TIDMPHAR
RNS Number : 3535Z
Pharos Energy PLC
14 September 2022
14 September 2022
Pharos Energy plc
("Pharos" or the "Company" or, together with its subsidiaries,
the "Group")
Interim results for the Half-year to 30 June 2022
Pharos Energy plc, an independent oil and gas exploration and
production company, announces its interim results for the six
months ended 30 June 2022. An analyst conference call will take
place at 11.00 BS T today.
Jann Brown, Chief Executive Officer, commented:
"Our results for this half year underscore the cash generation
potential of our portfolio of assets, with operating cash flow of
$27.6m achieved. In Vietnam, further development drilling on both
TGT and CNV is due to commence imminently, with the rig on location
and preparing to spud. In Egypt, a rig on long-term contract has
been secured and is due to arrive in Q4 to continue the development
drilling programme. These activities are set to add to production
levels and cash flow in H2 and beyond.
We continue to focus our efforts on driving efficiencies,
controlling costs and making judicious investments to maximise the
value of our portfolio. The share buyback programme, which we
announced in July, continues as part of the Company's broader
strategy to deliver value to our shareholders and is expected to
run for a further four to six months.
Pharos is now in a materially improved financial position, has
an accelerating programme in Egypt and significant growth potential
in Vietnam. Together, these put us in a strong position and I am
pleased to be able to reward shareholder patience with the
announcement of a return to a regular dividend, based on operating
cash flow, with the first payment set for 2023. With our
strengthened balance sheet, a portfolio of cash generative assets
with substantial upside in both near term developments and
exploration potential plus a commitment to capital discipline, we
are well placed to create sustainable shareholder value."
Corporate Highlights
-- Signature of the Third Amendment to the El Fayum Concession
Agreement in January 2022, increasing Contractor's share of revenue
from c.42% to c.50%
-- Completion of farm-out transaction and transfer of
operatorship of Egyptian assets to IPR in March 2022, delivering
Pharos a 45% carry over its remaining interest
-- Reshaping of Board structure and composition from 9 to 6 Board members
-- Initiation of share buyback programme in July 2022, of which $1.6m has now been used
-- Commitment to achieve Net Zero GHG emissions from all our
assets by no later than 2050 announced today
-- Establishment of an Emissions Management Fund, under which we
will set aside $0.25 for each barrel sold at an oil price above
$75/bbl to support emissions management projects
Operational Highlights
-- Group working interest production 7,962 boepd net (1H 2021:
9,147 boepd) in line with full year guidance
-- Vietnam
- Production 5,861 boepd net (1H 2021: 5,429 boepd net)
- Drilling of first of two TGT development wells due to commence
- Work on submission of TGT & CNV licence extension requests progressing within the JOCs
- Work ongoing to progress well planning and to secure a partner
before drilling the commitment well on Block 125 in 2023
-- Egypt
- Production 2,101 bopd (*) (1H 2021: 3,718 bopd)
- Development activities continues in El Fayum, targeting recovery of c.17 Mbbl 2P
- Four wells on production in the period
- Drilling rig secured on long-term contract
- North Beni Suef (NBS) first exploration commitment well planned for Q4 2022
Financial Highlights
-- Group revenue $129.6m(**) prior to hedging losses of $17.3m
(1H 2021: $72.9m(**) prior to hedging losses of $13.7m)
-- Net profit of $54.3m (1H 2021: $6.4m profit), including
non-cash impairment reversal after tax of $49.2m (1H 2021:
impairment reversal after tax $19.4m)
-- Cash generated from operations $57.0m(1) (1H 2021: $18.2m)(1)
-- Operating cash flow $27.6m(4) (1H 2021: 0.1m)
-- Cash operating costs $15.82/bbl(2) (1H 2021: $14.74/bbl)(2)
-- Cash balances as at 30 June 2022 of $47.5m (30 June 2021: $28.4m)
-- Forecast cash capex for the full year c.$29m of which $14.9m
had been incurred by 30 June 2022
-- Net debt as at 30 June 2022 of $37.9m(2,3) (30 June 2021: $32.9m)(2)
-- Net debt to EBITDAX of 0.51x (2) (1H 2021: 1.26x) (2)
(*) The farm-out transaction and transfer of operatorship of
Pharos' Egyptian assets to IPR completed on 21 March 2022. Working
interest production for Egypt is therefore reported as 100% through
to completion and 45% thereafter
(**) Egyptian revenues are given post government take including
corporate taxes
(1) Stated after realised hedging loss of $17.3m (1H 2021: loss
of $13.7m)
(2) See Non-IFRS measures at page 32
(3) Includes RBL and National Bank of Egypt working capital
drawdown
(4) Operating cash flow = Net cash from operating activities, as
set out in the Cash Flow Statement
Outlook
-- 2022 full year Group working interest production guidance
remains unchange d at 6,350 - 7,800 boep d net
-- Vietnam
- 2022 production guidance range unchanged at 5,000 - 6,000 boepd net
- Three well drilling programme, including two development wells
at TGT and one development well at CNV, is on track to commence
with the rig on location at TGT
- Work ongoing to progress well planning, with discussions
ongoing to secure a partner ahead of drilling the commitment well
on Block 125 in 2023
-- Egypt
- 2022 production guidance range unchanged at 1,350 - 1,800 bopd
(equivalent to gross production of 3,000 - 4,000 bopd)
- Rig secured on a long-term contract due to start in
mid-October 2022, focusing on ramping up activities in El Fayum
from developed resource base
- Progressing work on conventional and unconventional
exploration prospects to further enhance the value of our
acreage
- NBS commitment well due to be drilled in Q4 2022
- Request for an extension to the NBS exploration period has been submitted to EGPC
-- Net Zero commitment on all assets by 2050, detailed roadmap coming in 2023
-- Recommending recommencement of regular dividend payments
starting in 2023, subject to shareholder approval at AGM 2023,
returning no less than 10% of Operating Cash Flow (OCF)
Enquiries
Pharos Energy plc Tel: 020 7747 2000
Jann Brown, Chief Executive Officer
Sue Rivett, Chief Financial Officer
Camarco Tel: 020 3757 4980
Billy Clegg | Georgia Edmonds | Rebecca Waterworth
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, Pharos holds a 45% working
interest share in the El Fayum Concession in the Western Desert,
with IPR Lake Qarun, part of the international integrated energy
business IPR Energy Group, holding the remaining 55% working
interest. The El Fayum Concession produces oil from 10 fields and
is located 80 km southwest of Cairo. It is operated by Petrosilah,
a 50/50 joint stock company between the contractor parties (being
IPR Lake Qarun and Pharos) and the Egyptian General Petroleum
Corporation (EGPC). Pharos also holds a 45% working interest share
in the North Beni Suef (NBS) Concession in Egypt, which is located
immediately south of the El Fayum Concession. IPR Lake Qarun
operates and holds the remaining 55% working interest in the NBS
Concession. In Vietnam, Pharos has a 30.5% working interest in
Block 16-1 which contains 97% of the Te Giac Trang (TGT) field and
is operated by the Hoang Long Joint Operating Company. Pharos'
unitised interest in the TGT field is 29.7%. Pharos also has a 25%
working interest in the Ca Ngu Vang (CNV) field located in Block
9-2, which is operated by the Hoan Vu Joint Operating Company.
Blocks 16-1 and 9-2 are located in the shallow water Cuu Long
Basin, offshore southern Vietnam. Pharos also holds a 70% interest
in, and is designated operator of, Blocks 125 & 126, located in
the moderate to deep water Phu Khanh Basin, north east of the Cuu
Long Basin, offshore central Vietnam. In July 2022 Capricorn, Ratio
and Pharos reached agreement to relinquish the Israeli licences,
and Capricorn as operator has informed the Israeli Ministry of
Energy of the parties' intention.
Operational Review
Vietnam
Vietnam Production
Production for the first half of 2022 from the TGT and CNV
fields net to the Group's working interest averaged 5,861 boepd (1H
2021: 5,429 boepd), in line with our previously published guidance
of 5,000-6,000 boepd.
TGT 1H 2022 production averaged 15,133 boepd gross and 4,490
boepd net to Pharos (1H 2021: 13,401 boepd gross and 3,976 boepd
net). CNV 1H 2022 production averaged 5,483 boepd gross and 1,371
boepd net to Pharos (1H 2021: 5,813 boepd gross and 1,453 boepd
net).
Vietnam Development and Operations .
Velesto's Naga 3 rig has been contracted for this year's
drilling program, which includes the two development wells at TGT
and one CNV well.
On Block 16-1 - TGT Field, the drilling programme for two
development wells in H2 2022 is due to commence with the rig on
location at TGT.
On Block 9-2 - CNV Field, one development well is planned in H2
2022. The revised field development plan, including the additional
well, was approved by the Vietnam Ministry of Industry and Trade on
19 April 2022.
Work on the submission of licence extension requests for both
TGT & CNV is progressing within the JOCs.
Vietnam Exploration
On Block 125, the 3D seismic processing is substantially
complete and the ongoing interpretation of this data has resulted
in the mapping of a variety of interesting Leads in this relatively
unexplored basin, with further work needed to refine them into
Prospect sizes pre-drill. Well location(s) will be presented to the
Management Committee in December 2022. Well planning has started to
meet the timeline of drilling in H2 2023, and we are already in
discussions with a number of parties interested in farming in to
support the funding of this commitment well.
Vietnam outlook & operational focus for remainder of
2022
-- Vietnam
- 2022 production guidance range remains unchanged at 5,000 - 6,000 boped net.
- Three well drilling programme, including two development wells
at TGT and one development well at CNV, is on track to commence
with the rig on location at TGT
- Work ongoing to progress well planning and to secure a partner
before drilling the commitment well on Block 125 in 2023.
Egypt
El Fayum Production
The transaction with IPR and transfer of operatorship completed
on 21 March 2022. Working interest production is therefore reported
as 100% through to completion of the farm-out and 45%
thereafter.
Production for the first half of 2022 from El Fayum averaged
3,142 bopd gross (1H 2021: 3,718 bopd) and 2,101 bopd net to
Pharos.
El Fayum Development and Operations
The multi-well development drilling in El Fayum continues. Four
wells have been put on production in the period to 30 June 2022
(including one well drilled in 2021), two more wells drilled after
30 June 2022 are currently being completed, and two to three
additional wells are planned before year end, subject to rig
scheduling. IPR is focusing on ramping up drilling and workover
activities, focusing on waterflood implementation and securing
long-lead items to minimize supply chain interruption.
Petrosilah, the El Fayum joint operating company (JOC), secured
a rig on a long-term contract in July, one year firm plus an option
for a second year, starting in mid-October 2022. The new rig will
allow a continuous drilling campaign which is essential to adding
new barrels to production as well as providing a stable platform
for additional drilling activities.
The rig currently in use will be released some time in Q4 2022,
allowing a short time of overlap between the two rigs.
In addition, one workover rig continues to contribute to
production through low-cost well repairs and recompletions and a
second workover rig will be added in Q4 2022.
North Beni Suef (NBS)
Planning for the commitment well due to be drilled in Q4 2022 is
advancing, and the request for a short extension to the exploration
period has been submitted to EGPC. This extension will give us
additional time to drill high-ranked prospects, including all work
programme commitments. Several prospects have been identified from
the existing 3D seismic and c.110 km(2) of additional 3D seismic is
planned to be acquired in Q1 2023.
Egypt outlook & operational focus for remainder of 2022
-- Egypt
- 2022 production guidance unchanged at 1,350-1,800 bopd,
equivalent to gross production of 3,000-4,000 bopd
- Rig secured on a long-term contract due to start in
mid-October 2022, focusing on ramping up activities in El Fayum
from developed resource base
- Progressing work on conventional and unconventional
exploration prospects to further enhance the value of our
acreage
- NBS commitment well due to be drilled in Q4 2022
- Request for an extension to the NBS exploration period has been submitted to EGPC
Israel
Following completion of the seismic processing in order to
mature prospectivity ahead of a drilling decision, Capricorn as the
operator along with the JV partners, has informed the Ministry of
Energy of the JV's intention to relinquish the licences.
Health, Safety & ESG
Health and Safety
Safety continues to be the top priority for our business, and we
are committed to operating safely and responsibly at all times and
to providing a safe and healthy working environment for staff and
contractors. We work closely with our JV/JOC partners to ensure
work safety practices are adhered to. We provide regular training
and conduct test exercises to ensure the workforce remains updated
and prepared at all times.
We are pleased to report that in Egypt and Vietnam, we have
worked with our partners to maintain our record of zero Lost Time
Injury (LTI) frequency rate through the first half of 2022.
Unfortunately, there were two recent incidents involving
sub-contractors that occurred in Q3 2022 and which are under
investigation.
ESG
The management of our Greenhouse Gas (GHG) Emissions remains a
key issue for the Group. We continue our journey to implementing
the TCFD recommendations and, during the first half of 2022, Pharos
carried out physical climate and transition risk analyses to
identify risks / opportunities for the business under different
climate scenarios and pathways.
Today, we formalise our commitment to achieve Net Zero Scope 1
and Scope 2 GHG emissions from our assets by no later than 2050.
Further details of this commitment can be found in the Corporate
Review section on page 13.
Social Engagement
Pharos remains committed to creating value in a sustainable
manner for host countries and local communities. We continue to
invest in long-term social projects through the HLHVJOC Charitable
Donation programme. For 2022, 11 charitable projects have been
approved, ranging from providing healthcare and educational support
for children with disabilities to supporting local communities in
areas hit hardest by flash flooding and COVID-19, with 4 projects
already completed in H1 2022 and 7 more to be completed in the
latter half of the year. In Q1 2022, the Group provided financial
support to help children unfortunately orphaned by the COVID-19
pandemic. In Q2 2022, the Donation programme helped fund the
physical improvement education programme for children with
disabilities. We work closely with our local and joint venture
partners and joint ventures in order to make sure that our social
initiatives bring positive impacts to the region, and will keep
stakeholders updated on progress.
Principal and Emerging risks and Uncertainties for the second
half of 2022
The Board continues to fulfil its role in risk oversight by
developing policies and procedures around risks that are consistent
with the organization's strategy and risk appetite, taking steps to
foster risk awareness and encouraging a company culture of risk
adjusting awareness throughout the Group.
The Group risk management activity in H1 2022 focused on the
ramifications of the ongoing war in Ukraine with increased
uncertainties and volatilities on world commodity markets and the
ensuing Western sanctions on Russia and vice versa which have
negatively impacted on the recoveries of many economies,
particularly Egypt. This activity has included the formation of a
dedicated cross-functional working group, regular risk management
reporting and the adoption of a new Group sanctions policy. At an
operational level, the Group has closely worked with JOCs to
develop contingency planning in a number of hypothetical scenarios.
The key principal and emerging risks are:
-- Prolonged War in Ukraine / ensuing sanctions*
-- Risks of rising inflation and stagflation*
-- Inability to repatriate cash earned from Egypt*
-- Further devaluation of the Egyptian pound*
-- Legal risks - Sanctions related*
-- Vietnam Licence Extension*
-- Farm in for 125/126*
-- Climate Change
-- Commodity Price volatility
-- Volatility in Production level
-- HSES
-- Partners' alignment
-- Sub-optimal capital allocation
-- Political and Regional
*New/emerging risks identified at HY 2022.
Financial Review
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.
Following recommencement of investment in Vietnam during 2021 and
the additional liquidity provided by our farm-in partner in Egypt
after successful completion of the transaction with IPR in March
2022, supported by the improved oil prices, we are on track to
deliver strong positive cash flow generation and growth in value in
2022.
Highlights
1H 2022 1H 2021
Production Volumes (boepd) 7,962 9,147
Production Volumes - Vietnam
(boepd) 5,861 5,429
Production Volumes - Egypt (boepd)(3) 2,101 3,718
Oil Price Realised ($/bbl) 109.47 64.76
Oil & Gas Price Realised ($/boe) 99.49 57.47
Oil & Gas Sales ($m) 129.6 72.9
Total Revenue ($m)(1) 112.3 59.2
Gross Profit ($m) 52.4 7.7
Operating profit ($m) 110.2 30.0
Operating profit excluding impairment
(reversal)/charge ($m)(2) 47.4 2.2
Cash operating cost per ($/boe)(2) 15.82 14.74
---------------------------------------
Net debt ($/m)(2) 37.9 32.9
EBITDAX ($/m)(2) 75.0 26.1
Gearing(2) 0.24 0.20
======================================= ======== ========
(1) Stated after realised hedging loss of $17.3m (1H 2021: loss
of $13.7m)
(2) See Non-IFRS measures at page 32
(3) From 21 March 2022 includes 45% Pharos share of production;
1H 2022 100% production: 3,142 boepd
Cash operating cost per 1H 1H
barrel* 2022 2021
$m $m
----------------------------- ------ ------
Cost of sales 59.9 51.5
----------------------------- ------ ------
Less
----------------------------- ------ ------
Depreciation, depletion
and amortisation (27.6) (23.6)
----------------------------- ------ ------
Production based taxes (8.8) (4.4)
----------------------------- ------ ------
Export duty (3.2) -
----------------------------- ------ ------
Inventories 5.1 1.7
----------------------------- ------ ------
Other cost of sales (1.1) (0.8)
----------------------------- ------ ------
Trade Receivable risk factor
provision (1.5) -
----------------------------- ------ ------
Cash operating costs 22.8 24.4
----------------------------- ------ ------
Production (BOEPD) 7,962 9,147
----------------------------- ------ ------
Cash operating cost per
BOE ($) 15.82 14.74
----------------------------- ------ ------
Cash operating cost Vietnam Egypt Egypt Egypt Total
per barrel by Segment
Up to From Total
20/03/22 21/03/22
(1) to 30/06/22
(1)
$m
$m $m $m $m
------------------------ -------- ---------- ------------- ------- ------
Cost of sales 50.0 4.9 5.0 9.9 59.9
------------------------ -------- ---------- ------------- ------- ------
Less
------------------------ -------- ---------- ------------- ------- ------
Depreciation, depletion
and amortisation (25.9) (0.6) (1.1) (1.7) (27.6)
------------------------ -------- ---------- ------------- ------- ------
Production based taxes (8.7) (0.0) (0.1) (0.1) (8.8)
------------------------ -------- ---------- ------------- ------- ------
Export duty (3.2) - - - (3.2)
------------------------ -------- ---------- ------------- ------- ------
Inventories 5.1 - - - 5.1
------------------------ -------- ---------- ------------- ------- ------
Other cost of sales (0.8) (0.2) (0.1) (0.3) (1.1)
------------------------ -------- ---------- ------------- ------- ------
Trade Receivable risk
factor provision - (0.5) (1.0) (1.5) (1.5)
------------------------ -------- ---------- ------------- ------- ------
Cash operating costs 16.5 3.6 2.7 6.3 22.8
------------------------ -------- ---------- ------------- ------- ------
Production (BOEPD) 5,861 2,857 1,513 2,101 7,962
------------------------ -------- ---------- ------------- ------- ------
Cash operating cost
per BOE ($) 15.55 15.94 17.31 16.57 15.82
------------------------ -------- ---------- ------------- ------- ------
(1) movements from 1 January 2022 up to 20/03/22 are 100% share
and from 21/03/22 includes 45% Pharos share. 100% cash operating
costs for period from 21/03/22 to 30/06/22 amounts to $6.0m and
100% Cash operating cost per BOE is $17.49.
Cash flows and accounting for Egypt
Following the completion of the farm-out transaction of Egyptian
assets to IPR, the accounting for the assets reflect the
following:
The effective date of the transaction was 1 July 2020, with
completion on 21 March 2022.
Pharos owned and managed the business up to completion. On
completion an adjustment to compensate IPR for 55% of net cash
flows, revenue offset by costs since the effective date has been
adjusted for in the level of carry to be provided by IPR to
Pharos.
In the financial statements, for the period post completion,
Pharos' 45% share of field costs - capex, opex and G&A - are
accounted for as incurred by Pharos, although all such costs are
paid by IPR and set off against the carry. Please see Note 15 on
page 30 for more details on the disposal of asset held for
sale.
All revenues earned are paid direct to Pharos.
Operating Performance
Revenue
Oil & gas sales for the period were up 78% to $129.6m (1H
2021: $72.9m). The Group revenues in the period were reduced by
hedging losses of $17.3m (1H 2021: $13.7m losses).
Revenue for Vietnam increased 84% to $103.8m (1H 2021: $56.3m).
The average realised crude oil price was $111.50/bbl (1H 2021:
$66.47/bbl), a 68% increase. The premium to Brent increased
marginally, representing just over $3/bbl (1H 2021: $2/bbl).
Production increased from 5,429 boepd to 5,861 boepd.
The increased revenue for Egypt of $25.8m (1H 2021: $16.6m) in
part was as a result of invoicing for an additional $7m following
approval of the third amendment to the El Fayum Concession
agreement which increased the cost recovery from 30% to 40% from
November 2020. The higher average realised crude oil price, up 67%
to $99.57/bbl (1H 2021: $59.70/bbl), was offset by lower average
production levels, from 3,718 bopd to 2,101 bopd (from 21 March
2022 includes 45% Pharos share of production; 1H 2022 100%
production 3,142). 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 (the
in-country regulator) and combined increased marginally to nearly
$6/bbl (1H 2021: $5/bbl).
Group operating costs, DD&A and expenses
Cash operating costs at Group level, defined in the Non-IFRS
measures section on page 32, amounted to $22.8m (1H 2021: $24.4m) a
7% decrease over the same period last year. On a barrel of oil
equivalent basis, this was $15.82/boe (1H 2021: $14.74/boe).
Cash operating costs in Vietnam increased to $16.5m (1H 2021:
$15.3m) in the period which equates to $15.55/bbl (1H 2021:
$15.57/bbl). The increase is due to higher costs relating to the
FPSO as a result of lower TLJOC production (TLJOC has 11.5% cost
share in 1H 2022 compared to 27.5% in 1H 2021) throughput which
increased Pharos' share of the costs.
Cash operating costs in Egypt were $6.3m (1H 2021: $9.1m) in the
period, which equate to $16.57/bbl (1H 2021: $13.52/bbl). Cash
operating costs from 1 January 2022 up to 20/03/22 are 100% share
and from 21/03/22 includes 45% Pharos share. The increase in cash
operating costs relates largely to higher variable cost as a result
of an upsurge in the fuel price offset by the devaluation of EGP
against the US dollar in comparison to 1H 2021.
DD&A charges on production and development assets increased
to $27.6m (1H 2021: $23.6m), driven by higher production from
Vietnam combined with a higher depreciating cost base following
2021 impairment reversals taken on both Vietnam and Egypt. DD&A
per bbl is currently $19.15/boe (1H 2021: $14.25/boe).
Administrative expenses of $5.0m (1H 2021: $5.5m) are lower than
the comparative period due to the restructuring that took place in
2021. After adjusting for the non-cash items such as depreciation
and IFRS 2 Share Based Payments of $0.9m (1H 2021: $1.5m), the
administrative expense is $4.1m (2021: $4.0m). Following completion
of the farm down to IPR in March and the AGM in May the Board was
reduced from 9 to 6. The remaining non-executives' fees were
restated to the levels prior to the reductions taken during 2020
and 2021. As previously noted in the 2021 Annual Report &
Accounts, the incoming CEO took a 21% reduction in base salary on
assuming the role.
Impairment Reversals
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. The results of these impairment tests
are summarised below. For each producing property, the recoverable
amount has been determined using the value in use method which
constitutes a level 3 valuation within the fair value hierarchy.
The recoverable amount is supported by the fair value derived from
a discounted cash flow valuation of the 2P production profile.
Summary of Impairments TGT CNV Egypt Total
- Oil and Gas properties $m $m $m $m
---------------------------- ------ ----- ----- ------
1H 2022
---------------------------- ------ ----- ----- ------
Pre-tax impairment reversal 24.8 13.6 24.5 62.9
---------------------------- ------ ----- ----- ------
Deferred tax charge (8.6) (5.1) - (13.7)
---------------------------- ------ ----- ----- ------
Post-tax impairment reversal 16.2 8.5 24.5 49.2
---------------------------- ------ ----- ----- ------
Reconciliation of carrying
amount: (1)
---------------------------- ------ ----- ----- ------
As at 1 Jan 2022 266.0 84.2 49.2 399.4
---------------------------- ------ ----- ----- ------
Additions 0.5 0.2 6.7 7.4
---------------------------- ------ ----- ----- ------
Changes in decommissioning
asset (2) (8.7) (1.7) - (10.4)
---------------------------- ------ ----- ----- ------
DD&A (20.6) (5.3) (1.7) (27.6)
---------------------------- ------ ----- ----- ------
Impairment reversal 24.8 13.6 24.5 62.9
---------------------------- ------ ----- ----- ------
As at 30 Jun 2022 262.0 91.0 78.7 431.7
---------------------------- ------ ----- ----- ------
1H 2021
---------------------------- ------ ----- ----- ------
Pre-tax impairment reversal 21.9 2.2 3.7 27.8
---------------------------- ------ ----- ----- ------
Deferred tax charge (7.6) (0.8) - (8.4)
---------------------------- ------ ----- ----- ------
Post-tax impairment reversal 14.3 1.4 3.7 19.4
---------------------------- ------ ----- ----- ------
Reconciliation of carrying
amount: (1)
---------------------------- ------ ----- ----- ------
As at 1 Jan 2021 239.3 91.2 104.1 434.6
---------------------------- ------ ----- ----- ------
Additions 0.7 0.2 3.3 4.2
---------------------------- ------ ----- ----- ------
Changes in decommissioning
asset (2) (2.7) (0.9) - (3.6)
---------------------------- ------ ----- ----- ------
DD&A (14.4) (5.0) (4.2) (23.6)
---------------------------- ------ ----- ----- ------
Impairment reversal 21.9 2.2 3.7 27.8
---------------------------- ------ ----- ----- ------
As at 30 Jun 2021 244.8 87.7 106.9 439.4
---------------------------- ------ ----- ----- ------
(1) Eg ypt carrying value reflects 45% share (1H 2021:
100%).
(2) Changes in decommissioning asset for TGT is due to changes
in discount rate and the field abandonment plan, whereas CNV
reflects the change in discount rate only (1H 2021: change in
discount rate only for both TGT and CNV)
It should be noted that the TGT impairment reversal at 1H 2022
has been restricted to reflect the remaining balance of historic
impairment charges previously recorded against the field. The
impairment reversal test calculated NPV13 of $218.9m which would
have been a pre-tax reversal of $67.2m, but this was restricted to
$24.8m. Further details of these impairment charges, including key
assumptions in relation to oil price and discount rate are provided
in Note 10 of the interim financial statements.
Hedging
Our hedging positions for the period resulted in a realised loss
of $17.3m (1H 2021: loss of $13.7m) as the Brent price improved
from $73 to $123 during 1H 2022. Additionally, the fair value as at
30 June 2022 was an unrealised loss of $11.3m for the remaining
hedges in place (1H 2021: unrealised loss of $12.4m). The Group is
required to hedge 35% of the RBL Vietnam production as part of the
agreement. Approximately 30% of the Group's forecast production
representing 36% of Vietnam's production until June 2023, is hedged
at an average price of $67.0/bbl (1H 2021: cover was 27% of the
Group's forecast production and 37% of Vietnam's production from
July 2021 to June 2022 securing a minimum price for this hedged
volume of $55.6/bbl).
Please see below a summary of hedges outstanding as at 30 June
2022.
3Q22 4Q22 1Q23 2Q23 3Q23 4Q23
====================== ====== ====== ======= ======= ======= =======
Production hedge per
quarter - 000/bbls 150 150 180 180 30 30
====================== ====== ====== ======= ======= ======= =======
Min. Average value
of hedge - $/bbl 69.09 69.09 65.33 65.33 65.00 65.00
====================== ====== ====== ======= ======= ======= =======
Max. Average value
of hedge - $/bbl 78.17 78.17 102.88 102.88 115.20 115.20
====================== ====== ====== ======= ======= ======= =======
Financing costs
Finance costs for the period were $5.6m (1H 2021: $2.9m) mainly
related to amortisation of capitalised borrowing costs of $2.0m,
inclusive of a one-off charge of $0.7m following a change in
estimated future cash flows (1H 2021: $1.0m), interest expense
payable and similar fees of $2.4m (1H 2021: $1.8m) and unwinding of
discount of provisions $0.5m (1H 2021: $0.3m).
Taxation
The overall net tax charge of $43.9m (1H 2021: $20.3m) relates
to tax charges in Vietnam of $30.2m plus the deferred tax charge on
impairment reversal of $13.7m (1H 2021: Vietnam tax charges of
$11.9m plus the deferred tax charge of $8.4m).
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 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.
Net profit
A net profit was recorded for the period from continuing
operations of $54.3m, which is after $49.2m post-tax impairment
reversal on PPE and $(0.1)m impairment of intangibles in Israel (1H
2021: profit $6.4m includes $19.4m post-tax impairment reversal on
PPE).
Balance Sheet
Net cash/debt
As at the balance sheet date, $85.4m (RBL $77.8m and NBE $7.6m)
was drawn under the Group's borrowing facilities and there was cash
of $47.5m, giving a net debt figure of $37.9m (1H 2021: RBL $61.3m
and NBE $nil; cash $28.4m and net debt of $32.9m). Gearing has been
calculated as total debt to equity of 0.24x (1H 2021: 0.20x).
We have had a solid record in receiving cash in Egyptian Pound
(EGP) and US Dollars (USD) as well as offsets of creditors against
our receivable position with EGPC since our acquisition of the
Egyptian asset in 2019. As at 30 June 2022, the trade receivables
with EGPC stood at $14.9m (31 Dec 21: $7.4m). However, with the
recent global macroeconomic volatility, which has seen both a
devaluation of the EGP and restrictions on outgoing USD transfers
by the Central Bank of Egypt, we have experienced a slowdown in
recovery and little scope for offset against creditors. Whilst we
are able to recover the receivable in EGP, we have no real
requirement other than the local office and staff costs. We are
therefore holding the receivable balance in USD to avoid being
caught by the current devaluation of the EGP. We continue to
request USD from EGPC which is the currency in which they should
settle the invoices, in accordance with the Concession Agreement,
and have received small payments in USD in the last few weeks. In
the event of any delay in our El Fayum invoices being paid, we have
access to our facility with the National Bank of Egypt (NBE), which
allows us to draw down 60% of the value of each invoice in USD. The
amount drawn under the NBE facility as at 30 June 2022 was $7.5m,
which is included in our net debt calculation. We will continue to
closely monitor our working capital position across the Group with
a view to expediting cash conversion and will keep the market
updated on progress.
Borrowings
Reserve Based Lending (RBL)
The RBL is secured over the Vietnam producing assets only and,
after the refinancing in July 2021, as at 30 June 2022 had a
four-year term maturing in July 2025. The borrowing base as at 30
June 2022 was $77.8m (1H 2021: $56.3m).
See Non-IFRS measures at page 32.
Uncommitted Revolving Credit Facility (National Bank of Egypt -
NBE)
The amount repayable under the agreement at 30 June 2022 was
$7.6m (30 June 2021: $5.0m) and it is presented as borrowings under
current liabilities.
In May 2022, Pharos renegotiated the uncommitted revolving
credit facility for discounting (with recourse) of up to $18m,
limited to 60% of outstanding receivables (1H 2021: $20m).
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 continue to recognise the receivables in their
entirety in its balance sheet.
Cash flow
Cash generated from operations was $57.0m (1H 2021: $18.2m) and
prior to working capital movements was $75.8m (1H 2021: $27.1m).
Stripping out the impact of the hedging positions to the underlying
operations numbers gives a total of $93.1m (1H 2021: $40.8m), which
is in line with the significant improvement that we see in
commodity prices, partially offset by the Group production decrease
period on period.
The increase in receivables was $10.4m for the period (1H 2021:
increase of $5.4m). The movement is mainly driven by $7m additional
invoice following the third amendment to the El Fayum Concession
agreement. The remaining increase is commodity price driven, from
YE21 the average oil price realised has increased from $70.95/bbl
to $109.47/bbl therefore increasing the receivables balance held at
half-year. (1H 2021: the average oil price realised from YE20
increased from $44.70/bbl to $64.76/bbl therefore increasing the
receivables balance held at half-year).
Capital allocation
Following a period of improved commodity prices and a
strengthening of the Group's liquidity position, we are able to
turn our thoughts to shareholder returns in the form of both share
buybacks and dividends. We announced a small share buyback
programme in July 2022 of $3m, of which $1.6m has been committed.
Based on progress to date, we expect to complete the programme in
the fourth quarter this year. We are also announcing our intention
to return to paying dividends based on the Company's 2022 full year
results and set out our framework below.
The forecast Group cash capital expenditure for the year remains
at $29m net after $15m carry in the Egypt drilling campaign and a
return to drilling in Vietnam with two wells on TGT and one on
CNV.
Dividend Framework
We aim to recommence dividend payments starting in 2023. Our
policy is now set at returning no less than 10% of Operating Cash
Flow (OCF).
OCF has been selected as the most appropriate measure as it
automatically takes account of:
-- swings in Brent price;
-- tax, which is the main form of government take in Vietnam; and
-- working capital movements.
The first dividend will be a final dividend for the 2022
financial year and will be paid in full following approval of the
shareholders at the Company's AGM in 2023. Going forward, we expect
the payment pattern will move to a conventional pattern of an
interim and a final dividend.
Liquidity risk management and going concern
The Group closely monitors its liquidity risk. Cash forecasts
are regularly produced, and stress tested for a number of scenarios
including a downturn in the oil price, changes in production rates,
operating costs and capital expenditure. In the current environment
of volatile, although strengthen oil prices and continued economic
uncertainties created by the Ukraine war and rising inflation,
scenario planning continues to be extensive. Accordingly, stress
tests have been run for oil prices down to $63/bbl in October 2022,
rising gradually over a year until in line with our base oil price
curve, concurrent with reductions in Vietnam and Egypt production
compared to our base case of 5%. As at 30 June 2022, the Group had
a cash balance of $47.5m and the forecasts show that the Group will
have sufficient financial headroom for the period of 12 months from
the date of approval of these half-year results. The Directors
therefore have a reasonable expectation that the Company has
adequate resources to continue in operational existence for the
foreseeable future. Thus, they continue to adopt the going concern
basis of accounting in preparing these half year results.
Sue Rivett
Chief Financial Officer
Corporate Review
Purpose
The oil and gas industry is in a period of transition as the
drive to reduce emissions globally combines with each nation's
efforts to secure the energy needed for the prosperity of its own
citizens. It is likely that global demand for energy from
hydrocarbons will remain strong for some years to come and it is
therefore vital that oil and gas assets are managed in a
responsible and transparent manner, for the benefit of the local
economies, businesses, communities and families. The use of oil and
gas in developing economies, particularly where it replaces coal,
can provide the energy needed to drive GDP growth as a foundation
for long-term economic and social benefits. In this way, our goal
is to contribute to create sustainable prosperity and value for all
of our stakeholders: investors, host countries, business and
communities.
ESG
1. Our commitment to Net Zero Emissions on all assets
Today, we are formalising a commitment to achieve Net Zero GHG
emissions from all our assets by no later than 2050. This Net Zero
target underscores the principle that sustainability is a key value
in our purpose and business strategy.
Our Net Zero target includes Scope 1 (direct) and Scope 2
(indirect) emissions from all our assets. In addition, our Net Zero
target applies to our existing as well as our future assets. As we
evaluate any potential development of our business, such as licence
extensions and acquisitions, we will take this commitment into
account in our decision-making and it will fall under our Net Zero
target.
We will look to advance our Net Zero target date which will
depend on achieving operational efficiencies, reducing flaring and
venting, replacing the power consumption of our facilities with
less impactful energy sources and eventually procuring nature-based
carbon offset projects for hard-to-abate, residual emissions. This
will require investment by Pharos and its operational partners,
which is why we are today establishing an Emissions Management
Fund. For every barrel sold at an oil price above $75, we will set
aside $0.25 into this Fund. The intended purpose of the fund is to
provide support for emissions management projects for Pharos and
our operational partners in line with our climate goals.
Today we also pledge to publish a detailed Net Zero roadmap in
2023. This will include the following:
- A baseline emissions inventory for all our assets
- Asset-level emission reduction frameworks
- Interim targets over the short and medium term
- Capital expenditure and resourcing to achieve targets
We recognise that the journey to Net Zero will not be
straightforward, for Pharos and for the wider industry, with a
stream of new ideas and solutions emerging to be tested. As new
technologies become established, they will be reviewed and brought
into use where relevant. We are committed to transparency in our
reporting and to keeping stakeholders updated on our progress.
We also recognise that the support of host governments, state
oil companies and regulators is key to push this agenda forward. We
will work with our host governments where they seek to use oil
revenues to promote sustainable and inclusive economic development,
and we stand ready to support actions that they take to manage
climate change and achieve their COP commitments.
We intend to keep our Net Zero commitment under review to align
with emerging best practice methodologies informed by climate
science a nd to accelerate our Net Zero timeline if possible .
2. Climate strategy
Our climate strategy includes providing responsible stewardship,
focusing on improving equipment efficiency to reduce power
consumption and emissions, as well as extending life of existing
fields though reservoir management, licence extensions and
appropriate investments. For hard to abate emissions, we will
target offset projects that can be developed and produced cost
effectively, responsibly and in support of multiple UN Sustainable
Development Goals.
Outlook
Our business remains focussed on creating value and near term
cash flow from our asset base. We look to maximise value from these
assets through ongoing efficiency drives, a close eye on the cost
base and capital allocation which targets returns well in excess of
the cost of capital.
Our capital allocation policy has always been founded on the
inclusion of cash returns to shareholders and we have recommenced
these in July 2022 with a share buyback programme.
Our current priorities, in terms of balance sheet management,
are to ensure that there is sufficient cover for upcoming work
programme commitments plus a level of liquidity immediately
available to the Group, to reinforce our resilience and ability to
withstand future oil price downturns.
In the current oil price environment, the levels of cash
generation are sufficient for us to resume regular dividend
payments in 2023, following approval at the next AGM. Alongside our
ongoing programme of responsible investment, we will continue to
review the value accretion offered by share buybacks and are
delighted to be in a position to recommence dividends no later than
mid-2023.
Jann Brown
Chief Executive Officer
Responsibility Statement
The Directors confirm that to the best of their knowledge:
1. The interim condensed consolidated set of financial
statements immediately following this report has been prepared in
accordance with United Kingdom adopted International Accounting
Standard IAS 34 'Interim Financial Reporting' and gives a true and
fair view of the assets, liabilities, financial position and profit
or loss of the Company; and
2. The interim report includes a fair review of the information required by:
-- DTR 4.2.7R of the Disclosure Guidance and Transparency Rules,
being an indication of important events that have occurred during
the first six months of the financial year and their impact on the
condensed consolidated set of financial statements; and a
description of the principal risks and uncertainties for the
remaining six months of the year; and
-- DTR 4.2.8R of the Disclosure Guidance and Transparency Rules,
being related party transactions that have taken place in the first
six months of the current financial year and that have materially
affected the financial position or performance of the entity during
that period; and any changes in the related party transactions
described in the last annual report that could do so.
INDEPENT REVIEW REPORT TO PHAROS ENERGY PLC
Conclusion
We have been engaged by the company to review the condensed set
of financial statements in the half-yearly financial report for the
six months ended 30 June 2022 which comprises the condensed
consolidated income statement, the condensed consolidated
statements of comprehensive income, the condensed consolidated
balance sheets, the condensed consolidated statements of changes in
equity, the condensed consolidated cash flow statements and related
notes 1 to 16.
Based on our review, nothing has come to our attention that
causes us to believe that the condensed consolidated set of
financial statements in the half-yearly financial report for the
six months ended 30 June 2022 is not prepared, in all material
respects, in accordance with United Kingdom adopted International
Accounting Standard 34 and the Disclosure Guidance and Transparency
Rules of the United Kingdom's Financial Conduct Authority.
Basis for Conclusion
We conducted our review in accordance with International
Standard on Review Engagements (UK) 2410 "Review of Interim
Financial Information Performed by the Independent Auditor of the
Entity" issued by the Financial Reporting Council for use in the
United Kingdom (ISRE (UK) 2410). A review of interim financial
information consists of making inquiries, primarily of persons
responsible for financial and accounting matters, and applying
analytical and other review procedures. A review is substantially
less in scope than an audit conducted in accordance with
International Standards on Auditing (UK) and consequently does not
enable us to obtain assurance that we would become aware of all
significant matters that might be identified in an audit.
Accordingly, we do not express an audit opinion.
As disclosed in note 2, the annual financial statements of the
Group are prepared in accordance with United Kingdom adopted
international accounting standards. The condensed consolidated set
of financial statements included in this half-yearly financial
report has been prepared in accordance with United Kingdom adopted
International Accounting Standard 34, "Interim Financial
Reporting".
Conclusion Relating to Going Concern
Based on our review procedures, which are less extensive than
those performed in an audit as described in the Basis for
Conclusion section of this report, nothing has come to our
attention to suggest that the directors have inappropriately
adopted the going concern basis of accounting or that the directors
have identified material uncertainties relating to going concern
that are not appropriately disclosed.
This Conclusion is based on the review procedures performed in
accordance with ISRE (UK) 2410; however future events or conditions
may cause the entity to cease to continue as a going concern.
Responsibilities of the directors
The directors are responsible for preparing the half-yearly
financial report in accordance with the Disclosure Guidance and
Transparency Rules of the United Kingdom's Financial Conduct
Authority.
In preparing the half-yearly financial report, the directors are
responsible for assessing the Group's ability to continue as a
going concern, disclosing as applicable, matters related to going
concern and using the going concern basis of accounting unless the
directors either intend to liquidate the company or to cease
operations, or have no realistic alternative but to do so.
Auditor's Responsibilities for the review of the financial
information
In reviewing the half-yearly financial report, we are
responsible for expressing to the Group a conclusion on the
condensed consolidated set of financial statements in the
half-yearly financial report. Our Conclusion, including our
Conclusion Relating to Going Concern, are based on procedures that
are less extensive than audit procedures, as described in the Basis
for Conclusion paragraph of this report.
Use of our report
This report is made solely to the company in accordance with
ISRE (UK) 2410. Our work has been undertaken so that we might state
to the company those matters we are required to state to it in an
independent review report and for no other purpose. To the fullest
extent permitted by law, we do not accept or assume responsibility
to anyone other than the company, for our review work, for this
report, or for the conclusions we have formed.
Deloitte LLP
Statutory Auditor
London, United Kingdom
14 September 2022
Condensed consolidated income statement
(unaudited) (unaudited)
Six Six
months months Year
ended ended ended
30 Jun 30 Jun 31 Dec
2022 2021 2021
Notes $ million $ million $ million
------------ ------------ ----------
Continuing operations
Revenue 3, 13 112.3 59.2 134.1
Cost of sales 4 (59.9) (51.5) (114.6)
------------ ------------ ----------
Gross profit 52.4 7.7 19.5
Administrative expenses (5.0) (5.5) (13.2)
Impairment charge
- Intangibles 3, 9 (0.1) - (2.2)
Impairment reversal
- PP&E 3, 10 62.9 27.8 54.6
Impairment charge - Assets classified
as held for sale - - (10.4)
------------ ------------ ----------
Operating profit 110.2 30.0 48.3
Other/restructuring expense 5 (0.6) (0.4) (3.3)
Loss on disposal 15 (5.8) - -
Finance costs 6 (5.6) (2.9) (6.4)
------------ ------------ ----------
Profit for the period before tax 3 98.2 26.7 38.6
Tax 7 (43.9) (20.3) (43.3)
------------ ------------ ----------
Profit/(Loss) for the period 54.3 6.4 (4.7)
------------ ------------ ----------
Earnings/(Loss) per share from continuing
operations (cents) 8
Basic 12.3 1.5 (1.1)
Diluted 12.3 1.4 (1.1)
Condensed consolidated statements of comprehensive income
(unaudited) (unaudited)
Six Six
months months Year
ended ended ended
30 Jun 30 Jun 31 Dec
2022 2021 2021
Notes $ million $ million $ million
------------ ------------ ----------
Profit/(Loss) for
the period 54.3 6.4 (4.7)
Items that may be subsequently reclassified
to profit or loss:
Fair value (loss) arising on hedging instruments
during the period (24.2) (19.8) (27.7)
Less: Loss arising on hedging
instruments reclassified
to profit or loss 13 17.3 13.7 29.7
Unrealised currency - 0.1
translation
differences -
------------ ------------ ----------
Total comprehensive income/(loss)
for the period 47.4 0.4 (2.7)
------------ ------------ ----------
The above condensed consolidated income statement and condensed
consolidated statement of comprehensive income should be read in
conjunction with the accompanying notes.
CONDENSED CONSOLIDATED Balance sheets
(unaudited) (unaudited)
30 Jun 30 Jun 31 Dec
22 21 21
Notes $ million $ million $ million
------------ ------------ ----------
Non-current
assets
Intangible
assets 9 14.3 4.6 12.4
Property, plant
and equipment 10 432.0 440.3 399.8
Other assets 58.2 47.1 48.1
------------ ------------ ----------
504.5 492.0 460.3
------------ ------------ ----------
Current assets
Inventories 10.7 19.2 10.7
Trade and other
receivables 15 72.1 29.5 28.1
Tax receivables 1.1 0.4 1.5
Cash and cash equivalents 47.5 28.4 27.1
Assets classified
as held for sale - - 62.0
------------ ------------ ----------
131.4 77.5 129.4
------------ ------------ ----------
Total assets 635.9 569.5 589.7
Current liabilities
Trade and other
payables (15.2) (25.6) (24.1)
Derivative financial
instruments 13 (14.9) (14.9) (6.5)
Borrowings 14 (35.3) (13.7) (33.3)
Tax payables (4.8) (4.2) (5.4)
Liabilities associated with assets classified
as held for sale - - (8.5)
------------ ------------ ----------
(70.2) (58.4) (77.8)
------------ ------------ ----------
Net current assets 61.2 19.1 51.6
Non-current
liabilities
Trade and other payables 15 (0.9) - -
Deferred tax
liabilities (106.4) (89.9) (91.2)
Borrowings 14 (48.0) (45.0) (47.2)
Long term provisions (57.4) (70.1) (69.1)
------------ ------------ ----------
(212.7) (205.0) (207.5)
Total liabilities (282.9) (263.4) (285.3)
------------ ------------ ----------
Net assets 353.0 306.1 304.4
------------ ------------ ----------
Equity
Share capital 34.9 34.9 34.9
Share premium 58.0 58.0 58.0
Other reserves 242.5 241.2 250.5
Retained earnings
/ (deficit) 17.6 (28.0) (39.0)
------------ ------------ ----------
Total equity 353.0 306.1 304.4
------------ ------------ ----------
The above condensed consolidated balance sheets should be read
in conjunction with the accompanying notes.
CONDENSED consolidated STATEMENTs OF CHANGES IN EQUITY
Called Retained
up share Share Other (deficit)/
capital Premium reserves earnings Total
$
$ million $ million million $ million $ million
---------- ---------- ---------- ------------ ----------
As at 1 January 2021 31.9 55.4 243.0 (36.6) 293.7
Profit for the period - - - 6.4 6.4
Other comprehensive loss - - (6.0) - (6.0)
Shares issued 3.0 2.6 5.3 - 10.9
Share-based payments - - 1.1 - 1.1
Transfer relating to
share-based payments - - (2.2) 2.2 -
As at 30 June 2021 (unaudited) 34.9 58.0 241.2 (28.0) 306.1
Loss for the period - - - (11.1) (11.1)
Other comprehensive income - - 8.0 - 8.0
Share-based payments - - 1.4 - 1.4
Transfer relating to share-based
payments - - (0.1) 0.1 -
As at 1 January 2022 34.9 58.0 250.5 (39.0) 304.4
Profit for the period - - - 54.3 54.3
Other comprehensive loss - - (6.9) - (6.9)
Share-based payments - - 1.2 - 1.2
Transfer relating to
share-based payments - - (2.3) 2.3 -
As at 30 June 2022 (unaudited) 34.9 58.0 242.5(1) 17.6 353.0
---------- ---------- ---------- ------------ ----------
(1) Includes $137.1m as Merger Reserve which is fully
distributable
The above condensed consolidated statements of changes in equity
should be read in conjunction with the accompanying notes.
condensed consolidated cash flow statements
(unaudited) (unaudited)
Six months Six months Year
ended ended ended
30 Jun 30 Jun 31 Dec
2022 2021 2021
Notes $ million $ million $ million
------------ ------------ ----------
Net cash from operating activities 12 27.6 0.1 10.8
Investing activities
Purchase of intangible
assets (2.3) (4.2) (15.2)
Purchase of property, plant and
equipment (11.5) (4.1) (24.4)
Consideration received on farm
out of Egyptian assets 15 10.1 - 2.0
Assignment fee in relation to
farm out of Egyptian assets 15 (0.5) - -
Payment to abandonment fund (1.1) (1.2) (2.2)
------------ ------------ ----------
Net cash used in investing activities (5.3) (9.5) (39.8)
Financing activities
Proceeds from borrowings 14 7.5 8.3 39.9
Interest paid on borrowings 14 (2.4) (1.8) (6.8)
Repayment of borrowings 14 (6.7) (4.2) (12.5)
Lease payments - (0.1) (0.4)
Share-based payments 0.1 - -
Net proceeds from issue
of share capital - 10.9 10.9
------------ ------------
Net cash (used in)/from financing
activities (1.5) 13.1 31.1
Net increase in cash and cash
equivalents 20.8 3.7 2.1
Cash and cash equivalents at
beginning of period 27.1 24.6 24.6
Effect of foreign exchange rate
changes (0.4) 0.1 0.4
Cash and cash equivalents at
end of period 47.5 28.4 27.1
------------ ------------ ----------
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 information for the year ended 31 December 2021 does not
constitute statutory accounts as defined in section 434 of the
Companies Act 2006. A copy of the statutory accounts for that year
has been delivered to the Registrar of Companies. The auditor's
report on those accounts was not qualified, did not include a
reference to any matters to which the auditors drew attention by
way of emphasis without qualifying the report and did not contain
statements under section 498(2) or (3) of the Companies Act
2006.
The half year financial report is presented in US dollars
because that is the currency of the primary economic environment in
which the Group operates.
The half year financial report for the six months ended 30 June
2022 was approved by the Directors on 13 September 2022.
2. Significant accounting policies
The condensed set of financial statements included in this half
year financial report has been prepared on a going concern basis of
accounting for the reasons set out in the Financial Results section
of this report and in accordance with United Kingdom adopted
International Accounting Standard IAS 34 'Interim Financial
Reporting', and the requirements of the UK Disclosure and
Transparency Rules of the Financial Services Authority in the
United Kingdom as applicable to interim financial reporting.
The accounting policies and methods of computation applied in
the half year financial report are consistent with the accounting
policies disclosed in the Group's latest annual financial
statements.
A number of judgements were taken in concluding that this basis
of preparation was appropriate and that there were no material
uncertainties in this regard. These included applying appropriate
estimates of future production and oil price together with ensuring
that the forecasts included all expenditure that was either
committed or expected to be incurred in relation to estimated
production volumes.
The interim report does not include all the notes of the type
normally included in an annual financial report. Accordingly, this
report is to be read in conjunction with the annual report for the
year ended 31 December 2021 and any public announcements made by
Pharos during the interim reporting period.
New and amended standards adopted by the Group
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.
Reference to the Conceptual Framework - Amendments to IFRS 3
Property, Plant and Equipment: Proceeds before Intended Use -
Amendments to IAS 16
Onerous Contracts - Costs of Fulfilling a Contract - Amendments
to IAS 37
These amendments had no impact on the interim condensed
consolidated financial statements of the Group.
Critical judgements and accounting estimates
The preparation of condensed consolidated financial statements
requires management to make judgements, estimates and assumptions
which affect the application of accounting policies and the
reported amounts of assets, liabilities, income and expense. Actual
results may differ from these estimates.
(a) Critical judgement in applying the Group's accounting policies
In the process of applying the Group's accounting policies,
management has made judgements that may have a significant effect
on the amounts recognised in the financial statements. These are:
(i) oil and gas assets and (ii) going concern. The critical
judgements disclosed in the annual report for the year ended 31
December 2021, Asset held for sale and Treatment of the Third
Amendment to the El Fayum Concession Agreement, are not relevant as
at 30 June 2022.
(b) Key sources of estimation uncertainty
The key assumptions concerning the future, and other key sources
of estimation uncertainty, other than those mentioned above, that
may have a significant risk of causing a material adjustment to the
carrying amounts of assets and liabilities within the next
financial year continue to be: (i) oil & gas reserves and
DD&A; (ii) impairment of producing oil & gas assets; and
(iii) climate change and the energy transition.
Consideration was also given to the potential ongoing impact of
the COVID-19 pandemic. During the first six months of 2022, the
pandemic did not cause any interruptions to the Group's producing
assets in Vietnam and Egypt.
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 and these areas form the basis
on which the Group reports its segment information (the Group's
operating segments). There are no inter-segment sales.
Six months ended 30 June 2022 Unallocated
(unaudited) SE Asia Egypt (1) Group
$ million $ million $ million $ million
---------- ---------- ------------ ----------
Oil and gas revenue 103.8 25.8(3) - 129.6
Commodity Hedge (see Note 13) - - (17.3) (17.3)
Total Revenue 103.8 25.8 (17.3) 112.3
Depreciation, depletion and
amortisation - oil and gas (25.9) (1.7) - (27.6)
Impairment charge - Intangibles - - (0.1) (0.1)
Impairment reversal - PP&E 38.4 24.5 - 62.9
Profit/(Loss) before tax from
continuing operations(1) 91.7 35.3 (28.8) 98.2
Tax charge on operations (see
Note 7) (30.2) - - (30.2)
Tax charge on impairment reversal
(see Note 7) (13.7) - - (13.7)
Non-current assets (2) 365.1 81.2 - 446.3
---------- ---------- ------------ ----------
Six months ended 30 June 2021 Unallocated
(unaudited) SE Asia Egypt (1) Group
$ million $ million $ million $ million
---------- ---------- ------------ ----------
Oil and gas revenue 56.3 16.6 - 72.9
Commodity Hedge (see Note 13) - - (13.7) (13.7)
Total Revenue 56.3 16.6 (13.7) 59.2
Depreciation, depletion and
amortisation - oil and gas (19.4) (4.2) - (23.6)
Depreciation, depletion and
amortisation - other - (0.3) - (0.3)
Impairment reversal - PP&E 24.1 3.7 - 27.8
Profit/(Loss) before tax from
continuing operations(1) 42.4 6.0 (21.7) 26.7
Tax charge on operations (see
Note 7) (11.9) - - (11.9)
Tax charge on impairment reversal
(see Note 7) (8.4) - - (8.4)
Non-current assets (2) 333.3 109.7 1.9 444.9
---------- ---------- ------------ ----------
Unallocated
Year end 31 December 2021 SE Asia Egypt (1) Group
$ million $ million $ million $ million
---------- ---------- ------------ ----------
Oil and gas revenue 131.0 32.8 - 163.8
Commodity Hedge - - (29.7) (29.7)
Total Revenue 131.0 32.8 (29.7) 134.1
Depreciation, depletion and
amortisation - oil and gas (43.0) (8.0) - (51.0)
Depreciation, depletion and
amortisation - other - (0.4) - (0.4)
Impairment charge - Intangibles - - (2.2) (2.2)
Impairment reversal - PP&E 52.9 1.7 - 54.6
Impairment charge - Assets
classified as held for sale - (10.4) - (10.4)
Profit/(Loss) before tax from
continuing operations(1) 98.8 (10.1) (50.1) 38.6
Tax charge on operations (see
Note 7) (24.8) - - (24.8)
Tax charge on impairment reversal
(see Note 7) (18.5) - - (18.5)
Non-current assets (2) 360.8 51.4 - 412.2
---------- ---------- ------------ ----------
(1) Unallocated amounts included in profit/(loss) before tax
comprise corporate costs not attributable to an operating segment,
investment and hedging revenue, other gains and losses and finance
costs.
(2) Excludes other assets.
(3) 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.
Under the terms, the cost recovery percentage was increased from
30% to 40% allowing Pharos a significantly faster recovery of all
its past and future investments. In return, Pharos 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
31 December 2021).
4. Cost of sales
(unaudited) (unaudited)
six months six months
ended ended Year ended
30 Jun 30 Jun 31 Dec
2022 2021 2021
$ million $ million $ million
------------ ------------ -----------
Depreciation, depletion and amortisation 27.6 23.6 51.0
Production based
taxes 8.8 4.4 10.1
Export duty 3.2 - -
Production operating
costs 25.4 25.2 53.6
Inventories (5.1) (1.7) (0.1)
59.9 51.5 114.6
------------ ------------ -----------
5. Other/restructuring expense
(unaudited) (unaudited)
six months six months Year
ended ended ended
30 Jun 30 Jun 31 Dec
2022 2021 2021
$ million $ million $ million
------------ ------------ ----------
Redundancy loss 0.1 0.4 3.0
Premium - lease
transfer 0.5 - 0.3
0.6 0.4 3.3
------------ ------------ ----------
6. Finance Costs
(unaudited) (unaudited)
six months six months
ended ended Year ended
30 Jun 30 Jun 31 Dec
2022 2021 2021
$ million $ million $ million
------------ ------------ -----------
Unwinding of discount on
provisions 0.5 0.3 0.8
Interest expense payable and
similar fees
(see Note 14) 2.4 1.8 3.8
Amortisation of capitalised
borrowing costs
(see Note 14) 2.0 1.0 2.4
Net foreign exchange
losses/(gains) 0.7 (0.2) (0.6)
5.6 2.9 6.4
------------ ------------ -----------
As at 30 June 2022, $0.5m relates to the unwinding of discount
on the provisions for decommissioning (1H 2021: $0.3m). The
provisions are based on the net present value of the Group's share
of the expenditure which may be incurred at the end of the life of
TGT and CNV (currently estimated to be 8-9 years) in the removal
and decommissioning of the facilities currently in place.
Following the June 2022 redetermination and the $0.2m repayment
of principal in relation to the Group's reserve based lending
facility, there was a change in estimated future cash flows. As a
result, in June 2022, a one off charge of $0.7m (1H 2021: $nil; Dec
2021: $0.5m gain) and amortised cost of $1.3m (1H 2021: $1.0m; Dec
2021: $2.9m) was recognised in the income statement.
7. Tax
(unaudited) (unaudited)
six months six months
ended ended Year ended
30 Jun 30 Jun 31 Dec
2022 2021 2021
$ million $ million $ million
------------ ------------ -----------
Current tax 28.7 16.0 37.6
Deferred tax charge/(credit)
on operations 1.5 (4.1) (12.8)
Deferred tax charge on
impairment
reversal 13.7 8.4 18.5
Total tax charge 43.9 20.3 43.3
------------ ------------ -----------
The Group's corporation tax is calculated at 50% (1H 2021: 50%)
of the estimated assessable profit for the year in Vietnam. In
Egypt, under the terms of the concession any local taxes arising
are settled by EGPC. During each period, both current and deferred
taxation have arisen in overseas jurisdictions only.
For CNV, a pre-tax impairment reversal in the amount of $13.6m
has been reflected in the income statement with an associated
deferred tax charge of $5.1m (1H 2021: pre-tax impairment reversal
$2.2m, deferred tax charge of $0.8m). For TGT, a pre-tax impairment
reversal in the amount of $24.8m has been reflected in the income
statement with an associated deferred tax charge of $8.6m (1H 2021:
pre-tax impairment reversal $21.9m, deferred tax charge of
$7.6m).
The charge for the year can be reconciled to the profit / (loss)
per the income statement as follows:
(unaudited) (unaudited)
six months six months
ended ended Year ended
30 Jun 30 Jun 31 Dec
2022 $ 2021 $ 2021 $
million million million
------------ ------------ -----------
Profit before tax 98.2 26.7 38.6
Profit before tax at 50% (2021: 50%) 49.1 13.3 19.3
Effects of:
Non-taxable income (5.6) (3.7) (8.0)
Non-deductible expenses 4.7 3.5 4.5
Tax losses not recognised 13.1 10.2 28.7
Utilisation of losses (17.7) (3.0) -
Adjustments to tax charge in respect
of previous periods 0.3 - (1.2)
Tax charge for the
year 43.9 20.3 43.3
------------ ------------ -----------
The prevailing tax rate in Vietnam, where the Group produces oil
and gas, is 50% (1H 2021: 50%). The tax charge in future periods
may also be affected by the factors in the reconciliation
above.
Non-taxable income principally relates to Vietnam impairment
reversal of $(5.5)m (1H 2021: $(3.7)m). Non-deductible expenses
primarily relate to Vietnam DD&A charges for costs previously
capitalised, which are non-deductible for Vietnamese tax purposes
of $3.3m (1H 2021: $1.9m). A further $1.4m (1H 2021: $1.6m) relates
to non-deductible corporate costs including share scheme
incentives. Tax losses not recognised of $13.1m (1H 2021: $10.2m)
are predominantly due to the tax impact of realised hedging losses
during the period.
Utilisation of losses of $(17.7)m (1H 2021: $(3.0)m) relate to
Egypt. 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 revenue, for the tax paid by EGPC
on its behalf. However, this is only valid if PEF is in an historic
profit making position and no such tax has been recorded this
period.
8. Earnings/(loss) per share
The calculation of the basic and diluted earnings/(loss) per
share is based on the following data:
(unaudited) (unaudited)
six months six months
ended ended Year ended
30 Jun 30 Jun 31 Dec
2022 2021 2021
$ million $ million $ million
------------ ------------ -----------
Profit/(Loss) from continuing
operations
for the purposes of basic
profit/(loss) per
share 54.3 6.4 (4.7)
Effect of dilutive potential
ordinary shares
- Cash settled share awards and
options - (0.3) -
Profit/(Loss) from continuing
operations
for the purposes of diluted
profit/(loss)
per share 54.3 6.1 (4.7)
------------ ------------ -----------
(unaudited) (unaudited)
six months six months Year
ended ended ended
30 Jun 30 Jun 31 Dec
2022 2021 2021
$ million $ million $ million
------------ ------------- ----------
Weighted average number of
ordinary shares 441.7 434.6 437.8
Effect of dilutive potential
ordinary shares
- Share awards and options 0.5 0.7 -
Weighted average number of
ordinary shares
for the purpose of diluted
profit/(loss)
per share 442.2 435.3 437.8
------------ ------------- ----------
In accordance with IAS 33 "Earnings per Share", the effects of
$14.2m antidilutive potential shares have not been included when
calculating diluted earnings per share for the year ended 31
December 2021, as the Group was loss making.
9. Intangible assets
Intangible assets comprise the Group's exploration and
evaluation projects which are pending determination.
In June 2022, having reviewed the triggers for impairment,
Management are of the view that none of the impairment indicators
under IFRS 6 have been triggered and therefore no impairment
testing is required for Vietnam or Egypt.
During H1 2022, $0.1m was spent in Israel on geoscience and
geophysical studies. Pharos continues to hold $2.7m (Dec 2021:
$2.7m) cash in relation to bank guarantees for the Israeli offshore
exploration licenses. At 30 June 2022, the Group has decided to
write off the $0.1m in Israel as no substantive expenditure has
been identified as indicated in IFRS 6 (Dec 2021: Israel impairment
charge $2.2m).
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 and 2P reserves (2021: oil
price, discount rate and 2P reserves). As at 30 June 2022, the fair
value of the assets are estimated based on a post-tax nominal
discount rate of 13% (1H 2021: 11%) and a Brent oil price of
$107.6/bbl in 2H 2022 down to $77.0/bbl in 2025 plus inflation of
2% thereafter (1H 2021: an oil price of $64.7/bbl in 2H 2021 up to
$65.0/bbl in 2025, plus inflation of 2% thereafter).
For CNV, a pre-tax impairment reversal in the amount of $13.6m
has been reflected in the income statement with an associated
deferred tax charge of $5.1m. As at 30 June 2022, the carrying
amount of the CNV oil and gas producing property, after additions
of $0.2m, changes in decommissioning asset ($1.7m), DD&A
($5.3m) and impairment reversal of $13.6m, is $91.0m.
For TGT, a pre-tax impairment reversal in the amount of $24.8m
has been reflected in the income statement with an associated
deferred tax charge of $8.6m. As at 30 June 2022, the carrying
amount of the TGT oil and gas producing property, after additions
of $0.5m, changes in decommissioning asset ($8.7m), DD&A
($20.6m) and after impairment reversal of $24.8m, is $262.0m. It
should be noted that the TGT impairment reversal at 30 June 2022
has been restricted to reflect the remaining balance of historic
impairment charges previously recorded against the field. The
impairment reversal test calculated NPV13 $218.9m which would have
implied a pre-tax reversal of $67.2m, but this was restricted to
$24.8m.
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 impairment charges (compared to new
Net Book Value, "NBV") of $3.8m on CNV. A 1% increase in discount
rate would result in post-tax impairments of $1.3m 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; 2022:$105.6/bbl, 2023:$93.8/bbl,2024:$84.4/bbl,
2025:$77.0/bbl, 2026: $71.0/bbl, 2027:$65.0/bbl, 2028:$58.0/bbl,
2029:$51.0/bbl. 2030:$44.0/bbl. Using these prices and a 13%
discount rate would result in additional post-tax impairments of
$5.8m on CNV.
For TGT, even if these downside scenarios are applied ($5/bbl
reduction in long-term oil price, 1% increase in discount rate and
Net Zero price scenario), the impairment reversal would still have
been $24.8m.
Egypt
The key assumptions to which the fair value measurement is most
sensitive are oil price, discount rate and 2P reserves (2021: oil
price, discount rate and 2P reserves). As at 30 June 2022, the fair
value of the asset is estimated based on a post-tax nominal
discount rate of 15.1% (1H 2021: 14%) and a Brent oil price of
$107.6/bbl in 2H 2022 down to $77.0/bbl in 2025 plus inflation of
2% thereafter (1H 2021: an oil price of $64.7/bbl in 2H 2021 up to
$65.0/bbl in 2025, plus inflation of 2% thereafter).
For Egypt, an impairment reversal (pre and post tax) in the
amount of $24.5m has been reflected in the income statement. As at
30 June 2022, the carrying amount of the Egypt oil and gas
producing property, after additions of $6.7m, DD&A ($1.7m) and
after the impairment reversal of $24.5m, is $78.7m.
Testing of sensitivity cases indicated that a $5/bbl reduction
in long term oil price used would result in an impairment of $7.2m
(compared to new NBV) . A 1% increase in discount rate would result
in an impairment charge of $3.0m. We have also run a sensitivity
using a 15.1% discount rate and the Net Zero price scenario which
would result in an additional impairment of $15.0m.
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.
Capital commitments
At 30 June 2022, the Group had exploration licence commitments
not accrued of approximately $27.3m (31 Dec 2021: $36.2m).
11. Distribution to Shareholders
The Company remains focused on preserving balance sheet strength
and has not yet returned to declaring dividend payments (2021 :
$Nil).
12. Reconciliation of operating profit to operating cash
flows
(unaudited) (unaudited)
six months six months
ended ended Year ended
30 Jun 30 Jun 31 Dec
2022 2021 2021
$ million $ million $ million
------------ ------------ -----------
Operating profit 110.2 30.0 48.3
Share-based payments 0.8 1.0 2.4
Depreciation, depletion and
amortisation 27.6 23.9 51.4
Impairment charge - Intangibles 0.1 - 2.2
Impairment reversal - PP&E (62.9) (27.8) (54.6)
Impairment charge - Assets classified
as held for sale - - 10.4
------------ ------------ -----------
Operating cash flows before movements
in working capital 75.8 27.1 60.1
(Increase)/Decrease in inventories (4.4) (1.5) 0.8
Increase in receivables(1) (10.4) (5.4) (7.2)
Decrease in payables(1) (4.0) (2.0) (2.2)
------------ ------------ -----------
Cash generated by operations 57.0 18.2 51.5
Interest paid (0.1) (0.1) (0.1)
Other/redundancy expense outflow (2.3) (0.1) (0.7)
Income taxes paid (27.0) (17.9) (39.9)
------------ ------------ -----------
Net cash from operating activities 27.6 0.1 10.8
------------ ------------ -----------
(1) During the six months ended 30 June 2022 a total of $4.3m
(1H 2021: $2.6m) of trade receivables due from EGPC in Egypt were
settled by way of non-cash offset, out of which $1.0m relates to
3rd Amendment signature bonus (1HY 2021: Nil), $0.8m was set
against trade payables (1HY 2021 $2.6m), $2.0m Assignment bonus
settled on behalf of the Farm out partner, IPR and $0.5m Group's
share of NBS Concession assignment bonus (see Note 15).
13. Hedge transactions
During 1H 2022, Pharos entered into different commodity (swap
and zero collar) hedges to protect the Brent component of forecast
oil sales and to ensure future compliance with its obligations
under the RBL over the producing assets in Vietnam. The commodity
hedges run until June 2023 and are settled monthly. The hedging
positions in place at the balance sheet date cover 30% of the
Group's forecast production until June 2023, securing an average
price for this hedged volume of $67.0/bbl (1H 2021: cover was 27%
of the Group's forecast production until June 2022, securing a
minimum price for this hedged volume of $55.6/bbl).
Pharos has designated the swaps and zero collar 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
period ended 30 June 2022 a loss of $17.3m was realised (1H 2021:
loss of $13.7m). The outstanding unrealised loss on open position
as at 30 June 2022 amounts to $11.2m (1H 2021: loss of $12.4m).
The carrying amounts of the swaps and zero collar are based on
the fair value determined by a financial advisor. As all material
inputs are observable, they are categorised within Level 2 in the
fair value hierarchy. It is presented in " Derivative financial
instruments " in the consolidated statement of financial position.
The liability position as at June 2022 was $14.9m of which $3.6m
has been realised and due for payment early July (1H 2021:
liability position $14.9m of which $2.5m was realised).
14. Borrowings
Changes in liabilities arising from financing activities:
(unaudited)
(unaudited) six months
six months ended
ended 30 Jun
30 Jun 2022 2021
$ million $ million
------------------------------------------- ----------------------------- -----------
Credit RBL Total Total
facility Borrowings Borrowings
------------------------------------------- --------- ----- ----------- -----------
Carrying value as of 1 January 6.5 74.0 80.5 53.7
------------------------------------------- --------- ----- ----------- -----------
Proceeds from Uncommitted Revolving credit
facility 7.5 - 7.5 8.3
------------------------------------------- --------- ----- ----------- -----------
Repayments of borrowings (6.5) (0.2) (6.7) (4.2)
------------------------------------------- --------- ----- ----------- -----------
Amortisation of capitalised borrowing
costs (see Note 6) - 2.0 2.0 1.0
------------------------------------------- --------- ----- ----------- -----------
Interest payable and similar fees (see
Note 6) 0.2 2.2 2.4 1.8
------------------------------------------- --------- ----- ----------- -----------
Interest paid during the year (0.1) (2.3) (2.4) (1.9)
------------------------------------------- --------- ----- ----------- -----------
Carrying value as of 30 June 7.6 75.7 83.3 58.7
------------------------------------------- --------- ----- ----------- -----------
Current 7.6 27.7 35.3 13.7
------------------------------------------- --------- ----- ----------- -----------
Non-current - 48.0 48.0 45.0
------------------------------------------- --------- ----- ----------- -----------
Uncommitted revolving credit facility - National Bank of Egypt
(Credit facility)
In May 2022, the Group renegotiated the uncommitted revolving
credit facility with National Bank of Egypt for discounting (with
recourse) of up to $18m (1H 2021: $20m).
The carrying amount of the trade receivables include receivables
in Egypt which are subject to an Uncommitted Revolving Credit
Facility for Discounting (with Recourse) arrangement. This facility
was put in place to mitigate the risk of late payment. 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 receivables in their entirety in its balance
sheet.
15. Disposal of asset held for sale
In December 2021, the company classified 55% of the Group's
operated interest in each of our Egyptian Concessions, El Fayum and
North Beni Suef, as Assets classified as held for sale (Net assets
classified as held for sale as 31 December 2021: $53.5m).
Following the completion of the farm-out transaction of Egyptian
assets to IPR, the accounting for the assets reflect the
following:
The economic date of the transaction was 1 July 2020, with
completion on 21 March 2022.
Pharos owned and managed the business up to completion. On
completion, an adjustment to compensate for net cash flows since
the economic date has been adjusted for in the level of carry to be
provided by IPR to Pharos.
In the financial statements, for the period post completion,
Pharos 45% share of field costs - capex, opex and G&A - are
accounted for as incurred by Pharos, although all such costs are
paid by IPR and set off against the carry.
All revenues earned are paid direct to Pharos.
Disposal of asset held for sale:
$ million
----------
Intangible (2.3)
Property, plant and equipment (54.4)
Inventories (5.9)
Trade and other receivables (2.3)
Trade and other payables 8.3
----------
Disposal of 55% of El Fayum and NBS (56.6)
Firm consideration received - IPR Cash
Receipts 5.0
Other receivable - Carry 37.0
Other receivable - contingent consideration 13.6
Other receivable with IPR 0.5
----------
Consideration received and to be received 56.1
Assignment fees payable to EGPC (3.6)
Success fees paid on completion (1.7)
----------
Loss on disposal (5.8)
----------
The firm consideration was received in two tranches, $2.0m in
September 2021 and $3.0m on 30 March 2022.
The carry of $37.0m is disproportionate funding contribution
from IPR adjusted for working capital and interim period
adjustments from the effective economic date of 1 July 2020 and
completion date. The interim period adjustments amount is the best
estimate as at 30 June 2022.
The carry will decrease every month against the cash calls
received from IPR. The total amount utilised as at 30 June 2022
amounts to $7.1m, which has been disclosed in "Consideration
received on farm out of Egyptian assets" in the cash flow as part
of investing activities (combined with $3.0m firm consideration
received on 30 March 2022). No cash outflow is required until we
utilise the whole amount.
The Group is entitled to contingent consideration depending on
the average Brent Price each year from 2022 to the end of 2025
(with floor and cap at $62/bbl and c.$90/bbl respectively). The
contingent consideration is calculated yearly and is capped at a
maximum total payment of $20.0m. As at 30 June 2022, the contingent
consideration amounts to $13.6m ($4.6m current and $9.0m
non-current). Testing of sensitivity for a $5/bbl reduction in long
term oil price used would result in $1.7m decrease in contingent
consideration to $11.9m.
As at 30 June 2022, $3.6m relates to the assignment fee for the
sale of 55% of the Group's operated interest in each of our
Egyptian Concessions, El Fayum and North Beni Suef, to IPR. $0.5m
Group's share of NBS Concession assignment bonus was settled
against Trade Receivable. Out of the remaining $3.1m, $2.2m is
booked as current other payable and $0.9m as non-current other
payable.
16. Subsequent events
Share buy-back
On 20 July 2022, Pharos initiated a share buy-back programme to
purchase up to approximately $3m (excluding stamp duty and
expenses) of the Company's ordinary shares in the market. As at
close of business on 12 September 2022, $1.6m had been committed
under the programme. Based on progress to date, we expect to
complete the programme in the fourth quarter this year.
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.
(unaudited) (unaudited)
six months six months
ended ended Year ended
30 Jun 30 Jun 31 Dec
22 21 21
$ million $ million $ million
------------ ------------ -----------
Cost of sales 59.9 51.5 114.6
Less:
Depreciation, depletion and amortisation (27.6) (23.6) (51.0)
Production based taxes (8.8) (4.4) (10.1)
Export duty (3.2) - -
Inventories 5.1 1.7 0.1
Trade Receivable risk factor provision (1.5) - -
Other cost of sales (1.1) (0.8) (1.6)
Cash operating costs 22.8 24.4 52.0
------------ ------------ -----------
Production (BOEPD) 7,962 9,147 8,878
------------ ------------ -----------
Cash operating cost
per BOE ($) 15.82 14.74 16.05
------------ ------------ -----------
Cash operating costs per barrel by segment (1H 2022)
Vietnam Egypt Total
$ million $ million $ million
---------- ---------- ----------
Cost of sales 50.0 9.9 59.9
Less:
Depreciation, depletion and
amortisation (25.9) (1.7) (27.6)
Production based taxes (8.7) (0.1) (8.8)
Export duty (3.2) - (3.2)
Inventories 5.1 - 5.1
Trade Receivable risk factor
provision - (1.5) (1.5)
Other cost of sales (0.8) (0.3) (1.1)
Cash operating cost 16.5 6.3 22.8
---------- ---------- ----------
Production (BOEPD) 5,861 2,101 (1) 7,962
---------- ---------- ----------
Cash operating cost
per BOE ($) 15.55 16.57 15.82
---------- ---------- ----------
(1) From 21 March 2022 includes 45% Pharos share of production;
1H 2022 100% production: 3,142 boepd
(unaudited) (unaudited)
six months six months
ended ended
30 Jun 30 Jun
Vietnam 22 21
$ million $ million
------------ ------------
Cost of sales 50.0 37.7
Less:
Depreciation, depletion and amortisation (25.9) (19.4)
Production based taxes (8.7) (4.3)
Export duty (3.2) -
Inventories 5.1 1.7
Other cost of sales (0.8) (0.4)
Cash operating costs 16.5 15.3
------------ ------------
Production (BOEPD) 5,861 5,429
------------ ------------
Cash operating cost
per BOE ($) 15.55 15.57
------------ ------------
(unaudited) (unaudited)
six months six months
ended ended
30 Jun 30 Jun
Egypt 22 21
$ million $ million
------------ ------------
Cost of sales 9.9 13.8
Less:
Depreciation, depletion and amortisation (1.7) (4.2)
Production based taxes (0.1) (0.1)
Inventories - -
Trade Receivable risk factor provision (1.5) -
Other cost of sales (0.3) (0.4)
Cash operating costs 6.3 9.1
------------ ------------
2,101
Production (BOEPD) (1) 3,718
------------ ------------
Cash operating cost
per BOE ($) 16.57 13.52
------------ ------------
(1) From 21 March 2022 includes 45% Pharos share of production;
1H 2022 100% production: 3,142 boepd
DD&A 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.
(unaudited) (unaudited)
six months six months
ended ended Year ended
30 Jun 30 Jun 31 Dec
22 21 21
$ million $ million $ million
------------ ------------ -----------
Depreciation, depletion and amortisation (27.6) (23.6) (51.0)
------------ ------------ -----------
Production (BOEPD) 7,962 9,147 8,878
------------ ------------ -----------
DD&A per BOE ($) 19.15 14.25 15.74
------------ ------------ -----------
DD&A per barrel by segment (1H 2022)
Vietnam Egypt Total
$ million $ million $ million
---------- ---------- ------------
Depreciation, depletion and
amortisation (25.9) (1.7) (27.6)
---------- ---------- ----------
Production (BOEPD) 5,861 2,101 7,962
---------- ---------- ------------
DD&A per BOE ($) 24.41 4.47 19.15
---------- ---------- ------------
(unaudited) (unaudited)
six months six months
ended ended
30 Jun 30 Jun
Vietnam 22 21
$ million $ million
------------ ------------
Depreciation, depletion and amortisation (25.9) (19.4)
------------ ------------
Production (BOEPD) 5,861 5,429
------------ ------------
DD&A per BOE ($) 24.41 19.74
------------ ------------
(unaudited) (unaudited)
six months six months
ended ended
30 Jun 30 Jun
Egypt 22 21
$ million $ million
------------ ------------
Depreciation, depletion and amortisation (1.7) (4.2)
------------ ------------
Production (BOEPD) 2,101 3,718
------------ ------------
DD&A per BOE ($) 4.47 6.24
------------ ------------
Net Debt
Net debt comprises interest-bearing bank loans, less cash and
cash equivalents.
(unaudited) (unaudited)
six months six months
ended ended Year ended
30 Jun 30 Jun 31 Dec
22 21 21
$ million $ million $ million
------------ ------------ -----------
Cash and cash equivalents 47.5 28.4 27.1
Borrowings* (85.4) (61.3) (84.6)
------------ ------------ -----------
Net Debt (37.9) (32.9) (57.5)
------------ ------------ -----------
*Exclude unamortised capitalised set up costs
EBITDAX
EBITDAX is earnings from continuing activities before interest,
tax, DD&A, impairment (reversal)/charge of PP&E and
intangibles, loss on disposal and exploration expenditure.
(unaudited) (unaudited)
six months six months Year
ended ended ended
30 Jun 30 Jun 31 Dec
22 21 21
$ million $ million $ million
------------ ------------ ----------
Operating profit 110.2 30.0 48.3
Depreciation, depletion and amortisation 27.6 23.9 51.4
Impairment reversal (62.8) (27.8) (42.0)
------------ ------------ ----------
EBITDAX 75.0 26.1 57.7
------------ ------------ ----------
Net Debt/EBITDAX
Net Debt/EBITDAX ratio expresses how many years it would take to
repay the debt, if net debt and EBITDAX stay constant.
(unaudited) (unaudited)
six months six months Year
ended ended ended
30 Jun 30 Jun 31 Dec
22 21 21
$ million $ million $ million
------------ ------------ ----------
Net Debt (37.9) (32.9) (57.5)
EBITDAX 75.0 26.1 57.7
------------ ------------ ----------
Net Debt/EBITDAX 0.51 1.26 1.00
------------ ------------ ----------
Gearing
Debt to equity ratio is calculated by dividing interest-bearing
bank loans by stockholder's equity. The debt to equity ratio
expresses the relationship between external equity (liabilities)
and internal equity (stockholder's equity).
(unaudited) (unaudited)
six months six months Year
ended ended ended
30 Jun 30 Jun 31 Dec
22 21 21
$ million $ million $ million
------------ ------------ ----------
Total Debt 85.4 61.3 84.6
Total Equity 353.0 306.1 304.4
------------ ------------ ----------
Debt to Equity 0.24 0.20 0.28
------------ ------------ ----------
Operating cash per share
Operating cash per share is calculated by dividing net cash from
continuing operations by number of shares.
(unaudited) (unaudited)
six months six months
ended ended Year ended
30 Jun 30 Jun 31 Dec
22 21 21
$ million $ million $ million
------------ ------------ ------------
Net cash from continuing operating activities 27.6 0.1 10.8
Weighted number of
shares in the year 441,743,462 436,995,454 437,512,648
------------ ------------ ------------
Operating cash per
share 0.06 - 0.02
------------ ------------ ------------
Operating profit excluding impairment (reversal)/charge
Operating profit excluding impairment (reversal)/charge is
calculated by adding back the impairment (reversal)/charge to the
operating profit.
(unaudited) (unaudited)
six months six months
ended ended Year ended
30 Jun 30 Jun 31 Dec
22 21 21
$ million $ million $ million
------------ ------------ -----------
Operating profit 110.2 30.0 48.3
Impairment charge 0.1 - 12.6
Impairment reversal (62.9) (27.8) (54.6)
------------ ------------ -----------
Operating profit excluding impairment
(reversal)/charge 47.4 2.2 6.3
------------ ------------ -----------
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END
IR DGGDCSDBDGDX
(END) Dow Jones Newswires
September 14, 2022 02:01 ET (06:01 GMT)
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