multi-well
development programme in Q2 2022 .
Production forecast for 2022 will be evaluated following
completion of the farm-down to IPR and transfer of operatorship.
Guidance will be given at the AGM.
Vietnam
Vietnam Production
Production in 2021 from the TGT and CNV fields net to the
Group's net working interest averaged 5,560 boepd. This is in line
with the 2021 production guidance.
TGT production averaged 13,887 boepd gross and 4,120 boepd net
to Pharos in 2021 (2020: 15,296 boepd gross and 4,547 boepd net to
Pharos) . CNV production averaged 5,762 boepd gross and 1,440 boepd
net to Pharos in 2021 (2020: 6,223 boepd gross and 1,556 boepd net
to Pharos) .
Vietnam production guidance for 2022 is 5,000 to 6,000 boepd
net.
Vietnam Development and Operations
2021 Activity on TGT
TGT Well Intervention and Development Drilling
In November 2021, the Company announced that the Hoang Long
Joint Operating Company (HLJOC) had successfully completed its 2021
four-well development drilling campaign.
The 2021 drilling campaign was completed safely (on 15 November
2021) with four wells successfully drilled ahead of schedule
(approximately 54 days ahead) and budget. The production
contribution of the drilling campaign mitigated against the field's
natural decline and maintained field production levels. The four
wells were put on production by November 2021. Overall, field
production was affected by the fault of the GTC-A compressor which
was down for 74 days while the repair was done. This is now fully
back in service.
The results of the drilling and intervention activity will
ultimately improve recovery from the field and support the
additional opportunities set out in the Full Field Development Plan
(i.e. nine contingent wells and an extensive well intervention
programme), and a TGT licence extension request to December
2031.
2021 Activity on CNV
As planned, no new drilling activities took place on CNV during
2021. Operations on CNV focused on routine well maintenance and
acid stimulation for two wells.
Vietnam Exploration
Blocks 125 & 126
In July 2021, the Company announced the completion of the 3D
seismic acquisition commitment on the western part of Block 125 in
the Phu Khanh Basin, offshore Vietnam. The 909 km(2) 3D seismic
programme was acquired on behalf of Pharos by Shearwater
GeoServices Singapore Pte Ltd, using the SW Vespucci seismic
vessel, across water depths of between 100m and 2,300m.
The capital spend for the acquisition of the 3D survey was
$8.5m. The seismic processing contract has been awarded, the work
is on schedule and the final processed results are expected in July
2022.
On 8 September 2021, Pharos received approval for a two-year
extension to the initial exploration phase of the Block 125 &
126 PSC from the Vietnamese Ministry of Industry and Trade.
2022 Work Programme
Following completion of the drilling of the initial four
development wells in the TGT Full Field Development Plan (FFDP) and
the HLJOC management committee's budget approval in 2021, two
additional TGT development wells are planned to be drilled in Q3
2022, with the Group's share of the cost of the wells expected to
funded from cash flow. In addition, extensive well interventions
are planned for TGT in 2022.
On CNV, one well is planned to be drilled in Q4 2022 after
completion of the drilling of the two TGT wells.
Additionally, as part of the work programme, the JOC is
progressing work on submitting licence extension requests for both
TGT & CNV, with a Revised Full Field Development Plan ("FFDP")
for both fields to be submitted by Q4 2022. This would take the
licence terms out to December 2031 for TGT and December 2032 for
CNV and would add two years of reserves to the production profiles
and economics for these fields.
On Block 125, final 3D seismic processed results are expected in
July 2022. Following this, the Group will proceed to seismic
mapping to identify prospects and expects to seek a further partner
on the PSC before drilling.
Israel
Pharos, with Capricorn Energy PLC (formerly known as Cairn
Energy PLC) and Israel's Ratio Oil Exploration, have eight licences
offshore Israel. Each party has an equal working interest and
Capricorn Energy is the operator. Evaluation of all reprocessed
seismic data has been finalised with an assessment of prospectivity
being undertaken.
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, 2021 13.0 4.9 17.9 40.8 58.7
------ ------ ----------- --------- ------
Production (1.5) (0.5) (2.0) (1.2) (3.2)
------ ------ ----------- --------- ------
Revision (0.6) (0.1) (0.7) (1.8) (2.5)
------ ------ ----------- --------- ------
2P Commercial Reserves as
of 31 December 2021 10.9 4.3 15.2 37.8 53.0
------ ------ ----------- --------- ------
Oil & Gas 2C Contingent Resource (1,2)
As of 1 January, 2021 8.3 3.9 12.2 19.0 31.2
------ ------ ----------- --------- ------
Revision (0.7) (0.1) (0.8) (0.4) (1.2)
------ ------ ----------- --------- ------
2C Contingent Resources as
of 31 December 2021 7.6 3.8 11.4 18.6 30.0
------ ------ ----------- --------- ------
Total Group 2P Reserves &
2C Contingent Resources (3,4)
As of 31 December 2021 18.5 8.1 26.6 56.4 83.0
------ ------ ----------- --------- ------
(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
(4) Reserves and Contingent Resources have been independently
audited by McDaniel, 100% working interest pre-farm-down with
IPR.
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 2021 .
Vietnam Reserves Statistics
Net Working Interest (mmboe) TGT CNV Total
Vietnam
Oil & Gas 2P Commercial Reserves (1,2)
As of 1 January, 2021 13.0 4.9 17.9
------ ------ ---------
Production (1.5) (0.5) (2.0)
------ ------ ---------
Revision (0.6) (0.1) (0.7)
------ ------ ---------
2P Commercial Reserves as of
31 December 2021 10.9 4.3 15.2
------ ------ ---------
Oil & Gas 2C Contingent Resource (1,2)
As of 1 January, 2021 8.3 3.9 12.2
------ ------ ---------
Revision (0.7) (0.1) (0.8)
------ ------ ---------
2C Contingent Resources as
of 31 December 2021 7.6 3.8 11.4
------ ------ ---------
Total Vietnam 2P Reserves &
2C Contingent Resources (3)
As of 31 December 2021 18.5 8.1 26.6
------ ------ ---------
(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 and 2C contingent resources were revised
downwards due to lower-than-expected well performance and reduced
well intervention activity in the second half of the year because
of drilling operations.
On CNV, the 2P reserves and 2C contingent resources were revised
downwards due to lower than anticipated results from the well
interventions completed in the first half of 2021 .
Egypt Reserves and Contingent Resources
Egypt Reserves Statistics
Net Working Interest (mmboe) Egypt
Oil 2P Commercial Reserves (1)
As of 1 January, 2021 40.8
------
Production (1.2)
------
Revision (1.8)
------
2P Commercial Reserves as
of 31 December 2021 37.8
------
Oil 2C Contingent Resource (1)
As of 1 January, 2021 19.0
------
Revision (0.4)
------
2C Contingent Resources as
of 31 December 2021 18.6
------
Total Egypt 2P Reserves &
2C Contingent Resources (2)
As of 31 December 2021 56.4
------
(1) Reserves and contingent resources are categorised in line
with 2018 SPE standards.
(2) Reserves and Contingent Resources have been independently
audited by McDaniel, 100% working interest pre-farm-down with IPR.
.
On El Fayum, lower than expected field performance and the delay
in the implementation of the field development plan have resulted
in a downwards revision of the 2P reserves and 2C contingent
resources.
Group's Net Working Interest Reserves and Contingent Resources
El Fayum Fields at 31 December 2021 (mmboe)
--------------------------------------------------------------------------
Reserves 1P 2P 3P
----------------------------------------------- ------- ------- -------
Oil 16.8 37.8 50.2
----------------------------------------------- ------- ------- -------
Contingent Resources 1C 2C 3C
----------------------------------------------- ------- ------- -------
Oil 7.5 18.6 38.8
----------------------------------------------- ------- ------- -------
Sum of Reserves and Contingent Resources (1,2) 1P & 1C 2P & 2C 3P & 3C
----------------------------------------------- ------- ------- -------
Total 24.3 56.4 89.0
----------------------------------------------- ------- ------- -------
(1) Reserves and Contingent Resources have been audited
independently by McDaniel, 100% working interest pre-farm-down with
IPR.
(2) The summation of Reserves and Contingent Resources has been prepared by the Company.
TGT Field at 31 December 2021 (mmboe) (net to Group's working interest)
--------------------------------------------------------------------------------
Reserves(3) 1P 2P 3P
--------------------------------------------------- -------- -------- -------
Oil 8.0 10.0 12.0
--------------------------------------------------- -------- -------- -------
Gas(1) 0.6 0.9 1.2
--------------------------------------------------- -------- -------- -------
Total 8.6 10.9 13.2
--------------------------------------------------- -------- -------- -------
Contingent Resources(3) 1C 2C 3C
--------------------------------------------------- -------- -------- -------
Oil 4.2 7.2 10.2
--------------------------------------------------- -------- -------- -------
Gas(1) 0.1 0.4 0.7
--------------------------------------------------- -------- -------- -------
Total 4.3 7.6 10.9
--------------------------------------------------- -------- -------- -------
Sum of Reserves and Contingent Resources(2) 1P & 1C 2P & 2C 3P & 3C
--------------------------------------------------- -------- -------- -------
Oil 12.2 17.2 22.2
--------------------------------------------------- -------- -------- -------
Gas(1) 0.7 1.3 1.9
--------------------------------------------------- -------- -------- -------
Total 12.9 18.5 24.1
--------------------------------------------------- -------- -------- -------
(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 2021 (mmboe) (net to Group's working interest)
--------------------------------------------------------------------------------
Reserves(3) 1P 2P 3P
--------------------------------------------------- -------- -------- -------
Oil 2.4 2.8 3.2
--------------------------------------------------- -------- -------- -------
Gas(1) 1.2 1.5 1.7
--------------------------------------------------- -------- -------- -------
Total 3.6 4.3 4.9
--------------------------------------------------- -------- -------- -------
Contingent Resources(3) 1C 2C 3C
--------------------------------------------------- -------- -------- -------
Oil 1.5 2.5 3.5
--------------------------------------------------- -------- -------- -------
Gas(1) 0.8 1.3 1.9
--------------------------------------------------- -------- -------- -------
Total 2.3 3.8 5.4
--------------------------------------------------- -------- -------- -------
Sum of Reserves and Contingent Resources(2) 1P & 1C 2P & 2C 3P & 3C
--------------------------------------------------- -------- -------- -------
Oil 3.9 5.3 6.7
--------------------------------------------------- -------- -------- -------
Gas(1) 2.0 2.8 3.6
--------------------------------------------------- -------- -------- -------
Total 5.9 8.1 10.3
--------------------------------------------------- -------- -------- -------
(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
Finance strategy
Our finance strategy continues to underpin the Group's business
model and goes hand in hand with our commitment to building
shareholder value through capital growth and sustainable dividends.
In 2021, we recommenced investment in Vietnam and with the
additional liquidity offered by our farm-in partner in Egypt, we
are on the path back to focusing on investing for cash flow
generation and growth in 2022.
Operating performance
Revenues
Group revenues for the year totalled to $163.8m prior to hedging
loss of $29.7m, representing a 38% increase over the prior year
(2020: $118.3m plus hedging gain of $23.7m).
The revenue for Vietnam of $131.0m (2020: $87.7m) increased
significantly year on year. The average realised crude oil price
was $72.61/bbl (2020: $44.70/bbl), a 62% increase year on year, and
the premium to Brent was just under $2/bbl (2020: just over
$3/bbl). Production, however, declined from 6,103 boepd to 5,560
boepd primarily due to the GTC-A compressor fault on the TGT field
in November 2021.
The revenue for Egypt of $32.8m (2020: $30.6m) increased largely
as a result of the higher average realised crude oil price, up 76%
to $65.12/bbl (2020: $37.08/bbl), offset by lower average
production, of 3,318 boepd from 5,270 boepd . 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 nearly
$5/bbl over the year.
Operating costs
Group cash operating costs were $52.0m (2020: $48.3m). Vietnam
increased by 17% from $26.5m to $31.0m in 2021, which equates to
$15.28/bbl (2020: $11.86/bbl). The increase is due to higher costs
relating to the FPSO as a result of (i) lower TLJOC production
throughput which increased Pharos' share of the costs and (ii)
higher foreign contractor's withholding tax, of which the CIT
element impacts the FPSO costs included in operating costs, from 2%
to 5% from 27 August 2018 to date, which was also spread over fewer
produced barrels. Cash operating costs in Egypt were $21.0m in 2021
(2020: $21.8m), which equates to $17.34/bbl (2020: $11.30/bbl). The
decrease in cash operating costs relates predominantly to a
reduction in variable costs as a result of decreased production,
partially offset by higher well workover costs, but spread over
fewer produced barrels.
DD&A
Group DD&A associated with producing assets decreased to
$51.0m (2020: $63.3m) due to the lower depreciating cost base
following 2020 impairments taken on both Vietnam and Egypt,
combined with lower production. DD&A per bbl is currently
$21.19/boe for Vietnam (2020: $21.40/boe) and $6.61/boe in Egypt
(2020: $8.04/boe).
Administrative Expenses
Administrative expenses in 2021 of $13.2m (2020: $14.7m) are
lower than prior year, due to continuous efforts to reduce the head
office costs. After adjusting for the non-cash items under IFRS 2
Share Based Payments of $2.2m (2020: $2.8m) and IFRS 16 Leases $nil
(2020: $0.7m), the administrative expense is $11.0m (2020: $11.2m).
Voluntary staff salary reductions at 20% continued from 2020
through to 1Q 2021. The executive directors, who had previously
volunteered a 35% reduction in base salary in 2020 agreed to a
further reduction from 1 April 2021 to 50% of base salary. The
non-executive directors reduced their fees throughout most of 2020
and continued those reductions throughout the whole of 2021. The
fees will revert to previous levels post completion of the
transaction with IPR. A programme of phased redundancies took place
at head office in London during 2021.
Operating Profit
Operating profit from continuing operations for the year was
$6.3m (2020 : $3.5m) excluding the net impairment reversal of
$42.0m (2020: $234.8m impairment charge), reflecting the higher
commodity price environment throughout the year, offset by lower
production volumes.
Other/Restructuring Expenses
Other/restructuring expenses for the year totalled $3.3m (2020:
$5.8m) and included restructuring costs for both the head office in
London and the Egypt office in Cairo ($3.0m). In addition, there
was $0.3m charge relating to the premium on the transfer of the
lease on the London office.
Finance Costs
Finance costs increased to $6.4m (2020: $4.2m), mainly related
to amortisation of capitalised borrowing costs of $2.4m (2020:
$1.5m gain due to changes in future cash flows), interest expense
payable and similar fees of $3.8m (2020: $4.8m) and unwinding of
discount on provisions of $0.8m (2020: $0.8m).
Cash operating cost per 2021 2020
barrel*
$m $m
------------------------ ------ ------
Cost of sales 114.6 123.8
------------------------ ------ ------
Less
------------------------ ------ ------
Depreciation, depletion
and amortisation (51.0) (63.3)
------------------------ ------ ------
Production based taxes (10.1) (7.0)
------------------------ ------ ------
Inventories 0.1 (2.3)
------------------------ ------ ------
Other cost of sales (1.6) (2.9)
------------------------ ------ ------
Cash operating costs 52.0 48.3
------------------------ ------ ------
Production (BOEPD) 8,878 11,373
------------------------ ------ ------
Cash operating cost per
BOE ($) 16.05 11.60
------------------------ ------ ------
DD&A per barrel* 2021 2020
$m $m
------------------------ ------ ------
Depreciation, depletion
and amortisation (51.0) (63.3)
------------------------ ------ ------
Production (BOEPD) 8,878 11,373
------------------------ ------ ------
DD&A per BOE ($) 15.74 15.21
------------------------ ------ ------
Cash operating cost Vietnam Egypt Total
per barrel by Segment $m $m $m
------------------------ ------- ----- ------
Cost of sales 84.3 30.3 114.6
------------------------ ------- ----- ------
Less
------------------------ ------- ----- ------
Depreciation, depletion
and amortisation (43.0) (8.0) (51.0)
------------------------ ------- ----- ------
Production based taxes (9.8) (0.3) (10.1)
------------------------ ------- ----- ------
Inventories 0.1 - 0.1
------------------------ ------- ----- ------
Other cost of sales (0.6) (1.0) (1.6)
------------------------ ------- ----- ------
Cash operating costs 31.0 21.0 52.0
------------------------ ------- ----- ------
Production (BOEPD) 5,560 3,318 8,878
------------------------ ------- ----- ------
Cash operating cost
per BOE ($) 15.28 17.34 16.05
------------------------ ------- ----- ------
DD&A per barrel by Segment Vietnam Egypt Total
$m $m $m
--------------------------- ------- ----- ------
Depreciation, depletion
and amortisation (43.0) (8.0) (51.0)
--------------------------- ------- ----- ------
Production (BOEPD) 5,560 3,318 8,878
--------------------------- ------- ----- ------
DD&A per BOE ($) 21.19 6.61 15.74
--------------------------- ------- ----- ------
* Cash operating cost per barrel and DD&A per barrel are
alternative performance measures. See page 35.
Movements in Property, Plant 2021 2020
and Equipment
$m $m
------------------------------- ------ -------
As at 1 Jan 435.8 676.9
------------------------------- ------ -------
Capital spend 24.7 33.5
------------------------------- ------ -------
Revision in decommissioning
assets (1.9) 6.6
------------------------------- ------ -------
Disposal of other assets - (0.5)
------------------------------- ------ -------
Derecognition of right-of-use
asset - (5.7)
------------------------------- ------ -------
Re-classification of
assets held for sale (62.0) -
------------------------------- ------ -------
DD&A- Oil and gas properties (51.0) (63.3)
------------------------------- ------ -------
DD&A - Other assets (0.4) (1.2)
------------------------------- ------ -------
Impairment reversal/(charge)
- PP&E 54.6 (210.5)
------------------------------- ------ -------
As at 31 Dec 399.8 435.8
------------------------------- ------ -------
Property, Plant and
Equipment 399.8 435.7
------------------------------- ------ -------
Right-to-use-Asset
(IFRS 16 Impact) - 0.1
------------------------------- ------ -------
As at 31 Dec 399.8 435.8
------------------------------- ------ -------
Taxation
The overall net tax charge of $43.3m (2020: $25.6m credit)
relates to tax charges in Vietnam of $24.8m plus the deferred tax
charge on impairment reversal of $18.5m (2020: Vietnam tax charges
of $11.1m offset by a deferred tax credit on impairment of
$36.7m).
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 Pharos El Fayum
(PEF). The Group records a tax charge, with a corresponding
increase in revenue, for the tax paid by EGPC on its behalf. Due to
accumulated tax-deductible balances, there is no tax due on PEF
this period.
One of the Group company 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
$29.7m recorded in the year as it is unlikely that the UK tax group
will generate sufficient taxable profit in the future, against
which the deductible temporary differences can be utilised.
Loss post tax
The post tax loss for the year from continuing operations and
prior to the impairment reversal of $42.0m, impairment tax charge
of $18.5m and exceptional costs of $3.3m was $24.9m (2020: post tax
loss for the year of $11.7m from continuing operations and prior to
the impairment charge of $234.8m, impairment tax credit of $36.7m
and exceptional costs of $5.8m). The overall loss for the year was
$ 4.7m (2020: $ 215. 8 m).
Cash flow
Operating cash flow (before movements in working capital) was
$60.1m (2020: $70.8m), after tax charges of $39.9m (2020: $26.5m),
restructuring expense $0.7m (2020: $2.7m) and working capital
adjustments of $8.6m (2020: $14.7m), the cash generated from
operations was $10.8m (2020: $56.4m).
Operating cash flow (before movements in working capital)
adjusted for the impact of the hedging positions of $29.7m loss
(2020: gain $23.7m) gives an underlying operational performance of
$89.8m (2020: $47.1m), which is consistent with the improvement
seen in commodity prices offset by the production decrease year on
year.
The increase in receivables was $7.2m (2020: decrease in
receivables of $19.6m). The movement is mainly commodity price
driven, from YE20 the average oil price realised has increased from
$44.70/bbl to $70.95/bbl, therefore increasing the receivables
balance held at YE21.
Capital expenditure on continuing operations for the year was
relatively flat at $41.8m (2020: $41.3m). All discretionary capex
was deferred during 2020 following the oil price crash to preserve
balance sheet strength and liquidity. During 2021, the TGT four
well infill development was successfully carried out within
schedule and under budget. Egypt capital expenditure included the
drilling of commitment exploration well Batran-1X in May 2021 and a
three-well back-to-back development drilling programme commenced in
November 2021.
Net cash inflows from financing activities of $31.1m (2020:
$48.5m outflow) included net inflow of the RBL totalling $20.9m
following the refinancing in July 2021 ($21.8m further borrowing,
offset by $0.9m settlement of the original RBL). The revised RBL
has provided access of up to a committed $100m with a further $50m
available on an uncommitted "accordion" basis and has a four year
term that matures in July 2025. In 2020, the significant decrease
in the oil price during H1 2020 led to a reduction in the borrowing
base and principal repayments during the year on the RBL totalled
$42.8m. In addition for 2021, the Group drew down on a new facility
with National Bank of Egypt for a net amount of $6.5m ($18.1m
principal facility, less $11.6m of repayments). The carrying amount
of our trade receivables balance includes receivables in Egypt
which are subject to an Uncommitted Revolving Credit Facility for
Discounting (with Recourse) arrangement. This facility has been put
in place to mitigate the risk of late payment of our debtors. Under
this arrangement, Pharos is able to access cash from the facility
using the El Fayum oil sales invoices as evidence to support its
ability to repay the facility. The oil sales invoices remain due to
Pharos and it retains the credit risk. The Group therefore
continues to recognise the trade receivables in their entirety on
the balance sheet.
In January 2021, also within financing activities, the Company
announced the successful completion of the placing, subscription
and retail offer resulting in the issue of 44,661,490 new ordinary
shares. Through this transaction, Pharos raised additional capital
of $10.9m (net of direct issue costs of $0.8m).
No final dividend was paid for the year (2020: $nil).
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 Pharos' sustainable
business model.
The Group's Code of Business Conduct & 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 2021, the total payments to governments for the Group
amounted to $ 198.2 m (2020: $150.9m), of which $ 151.9 m or 77 %
(2020: $104.9m or 70%) was related to the Vietnam producing licence
areas, of which $ 102.6 m (2020: $72.5m) was for indirect taxes
based on production entitlement. In Egypt payments to government
totalled $ 44.7 m (2020: $42.2m), of which $ 44.1 m (2020: $41.3m)
related to indirect taxes based on production entitlement.
Balance sheet
Intangible assets increased during the period to $12.4m (2020:
$1.5m). Additions for the year related to Blocks 125 & 126 in
Vietnam $10.6m (2020: $2.0m), Egypt $3.9m (2020: $1.1m) and $0.7m
(2020: $1.2m) for the Israeli bid round licence fee. The Group has
written off $2.2m relating to the Israel asset as no substantive
expenditure has been identified under IFRS 6. In addition, $2.1m of
intangible assets relating to the Egypt concessions has been
re-classified as assets held for sale.
The movements in the Property, Plant and Equipment asset class
are shown above.
Impairment
As a result of ongoing oil price volatility and movements in 2P
reserves, we have tested each of our oil and gas producing
properties for impairment and impairment reversals. The results of
these impairment tests are summarised below. For Vietnam producing
properties, 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 based on the
fair value derived from a discounted cash flow valuation of the 2P
production profile for each producing property. For Egypt producing
property, the recoverable amount has been determined using the
value-in-use method.
For CNV, a pre-tax impairment reversal of $3.8m (2020:
impairment charge $23.3m) has been reflected in the income
statement with an associated deferred tax charge of $1.4m (2020:
deferred tax credit $8.7m). As at 31 December 2021, the carrying
amount of the CNV oil and gas producing property, after additions
of $0.3m, changes in decommissioning asset due to discount rate
($0.9m), DD&A ($10.2m) and the impairment reversal ($3.8m), is
$84.2m (2020: the carrying amount of the CNV oil and gas producing
property, after additions ($1.9m), DD&A ($11.5m) and the
impairment charge ($23.3m) was $91.2m).
For TGT, a pre-tax impairment reversal of $49.1m (2020:
impairment charge $81.8m) has been reflected in the income
statement with an associated deferred tax charge of $17.1m (2020:
deferred tax credit $28.0m). As at 31 December 2021, the carrying
amount of the TGT oil and gas producing property, after additions
of $11.4m, changes in decommissioning asset due to discount rate
($1.0m), DD&A ($32.8m) and the impairment reversal ($49.1m), is
$266.0m (2020: the carrying amount of the TGT oil and gas producing
property, after additions ($14.8m), DD&A ($36.3m) and the
impairment charge ($21.9m) was $239.3m).
For Egypt, an impairment reversal (pre- and post-tax) in the
amount of $1.7m (2020: impairment charge $105.4m) has been
reflected in the income statement. As at 31 December 2021, the
carrying amount of the Egypt oil and gas producing property, after
additions ($12.9m), re-classification of PP&E to assets held
for sale of ($1.4m), DD&A ($8.0m) and the impairment reversal
($1.7m), is $109.3m (2020: the carrying amount of the Egypt oil and
gas producing property, after additions ($22.7m), DD&A ($15.2m)
and the impairment charge ($105.4m) was $104.1m). After the
reclassification to assets held for sale, the Egypt oil and gas
producing property amounts to $49.2m.
The total non-cash, post tax impairment reversal amounts to
$36.1m and the balance sheet carrying values of the oil and gas
producing properties stands at $399.4m, after reclassification of
assets held for sale in relation to Egypt of $61.6m (2020: the
total non-cash, post tax impairment charge amounts to $173.8m and
the balance sheet carrying values of the oil and gas producing
properties stood at $434.6m). Further details of these impairment
charges and oil price scenario sensitivity testing, including key
assumptions in relation to oil price, discount rate and 2P reserves
in Vietnam, are provided in Note 10 of the financial
statements.
The agreement post year end of the Third Amendment to the El
Fayum Concession Agreement, with retroactive application of the
improved fiscal terms from November 2020 and a three and a half
year extension to the exploration period was not considered certain
at 31 December 2021 and so has been treated as a non-adjusting post
balance sheet event. An impairment reversal of $28.2m utilising the
circumstances of 31 December 2021 as the basis has been calculated
and will be factored into the impairment reviews going forward.
Balance sheet continued
Cash is set aside into abandonment funds for both TGT and CNV.
These abandonment funds are operated 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 our financial statements.
Oil inventory was $5.9m at 31 December 2021 (2020: $5.6m), of
which $5.4m related to Vietnam and $0.5m to Egypt. Trade and other
receivables increased to $28.1m (2020: $22.9m) of which $18.2m
(2020: $11.2m) relates to Vietnam and $8.5m (2020: $10.0m) to
Egypt, driven mainly by the higher oil price and timing of crude
oil cargos.
Cash and cash equivalents at the end of the year were $27.1m
(2020: $24.6m) mainly due to the RBL refinancing in July and also
the Placing in January 2021, offset by the reduction in net cash
from operating activities as a result of the hedging losses during
the year.
Trade and other payables were $30.6m (2020: $35.6m), of which
$14.5m (2020: $23.3m) relates to the Egypt payables, $4.8m (2020:
$1.7m) Vietnam payables and $6.5m (2020: $6.8m) net hedging
liability. Tax payable decreased to $5.4m (2020: $6.7m), consistent
with lower revenues.
Borrowings were $80.5m (2020: $53.7m), an increase of $26.8m and
$20.3m related to the RBL refinancing in July, inclusive of
capitalised borrowing costs. In April 2021, the Group drew down on
the new facility with the National Bank of Egypt and the amount
repayable under the agreement at 31 December 2021 was $6.5m (2020:
$nil). Net debt was $57.5m (2020: $32.6m).
Long-term provisions comprise the Group's decommissioning
obligations and the royalty over the El Fayum asset. In Vietnam,
the decommissioning provision decreased from $68.0m at 2020
year-end to $66.9m at 2021 mainly due to an increase in discount
rate from 0.9% to 1.5% as a result of an increase in prevailing
risk-free market rates, partially offset by the TGT infill well
programme. The amounts set aside into the abandonment funds total
$48.1m (2020: $45.9m). No decommissioning obligation exists in the
El Fayum producing area under the terms of the Concession Agreement
in Egypt.
The royalty provision relates to a historical arrangement
granting a 3% royalty on Pharos's share of profit oil and excess
cost recovery from El Fayum in Egypt. At 31 December 2021, the
provision was increased by $0.2m, giving a total of $5.6m ($3.4m of
which is deemed to be repayable in 2022).
Own shares
The Pharos EBT holds ordinary shares of the Company for the
purposes of satisfying long-term incentive awards for senior
management. At the end of 2021, the trust held 1,767,757 (2020:
2,181,655), representing 0.40% (2020: 0.54%) of the issued share
capital.
In addition, as at 31 December 2021, the Company held 9,122,268
(2020: 9,122,268) treasury shares, representing 2.02% (2020: 2.24%)
of the issued share capital.
Assets held for sale
In December 2021, the Company announced that shareholders had
approved the farm-out of 55% of the Group's operated interest in
each of our Egyptian Concessions, El Fayum and North Beni Suef, to
IPR, a group that has extensive experience in Egypt.
As part of the transaction, IPR will fund Pharos's share of the
costs to a maximum of $33.425m (to be adjusted for working capital
and interim period adjustments from the effective economic date of
1 July 2020). This is in addition to the deposit at signing of the
farm-out agreements of US$2 million and a further US$3 million
payable on completion. This investment programme should result in
an increase in production and also fulfil commitments under the
concessions. In addition, the Group will be entitled to contingent
consideration depending on the average Brent Price each year from
2022 to the end of 2025, capped at a maximum total payment of US$20
million.
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. The breakdown of
assets held for sale at year end is as follows:
2021
$m
---------------------------------------- ------
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
---------------------------------------- ------
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 which uses an oil price
of $76.9/bbl in 2022 and $70.2/bbl in 2023.The key assumptions and
related sensitivities include a "Reasonable Worst Case" (RWC)
sensitivity, where the Board has considered the risk of an oil
price crash broadly similar to 2020 as a result of the global
outbreak of the COVID-19 virus. This assumes the Brent oil price
drops to 49.0/bbl in April 2022 and gradually recovers to base
price in next 12 months, concurrent with reductions in Vietnam and
Egypt production compared to our base case of 5% from March 2022.
Both the base case and RWC take into consideration the hedging that
has already been put in place for 2022 and 2023 which covers 24.6%
of the Group's forecast Q2 2022 to Q2 2023 entitlement volumes
securing a minimum and maximum price for this hedged volume of
$67.5 and $81.4 per barrel, respectively. Under the RWC scenario,
we have identified appropriate mitigating actions, which could look
to defer capital expenditure programme as required.
We have also developed a reverse stress test sensitivity, which
shows the extent to which oil prices would need to fall before our
financial headroom is breached, keeping all other variables
unchanged.
In Egypt, the Base case assumes a full investment scenario and a
farm-down .
Our business in Vietnam remains robust with a breakeven price of
c.$25/bbl. We have limited capital expenditure outside of the two
TGT wells and one CNV well in Vietnam over the rest of the business
with most falling outside 2022. Most of our debt is secured against
the Vietnam assets under the RBL with just $6.5m drawn on an
uncommitted revolving credit facility on the Egypt revenue
invoices.
The forecasts outlined above show that the Group will have
sufficient financial headroom for the 12 months from the date of
approval of the 2021 Accounts. Based on this analysis, the
Directors have a reasonable expectation that the Group has adequate
resources to continue in operational existence for the foreseeable
future. Therefore, they continue to use the going concern basis of
accounting in preparing the annual Financial Statements.
Financial outlook
Pharos' financial strength is founded on our long-term approach
to managing capital to provide risk adjusted full cycle returns,
which has allowed us to return significant amounts of capital to
shareholders in previous years. In a prevailing stronger oil price
environment, our focus can turn again to returns to
shareholders.
We continue to have the support of our strong RBL lending banks
who approved the refinancing of the RBL during July, extending the
tenor to July 2025. Additionally, we also signed an uncommitted
revolving credit facility with National Bank of Egypt, which
provides modest additional liquidity.
The improvement in the fiscal terms and the farm-down of our
concessions in Egypt to IPR means that we will enjoy the benefit
from completion in 2022 and into 2023 of the carry of our share of
operating and capital costs. During the carry period we continue to
receive our revenues with only Pharos 100% costs to cover.
The low breakevens and continuation of the TGT infield
development plan in Vietnam with two additional wells and one well
infield well in CNV will support the production profiles in a
strong price environment.
The restructure of the London and Cairo offices will be fully
completed following the transfer of operatorship of the Egypt
concessions to IPR. The restructure resets the cost base for the
Group moving forward.
The measures we have taken during this period have set us up to
be able to reap the benefits of stable production from our assets,
improved fiscal terms, low breakevens, improved liquidity from our
lenders, a streamlined organisation against a background of
improved long term prices.
Sue Rivett
Chief Financial Officer
Condensed consolidated income statement
for the year to 31 December 2021
2021 2020
Notes $ million $ million
---------- ----------
Continuing operations
Revenue 3 134.1 142.0
Cost of sales 4 (114.6) (123.8)
---------- ----------
Gross profit 19.5 18.2
Administrative expenses (13.2) (14.7)
Impairment charge
- Intangibles 3, 9 (2.2) (24.3)
Impairment reversal/(charge)
PP&E 3, 10 54.6 (210.5)
Impairment charge
- Assets classified
as held for sale 14 (10.4) -
---------- ----------
Operating profit/(loss) 48.3 (231.3)
Other/restructuring
expense 5 (3.3) (5.8)
Investment revenue - 0.1
Finance costs 6 (6.4) (4.2)
---------- ----------
Profit/(loss) before
tax 3 38.6 (241.2)
Tax 3,7 (43.3) 25.6
---------- ----------
Loss for the year from continuing operations (4.7) (215.6)
---------- ----------
Discontinued operations 3
Loss post-tax for the year from discontinued
operations - (0.2)
Loss for the year (4.7) (215.8)
---------- ----------
Loss per share from continuing operations
(cents) 8
Basic (1.1) (54.6)
Diluted (1.1) (54.6)
Loss per share from continuing and discontinued
operations (cents)
Basic (1.1) (54.6)
Diluted (1.1) (54.6)
Condensed consolidated statements of comprehensive income
for the year to 31 December
2021
2021 2020
$ million $ million
---------- ----------
Loss for the year (4.7) (215.8)
Items that may be subsequently reclassified to
profit or loss:
Fair value (loss)/gain arising on hedging instruments
during the year (27.7) 20.0
Less: Loss/(gain) arising on hedging Instruments
reclassified to profit or loss 29.7 (23.7)
Total comprehensive loss for the year (2.7) (219.5)
---------- ----------
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
---------- ---------- ---------- ----------
2021 2020 2021 2020
Notes $ million $ million $ million $ million
---------- ---------- ---------- ----------
Non-current assets
Intangible assets 9 12.4 1.5 - -
Property, plant and
equipment 10 399.8 435.7 - -
Right-of-use assets - 0.1 - -
Investments - - 278.7 268.1
Loan to subsidiaries - - 27.4 21.1
Other assets 48.1 45.9 - -
---------- ----------
460.3 483.2 306.1 289.2
---------- ---------- ---------- ----------
Current assets
Inventories 10.7 17.7 - -
Trade and other receivables 28.1 22.9 1.4 1.6
Tax receivables 1.5 0.6 0.4 0.6
Cash and cash equivalents 27.1 24.6 5.3 3.5
Assets classified
as held for sale 14 62.0 - - -
---------- ---------- ----------
129.4 65.8 7.1 5.7
---------- ---------- ---------- ----------
Total assets 589.7 549.0 313.2 294.9
Current liabilities
Trade and other payables (30.6) (35.6) (4.3) (2.7)
Borrowings (33.3) (12.7) - -
Lease Liabilities - (0.4) - -
Tax payables (5.4) (6.7) (1.0) (0.4)
Liabilities directly associated
with assets classified as
held for sale 14 (8.5) - - -
---------- ---------- ---------- ----------
(77.8) (55.4) (5.3) (3.1)
---------- ---------- ----------
Non-current liabilities
Deferred tax liabilities (91.2) (85.5) - -
Borrowings (47.2) (41.0) - -
Long term provisions (69.1) (73.4) - -
---------- ---------- ---------- ----------
(207.5) (199.9) - -
Total liabilities (285.3) (255.3) (5.3) (3.1)
---------- ---------- ---------- ----------
Net assets 304.4 293.7 307.9 291.8
---------- ---------- ---------- ----------
Equity
Share capital 34.9 31.9 34.9 31.9
Share Premium 58.0 55.4 58.0 55.4
Other reserves 250.5 243.0 202.4 197.6
Retained (deficit)
/ earnings (39.0) (36.6) 12.6 6.9
---------- ---------- ---------- ----------
Total equity 304.4 293.7 307.9 291.8
---------- ---------- ---------- ----------
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 2020 31.9 55.4 246.6 176.2 510.1
Loss for the year - - - (215.8) (215.8)
Other comprehensive loss - - (3.7) - (3.7)
Currency exchange translation
differences - - 0.8 - 0.8
Share-based payments - - 2.3 - 2.3
Transfer relating to share-based
payments - - (3.0) 3.0 -
--------------- ------------- -------------- ------------ ----------
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
Shares 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 31 December 2021 34.9 58.0 250.5 (39.0) 304.4
--------------- ------------- -------------- ------------ ----------
Company
---------------------------------------------------------------------
Called up Retained
share capital Share premium Other reserves earnings Total
$ million $ million $ million $ million $ million
-------------- ------------- -------------- ---------- ----------
As at 1 January 2020 31.9 55.4 199.3 268.4 555.0
Loss for the year - - - (264.5) (264.5)
Currency exchange translation
differences - - 0.8 - 0.8
Share-based payments - - 2.3 - 2.3
Transfer relating to share-based
payments - - (4.8) 3.0 (1.8)
-------------- ------------- -------------- ---------- ----------
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 31 December 2021 34.9 58.0 202.4 12.6 307.9
-------------- ------------- -------------- ---------- ----------
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 2021
Group Company
---------- ---------- ---------- ----------
2021 2020 2021 2020
Notes $ million $ million $ million $ million
---------- ---------- ---------- ----------
Net cash from (used in) operating
activities 13 10.8 56.4 (7.1) (16.9)
---------- ---------- ---------- ----------
Investing activities
Purchase of intangible assets (15.2) (3.5) - -
Purchase of property, plant
and equipment (24.4) (35.5) - -
Advance consideration on farm
out of Egyptian assets 2.0 - - -
Payment to abandonment fund (2.2) (2.3) - -
Other investment in subsidiary
undertakings - - (8.4) (5.4)
Dividends received from subsidiary
undertakings - - 6.1 21.8
Net cash (used in) from investing
activities (39.8) (41.3) (2.3) 16.4
Financing activities
Repayment of borrowings (12.5) (42.8) - -
Proceeds from borrowings 39.9 - - -
Interest paid on borrowings (6.8) (4.6) - -
Lease payments (0.4) (1.1) - (0.5)
Net proceeds from issue of share
capital 10.9 - 10.9 -
Net cash from (used in) financing
activities 31.1 (48.5) 10.9 (0.5)
---------- ---------- ---------- ----------
Net increase (decrease) in cash
and cash equivalents 2.1 (33.4) 1.5 (1.0)
Cash and cash equivalents at
beginning of year 24.6 58.5 3.5 4.5
Effect of foreign exchange rate
changes 0.4 (0.5) 0.3 -
Cash and cash equivalents at
end of year 27.1 24.6 5.3 3.5
---------- ---------- ---------- ----------
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 2021
or 2020, but is derived from those accounts. A copy of the
statutory accounts for 2020 has been delivered to the Registrar of
Companies and those for 2021 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.
- Covid-19-Related Rent Concessions - amendments to IFRS 16, and
- Interest Rate Benchmark Reform - Phase 2 - amendments to IFRS
9, IAS 39, IFRS 7, IFRS 4 and IFRS 16.
(c) New standards and interpretations not yet adopted
Certain new accounting standards and interpretations have been
published that are not mandatory for 31 December 2021 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). Africa has been classified as a discontinued operation
for all years shown, as the Group disposed of all of its interests
in that geographical area in previous years. There are no
inter-segment sales. South East Asia and Egypt form the basis on
which the Group reports its segment information.
2021
SE Asia Egypt Africa(2) Unallocated Group
$ million $ 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(3) - - - (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 from
continuing operations(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)
----------- ---------- ---------- ----------- -----------------
2020
SE Asia Egypt Africa(2) Unallocated Group
$ million $ million $ million $ million $ million
----------- ---------- ---------- ----------- -----------------
Oil and gas sales 87.7 30.6 - - 118.3
Realised gain on commodity hedges - - - 23.7 23.7
Total revenue 87.7 30.6 - 23.7 142.0
Depreciation, depletion and amortisation
- Oil and gas (47.8) (15.5) - - (63.3)
Depreciation, depletion and amortisation
- Other - (0.5) - (0.7) (1.2)
Impairment charge - Intangibles(4) (19.0) (5.3) - - (24.3)
Impairment charge - PP&E (105.1) (105.4) - - (210.5)
Loss (profit) before tax from
continuing operations(1) (121.8) (124.6) - 5.2 (241.2)
Loss (post-tax) from discontinued
operations - - (0.2) - (0.2)
Tax charge on operations (11.1) - - - (11.1)
Tax credit on impairment 36.7 - - - 36.7
----------- ---------- ---------- ----------- -----------------
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 Africa operations in Congo and Angola were disposed of on 24
June 2018 and 5 October 2018 respectively.
3 Includes $2.2m write-off of seismic costs relating to Israel
exploration Zones A and C.
4 Includes $1.1m write off of Block 125&126 tax receivable
(other receivable - current) which was dependent on the E&E
being developed.
Included in revenues arising from South East Asia and Egypt are
revenues of $128.3m and $32.8m which arose from the Group's two
largest customers, who contributed more than 10% to the Group's oil
and gas revenue (20202: $61.3m and $30.6m in South East Asia 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.
2021 2020
$ million $ million
----------- -----------
Vietnam 131.0 64.4
Egypt 32.8 30.6
China - 9.4
Malaysia - 9.2
Other - 4.7
----------- -----------
163.8 118.3
----------- -----------
2021 2020
Non-current assets $ million $ million
----------- -----------
Vietnam 360.8 330.5
Egypt 51.4 105.3
Israel - 1.5
412.2 437.3
----------- -----------
Excludes other assets.
4. Cost of sales
2021 2020
$ million $ million
---------- ----------
Depreciation, depletion and amortisation 51.0 63.3
Production based
taxes 10.1 7.0
Production operating
costs 53.6 51.2
Inventories (0.1) 2.3
114.6 123.8
---------- ----------
5. Other/restructuring expense
2021 2020
$ million $ million
---------- ----------
Egypt acquisition
cost - royalty - 4.9
Redundancy loss/(gain) 3.0 (0.1)
Premium - lease
transfer 0.3 1.0
3.3 5.8
---------- ----------
6. Finance Cost
2021 2020
$ million $ million
----------- -----------
Unwinding of discount on provisions 0.8 0.8
Interest expense payable and similar fees 3.8 4.5
Interest on lease liabilities - 0.3
Amortisation of capitalised borrowing costs 2.4 (1.5)
Net foreign exchange (gains)/losses (0.6) 0.1
----------- -----------
6.4 4.2
----------- -----------
In 2021 $0.8m relates to the unwinding of discount on the
provisions for decommissioning (2020: $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 9-10 years) in the
removal and decommissioning of the facilities currently in
place.
Following the June and December 2021 redeterminations, together
with refinancing completed in July 2021 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 gain of $0.5m and
amortised cost of $2.9m have been recognised in profit or loss.
7. Tax
2021 2020
$ million $ million
--------------- -----------------
Current tax charge 37.6 26.7
Deferred tax credit on operations (12.8) (15.6)
Deferred tax charge/(credit) on impairment 18.5 (36.7)
--------------- -----------------
Total tax charge / (credit) 43.3 (25.6)
--------------- -----------------
The Group's corporation tax is calculated at 50% (2020: 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 2021 and 2020 both current and deferred
taxation have arisen in overseas jurisdictions only.
The charge for the year can be reconciled to the profit / (loss)
per the income statement as follows:
2021 2020
$ million $ million
----------- -----------
Profit / (Loss) before tax (including discontinued
operations) 38.6 (241.4)
Profit / (Loss) before tax at 50% (2020: 50%) 19.3 (120.7)
Effects of:
Non-taxable income (8.0) -
Non-deductible expenses 4.5 24.8
Tax losses not recognised 28.7 57.7
Non-deductible exploration costs written off - 9.5
Adjustments to tax charge in respect of previous
periods (1.2) 3.1
----------- -----------
Tax charge / (credit) for the year 43.3 (25.6)
----------- -----------
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 off of
$9.5m in 2020 related to the impairment of exploration assets in
Vietnam.
Non-taxable income principally relates to Vietnam impairment
reversal of $(8.0)m (2020: $nil). Non-deductible expenses primarily
relate to Vietnam DD&A charges for costs previously
capitalised, which are non-deductible for Vietnamese tax purposes
of $1.8m (2020: $6.1m) and Vietnam net impairment charge of $nil
(2020: $15.9m). A further $2.7m (2020: $2.0m) 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 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. It also includes
losses arising in Egypt for which no future benefit can be obtained
under the terms of the concession agreement.
8. Earnings per share
The calculation of the basic and diluted earnings per share is
based on the following data:
Group
------------------------
2021 2020
$ million $ million
----------- -----------
Loss from continuing and discontinued operations
for the purposes of basic loss per share (4.7) (215.8)
Effect of dilutive potential ordinary shares -
Cash settled share awards and options - -
----------- -----------
Loss from continuing and discontinued operations
for the purposes of diluted loss per share (4.7) (215.8)
----------- -----------
Group
------------------------
2021 2020
$ million $ million
----------- -----------
Loss from continuing operations for the purposes
of basic loss per share (4.7) (215.6)
Effect of dilutive potential ordinary shares - - -
Cash settled share awards and options
Loss from continuing operations for the purposes
of diluted loss profit per share (4.7) (215.6)
----------- -----------
Number of shares (million)
----------------------------
2021 2020
------------- -------------
Weighted average number of ordinary shares 437.8 395.1
Effect of dilutive potential ordinary shares -
Share awards and options - -
Weighted average number of ordinary shares for
the purpose of diluted loss per share 437.8 395.1
------------- -------------
In accordance with IAS 33 "Earnings per Share", the effects of
$14.2m (2020: $1.3m) antidilutive potential shares have not been
included when calculating dilutive earnings per share for the year
ended 31 December 2021 or 2020, as the Group was loss making.
9. Intangible assets
Intangible assets at 2021 year-end comprise the Group's
exploration and evaluation projects which are pending
determination. Included in the additions is Blocks 125 & 126 in
Vietnam $10.6m (2020: $2.0m), Egypt $3.9m (2020: $1.1m) of which
$0.6m (2020: $0.3m) relates to North Beni Suef, and $0.7m (2020:
$1.2m) for Israel.
During 2021, $0.7m was spent in Israel on geoscience and
geophysical studies (2020: $1.2m). Pharos continues to hold $2.7m
(2020: $2.7m) cash in relation to bank guarantees for the Israeli
offshore exploration licenses. At 31 December 2021, the Group has
decided to write off the $2.2m 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 &
126 in Vietnam is still ongoing and the carrying value of the Egypt
exploration and evaluation expenditure will be reviewed following
the completion of the farm out of the Egypt concessions. Whilst
ongoing costs for exploration are forecast and funds available for
future exploration, there is not sufficient certainty of recovery
to justify the reversal of the past impairment made. This will be
kept under review as the exploration activity continues.
10. Property, plant and equipment
As a result of the oil price volatility 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.
Vietnam
The key assumptions to which the fair value measurement is most
sensitive are oil price, discount rate, capital spend and 2P
reserves (2020: oil price, discount rate, capital spend and 2P
reserves). As at 31 December 2021, the fair value of the assets are
estimated based on a post-tax nominal discount rate of 11.4% (2020:
11%) and a Brent 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 (2020: an oil price of $57.0/bbl in 2022, $59.0/bbl in
2023, $61.0/bbl in 2024 plus inflation of 2.0% thereafter).
For CNV, a pre-tax impairment reversal in the amount of $3.8m
has been reflected in the income statement with an associated
deferred tax charge of $1.4m. As at 31 December 2021, the carrying
amount of the CNV oil and gas producing property, after additions
($0.9m decrease in decommissioning asset offset by $0.3m in
additions), DD&A ($10.2m) and impairment reversal ($3.8m), is
$84.2m.
For TGT, a pre-tax impairment reversal in the amount of $49.1m
has been reflected in the income statement with an associated
deferred tax charge of $17.1m. As at 31 December 2021, the carrying
amount of the TGT oil and gas producing property, after additions
($1.0m decrease in decommissioning asset offset by $11.4m in
additions), DD&A ($32.8m) and after impairment reversal
($49.1m), is $266.0m.
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 $23.8m on TGT and a $4.5m on CNV. A 1% increase in discount
rate would result in post-tax impairments of $4.5m on TGT and $1.5m
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; $70.2/bbl in 2022, $70.2/bbl in 2023,
$67.8/bbl in 2024, $68.0/bbl in 2025, $64.0/bbl in 2026, $59.0/bbl
in 2027, $54.0/bbl in 2028, $49.0/bbl in 2029 and $44.0/bbl in
2030. Using these prices and an 11.4% discount rate would result in
additional post-tax impairments of $16.9m on TGT and $5.6m 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 (2020: oil price, discount rate, capital spend and 2P
reserves). As at 31 December 2021, the fair value of the assets are
estimated based on a post-tax nominal discount rate of 14% (2020:
14%) and a Brent 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 (2020: an oil price of $57.0/bbl in 2022, $59.0/bbl in
2023, $61.0/bbl in 2024 plus inflation of 2.0% thereafter).
An impairment reversal (pre and post-tax) of $1.7m arose on El
Fayum as a result of the above impairment test. As at 31 December
2021, the carrying amount of the Egypt oil and gas producing
property, after additions ($12.9m offset by $1.4m reclassified 100%
to assets held for sale), DD&A ($8.0m) and the impairment
reversal, is $109.3m, pre-reclassification to Assets held for
sale.
After the reclassification to assets held for sale, the Egypt
oil and gas producing property amounts to $49.2m. Testing of
sensitivity cases indicated that a $5/bbl reduction in long term
oil price used would result in an impairment of $18.1m (compare to
new NBV). A 1% increase in discount rate would result in an
impairment charge of $3.1m. We have also run a sensitivity using a
14% discount rate and the Net Zero price scenario which would
result in an additional impairment of $24.1m.
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 2021, 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 RBL over the producing assets in Vietnam. The commodity hedges
run until December 2022 and are settled monthly. The hedging
positions in place at the balance sheet date cover 23% of the
Group's forecast production until December 2022, securing a minimum
price for this hedged volume of $68.2 per barrel (2020: cover was
42% of the Group's forecast production until December 2021 securing
an average price for this hedged volume of $44.7 per barrel).
Pharos has designated the swaps 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 2021 a
loss of $29.7m was realised (2020: gain of $23.7m). The outstanding
unrealised loss on open position as at 31 December 2021 amounts to
$4.3m (2020: loss of $6.3m).
The carrying amount of the swaps 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 2021 was
$6.5m (2020: liability position $6.8m).
12. Distribution to Shareholders
The Company is focused on preserving balance sheet strength and
has therefore decided to withdraw dividend payments during 2021 and
2020, given the continued uncertainty in the macro environment.
13. Reconciliation of operating profit/(loss) to operating cash
flows
Group Company
---------- ---------- ---------- ----------
2021 2020 2021 2020
$ million $ million $ million $ million
---------- ---------- ---------- ----------
Operating profit/(loss) 47.7 (231.3) (11.5) (14.3)
Share-based payments 2.4 2.8 2.4 2.8
Depletion, depreciation and
amortisation 51.4 64.5 - 0.7
Impairment (reversal)/charge (41.4) 234.8 - -
---------- ---------- ---------- ----------
Operating cash flows before
movements in working capital 60.1 70.8 (9.1) (10.8)
Decrease (Increase) in inventories 0.8 (1.5) - -
(Increase) Decrease in receivables (7.2) 19.6 0.4 (0.1)
Decrease in payables (2.2) (3.4) 2.2 (3.3)
---------- ---------- ---------- ----------
Cash generated by (used in)
operations 51.5 85.5 (6.5) (14.2)
Interest (paid) received (0.1) 0.1 - -
Other/ redundancy expense outflow (0.7) (2.7) (0.6) (2.7)
Income taxes paid (39.9) (26.5) - -
---------- ---------- ---------- ----------
Net cash from (used in) operating
activities 10.8 56.4 (7.1) (16.9)
---------- ---------- ---------- ----------
During the year, a total of $8.3m (2020: $10.2m) of trade
receivables due from EGPC in Egypt were settled by way of non-cash
offset against trade payables.
14. Assets held for sale
In December 2021, the Company announced that shareholders had
approved the farm-out of 55% of the Group's operated interest in
each of our Egyptian Concessions, El Fayum and North Beni Suef, to
IPR, a group that has extensive experience in Egypt.
As part of the transaction, IPR will fund Pharos's share of the
costs to a maximum of $33.425m (to be adjusted for working capital
and interim period adjustments from the effective economic date of
1 July 2020). This is in addition to the deposit at signing of the
farm-out agreements of US$2 million and a further US$3 million
payable on completion. This investment programme should result in
an increase in production and also fulfil commitments under the
concessions. In addition, the Group will be entitled to contingent
consideration depending on the average Brent Price each year from
2022 to the end of 2025, capped at a maximum total payment of US$20
million. We have calculated the contingent consideration using our
Brent oil price curve as at 31 December 2021 (not recognised the
full $20m).
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.
2021
$ million
----------------
Intangible assets 2.1
Property, plant and equipment - oil and gas properties
- NBV 61.6
Property, plant and equipment - other - NBV 0.4
Inventories 6.3
Trade and other receivables 2.0
Impairment charge - Assets classified as held for
sale (10.4)
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
----------------
15. Subsequent events
El Fayum Farm-out
Pharos and EGPC have finalised all necessary documents to be
presented to the Minister of Petroleum and Natural Resources to
approve the transaction with IPR and this approval is expected
shortly.
Concession Agreement Amendment El Fayum area
On 19 January 2022, the Third Amendment to the El Fayum
Concession Agreement was signed by His Excellency Eng. Tarek El
Molla (Minister of Petroleum & Mineral Resources of the Arab
Republic of Egypt), EGPC and the Company.
Signature of the Third Amendment was a key Condition Precedent
for the transfer of a 55% participating interest (and operatorship)
in the El Fayum and North Beni Suef Concessions to IPR Lake
Qarun.
Under the terms, the cost recovery percentage will be increased
from 30% to 40% allowing Pharos a significantly faster recovery of
all its past and future investments. In return, Pharos has agreed
to waive its rights to recover a portion of the past costs pool
($115m) and reduce its share of Excess Cost Recovery Petroleum from
15% to 7.5%. While in full cost recovery mode, Contractor's share
of revenue increases from 42.6% to 50.8% as from November 2020
(corresponding to additional net revenues to Contractor of $7.0m to
the date of signature).
The relevant final approvals from the Egyptian Government had
not been obtained at 31 December 2021 and so this has been
accounted as a non-adjusting balance sheet event.
Assuming conditions at 31 December 2021, the discounted cash
flows from the remaining 45% share held and calculated for
impairment purposes would increase from $49.2m to $77.4m.
16. Preliminary results announced
Copies of the announcement will be available to download from
www.pharos.energy. The Annual Report and Accounts, together with
notice of the 2022 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.
2021 2020
$ million $ million
---------- ----------
Cost of sales 114.6 123.8
Less:
Depreciation, depletion and amortisation (51.0) (63.3)
Production based taxes (10.1) (7.0)
Inventories 0.1 (2.3)
Other cost of sales (1.6) (2.9)
Cash Operating Costs 52.0 48.3
---------- ----------
Production (BOEPD) 8,878 11,373
---------- ----------
Cash operating cost
per BOE ($) 16.05 11.60
---------- ----------
Cash-operating costs per barrel by Segment (2021)
Vietnam Egypt Total
$ million $ million $ million
---------- ---------- ----------
Cost of sales 84.3 30.3 114.6
Less:
Depreciation, depletion and
amortisation (43.0) (8.0) (51.0)
Production based taxes (9.8) (0.3) (10.1)
Inventories 0.1 - 0.1
Other cost of sales (0.6) (1.0) (1.6)
Cash operating cost 31.0 21.0 52.0
---------- ---------- ----------
Production (BOEPD) 5,560 3,318 8,878
---------- ---------- ----------
Cash operating cost
per BOE ($) 15.28 17.34 16.05
---------- ---------- ----------
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.
2021 2020
$ million $ million
---------- ----------
Depreciation, depletion and amortisation (51.0) (63.3)
---------- ----------
Production (BOEPD) 8,878 11,373
---------- ----------
DD&A per BOE ($) 15.74 15.21
---------- ----------
DD&A per barrel by Segment (2021)
Vietnam Egypt Total
$ million $ million $ million
---------- ---------- ------------
Depreciation, depletion and
amortisation (43.0) (8.0) (51.0)
---------- ---------- ----------
Production (BOEPD) 5,560 3,318 8,878
---------- ---------- ------------
DD&A per BOE ($) 21.19 6.61 15.74
---------- ---------- ------------
Net Debt
Net debt comprises interest-bearing bank loans, less cash and
cash equivalents.
2021 2020
$ million $ million
---------- ------------
Cash and cash equivalents 27.1 24.6
Borrowings (1) (84.6) (57.2)
---------- ------------
Net Debt (57.5) (32.6)
---------- ------------
(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.
2021 2020
$ million $ million
---------- ---------------------
Operating profit/(loss) 48.3 (231.3)
Depreciation, depletion and amortisation 51.4 64.5
Impairment (reversal)/charge (42.0) 234.8
EBITDAX 57.7 68.0
---------- ---------------------
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.
2021 2020
$ million $ million
---------- ----------
Net Debt (57.5) (32.6)
EBITDAX 57.7 68.0
Net Debt/EBITDAX 1.00 0.48
---------- ----------
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's equity)
2021 2020
$ million $ million
---------- ----------
Total Debt (1) 84.6 57.2
Total Equity 304.4 293.7
Debt to Equity 0.28 0.20
---------- ----------
(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.
2021 2020
$ million $ million
------------ ---------------------
Net cash from operating activities 10.8 56.4
Weighted number of shares in the year 437,512,648 397,515,684
Operating cash per share 0.02 0.14
------------ ---------------------
Glossary of Terms
AGM
Annual General Meeting
bbl
Barrel
boe
Barrels of oil equivalent
boepd
Barrels of oil equivalent per day
bopd
Barrels of oil per day
CASH or cash
Cash, cash equivalent and liquid investments
CAPEX or capex
Capital expenditure
CDP
Formerly the Carbon Disclosure Project
CEO
Chief Executive Officer
CFO
Chief Financial Officer
CNV
Ca Ngu Vang field located in Block 9-2, VIetnam
Company
Pharos Energy plc
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
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
EBT
Employee benefit trust
E&E
Exploration and Evaluation
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
FFDP
Full Field Development Plan
Financial Statements
The audited financial statements of the Company and the Group
for the year ended 31 December 2021 set out on pages 22 to 37.
FPSO
Floating, Production, Storage and Offloading Vessel
G&A
General and administration
GHG
Greenhouse gas
Group
Pharos and its direct and indirect subsidiary undertakings
H&S
Health and Safety
HLHVJOC
Hoang Long and Hoan Vu Joint Operating Companies
HLJOC
Hoang Long Joint Operating Company
HSES
Health, Safety, Environmental and Security
HVJOC
Hoan Vu Joint Operating Company
IFRS
International Financial Reporting Standards
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
k
thousands
kbopd
Thousand barrels of oil per day
km
Kilometre
km(2)
Square kilometre
LTI
Lost Time Injury
LTIF
Lost Time Injury Frequency
LTIP
Long Term Incentive Plan
m
million
mmbbl
Million barrels
mmboe
Million barrels of oil equivalent
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
NED
Non-Executive Director
NPV
Net Present Value
Opex
Operational expenditure
Petrosilah
An Egyptian joint stock company held 50/50 between the
Contractor parties (being the Pharos Group and IPR Lake Qarun
following completion of the farm-down of the El Fayum concession)
and the Egyptian General Petroleum Corporation
PSC
Production sharing contract or production sharing agreement
Petrovietnam
Vietnam Oil and Gas Group
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
Shares
Ordinary Shares
SPA
Sales and Purchase Agreement
TCFD
Task Force on Climate-Related Financial Disclosures established
by the G20 Financial Stability Board
TGT
Te Giac Trang field located in Block 16-1, Vietnam
UK
United Kingdom
$
United States Dollar
GBP
UK Pound Sterling
1C
Low estimate scenario of Contingent Resources
1H
First half
1P
Equivalent to Proved Reserves; denotes low estimate scenario of
Reserves
2C
Best estimate scenario of Contingent Resources
2C Contingent Resources
Best estimate scenario of Contingent Resources
2P Reserves
Equivalent to the sum of Proved plus Probable Reserves; denotes
best estimate scenario of Reserves. Also referred to as 2P
Commercial Reserves
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