REG - Pharos Energy PLC - 2025 Interim Results
24/09/2025 07:00
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RNS Number : 5307A Pharos Energy PLC 24 September 2025
Pharos Energy plc
("Pharos" or the "Company" or, together with its subsidiaries, the "Group")
Interim results for the six months ended 30 June 2025
Pharos Energy plc, an independent energy company with assets in Vietnam and
Egypt, announces its interim results for the six months ended 30 June 2025. A
conference call for analysts will take place at 09.00 BST today.
Katherine Roe, Chief Executive Officer, commented:
"We have continued to make strong strategic and operational progress during
the first half of the year. The global stage remains challenging but our focus
on operational excellence and financial discipline has delivered stable
production averaging 5,642 boepd net, and continued strong cash generation, in
line with our guidance.
"In Vietnam, we will begin an important and material six-well drilling
campaign in the fourth quarter, with results expected in the first half of
2026. Preparations for drilling the TGT appraisal well 18X to unlock future
upside are progressing well and, together with the planned CNV 5X-L1 appraisal
and infill drilling campaign, are expected to de-risk additional development
opportunities and drive production growth from 2026 onwards. On our
exploration blocks 125 & 126, we have engaged with an independent third
party adviser to conduct a formal process to identify farm-in partners. This
process, together with the ordering of long lead items, provides optionality
to pursue the long-term potential of these important exploration assets. The
recent approval of a two-year PSC extension in June further supports this
optionality.
"In Egypt, we continue to ensure we make economic investment decisions to
maximise the value of these self-funding assets. We were pleased to have
announced on Tuesday the approval from EGPC of a consolidated Concession
Agreement, which brings an immediate uplift in the value of our Egyptian
portfolio and a 25% increase from year-end 2024 2P reserves. The improved
fiscal terms provide an attractive investment framework for both Pharos and
our partner IPR. We will continue our cautious approach to capital allocation
whilst we seek to continue the recovery of our outstanding receivables.
"Underpinning our progress is our strong cash flow generation and debt-free
balance sheet. This financial strength allows us to announce today an interim
dividend of 0.3993 pence per share for the 2025 financial year, an increase of
10% from last year. As we restart investment into our core assets, we will
continue to be careful to maintain a strong financial position to support our
commitment to shareholder returns.
"Looking ahead, we recognise scale is essential to delivering long-term growth
and we have the financial flexibility to pursue both organic and inorganic
opportunities. We remain committed to delivering value for shareholders
through disciplined execution with strategic focus."
1H Operational Highlights
· Group working interest production was 5,642 boepd net (1H 2024:
5,851 boepd net), in line with full year guidance:
o Vietnam 4,183 boepd (1H 2024: 4,456 boepd)
o Egypt 1,459 bopd (1H 2024: 1,395 bopd)
· In Vietnam:
o TGT: Rig contracts secured for the drilling of three infill wells and the
18X appraisal well in 4Q, targeting the block's untapped western area
o CNV: Planning continues for the drilling of one infill well and the 5X-LI
appraisal well in 4Q, intended to unlock the northern part of the field
o Rig contracts also incorporate flexibility to drill optional appraisal
wells on TGT and CNV
o Blocks 125 & 126: Approval received from the Vietnamese Government for
the two-year extension of the PSC Exploration Period (from 9 November 2025 to
8 November 2027); appointment of independent third party adviser to support
formal process to identify a potential farm-in partner
· In Egypt:
o El Fayum: East Saad-1X well on production from 1 July following commercial
discovery in February
o North Beni Suef (NBS): 3D seismic data processing ongoing
1H Financial and Corporate Highlights
· Group revenue $65.6m(1) (1H 2024: $65.0m)
· Net loss $2.2m after adjusting for re-measurements of $0.6m (1H
2024: $2.7m net profit after adjusting for restructuring expenses,
re-measurements and impairment reversals totalling $12.6m credit) (2)
· Cash generated from operations $31.9m (1H 2024: $44.3m including
$10m one off payment from EGPC in USD)
· Operating cash flow $16.1m(3) (1H 2024: $27.9m including $10m
one off payment from EGPC in USD)(3)
· Cash operating costs $17.04/bbl(4) (1H 2024: $17.09/bbl)(4 )
· Net cash as at 30 June 2025 of $22.6m (31 Dec 2024: $16.5m)
· Egypt receivable balance at 30 June 2025 of $33.5m (31 Dec 2024:
$29.5m), having received $5.5m in the six months to 30 June. Post our balance
sheet date, we received an additional $5.6m as at 23 September 2025
· Interim dividend in respect of 2024 of 0.363 pence per share was
paid on 22 January 2025. The final dividend of 0.847 pence per share,
amounting to $4.7m, was paid on 18 July 2025. The full year 2024 dividend was
1.210 pence per share, amounting to $6.5m in total
· Appointment of João Saraiva e Silva as Non-Executive Chair on 26
June 2025
(1) No realised hedge gains or losses in the period (1H 2024: realised hedge
losses of $0.1m)
(2) Refer to page 9 for a reconciliation to (Loss)/Profit after tax
(3) Operating cash flow = Net cash from operating activities, as set out in
the Cash Flow Statement
(4 ) See Non-IFRS measures on page 30
Outlook
· 2025 production guidance range narrowed to 5,200-6,000 boepd
(from 5,000 - 6,200 boepd), reflecting consistent production in Vietnam and
lower than expected production in Egypt
· Six-well drilling campaign in Vietnam about to commence and
expected to deliver incremental production volumes in 2026 and beyond
· Exploration farm-out of blocks 125 & 126 in Vietnam to
continue with encouraging engagement from potential partners
· Improved fiscal terms in Egypt now agreed; preparations for the
committed work programme to commence imminently
· Forecast cash capex for the full year expected to be c. $35m, of
which $8.2m incurred in the first half. A further $22m relating to the 2025
drilling campaign is expected to fall into 1H 2026
· Strategic focus on maximising value from existing portfolio
whilst evaluating opportunities to build scale
Enquiries
Pharos Energy plc
Tel: 020 7747 2000
Katherine Roe, Chief Executive Officer
Sue Rivett, Chief Financial Officer
Camarco
Tel: 020 3757 4980
Billy Clegg | Georgia Edmonds | Violet Wilson | Tamsin Howard
Notes to editors
Pharos Energy plc is an independent energy company focused on delivering
sustainable growth and returns to stakeholders, with a portfolio of stable
production, development and exploration assets in Vietnam and Egypt. Led by an
experienced team, Pharos is a cash generative business with a robust balance
sheet and an established platform to deliver both organic growth and inorganic
opportunities.
Pharos is listed on the Main Market of the London Stock Exchange. For further
information, please visit www.pharos.energy (http://www.pharos.energy) .
Operational Review
Health and Safety
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 2025. Although Pharos had no
recordable spills in Vietnam and Egypt during the period, in July 2025, an
incident involving a truck occurred in Egypt, causing damage to the truck and
spillage of 178 barrels of crude oil. No injuries occurred during this
incident. Following a thorough internal investigation, several operating
procedures, such as additional training and monitoring systems, have been
updated to prevent similar incidents in the future. All oil spilled was
cleaned up efficiently and with limited environmental damage.
Safety continues to be the top priority for our business, and we are committed
to operating safely and responsibly at all times to provide a safe and healthy
working environment for staff and contractors working within our joint
ventures or JOCs.
Vietnam
Vietnam Production
Production for the first half of 2025 from the TGT and CNV fields net to the
Group's working interest averaged 4,183 boepd (1H 2024: 4,456 boepd), in line
with guidance.
TGT 1H 2025 production averaged 11,053 boepd gross and 3,279 boepd net to
Pharos (1H 2024: 11,086 boepd gross and 3,289 boepd net). CNV 1H 2025
production averaged 3,617 boepd gross and 904 boepd net to Pharos (1H 2024:
4,667 boepd gross and 1,167 boepd net).
Vietnam Development and Operations
TGT & CNV Fields
Operational activities in the first half focused on securing rig contracts and
preparing for appraisal and infill drilling programmes on both TGT and CNV in
2H 2025, with no new wells drilled. Overall production remained stable due to
well interventions and production optimisation opportunities.
Following the approval of the TGT and CNV five-year licence extension in
December, preparations are underway for the drilling of the 18X appraisal well
and three infill wells on the TGT Field in Block 16-1. The success of the
appraisal well would open up an undrilled area in the western part of the
field. Contracts for two rigs were secured in August, and drilling is expected
to commence in 4Q.
On the CNV Field in Block 9-2, planning continues for the drilling of the
5X-LI appraisal well and one infill well, expected to commence in 4Q. The
appraisal well is intended to unlock the potential of the northern area of the
field.
Additionally, 3D seismic reprocessing on both assets was completed in August
and interpretation of this data is now underway.
Vietnam Exploration
Blocks 125 & 126
In 1H 2025, the Company continued to optimise its prospects and leads
portfolio with detailed drilling engineering studies for the well on Prospect
A.
Additionally, Pharos has engaged an independent third party adviser to support
a formal process intended to identify a potential farm-in partner before
exploration drilling commences with encouraging engagement. In parallel,
discussions continue with rig contractors to retain optionality for the
prospect to be drilled.
Most notably, the application for a two-year extension of the Blocks 125 &
126 PSC Exploration Period was granted by the Vietnamese Government in June
2025, extending the Exploration Period to 8 November 2027. This extension
reflects the Government's continued support for Pharos and underlines our
commitment to the region.
Egypt
Egypt Production
Production for the first half of 2025 from the El Fayum and NBS fields net to
the Group's working interest averaged 1,459 bopd (1H 2024: 1,395 bopd), in
line with guidance.
El Fayum 1H 2025 production averaged 3,093 bopd gross and 1,392 bopd net to
Pharos (1H 2024: 2,867 bopd gross and 1,290 bopd net). NBS 1H 2025 production
averaged 150 bopd gross and 67 bopd net to Pharos (1H 2024: 232 bopd gross and
105 bopd net).
Egypt Development and Operations
El Fayum
Following its commercial discovery in February 2025, the East Saad-1X well was
put on production from 1 July, contributing to total production.
Planning is underway for the two-well drilling programme which is expected to
commence in 4Q.
Egypt Commercial
On 23 September, Pharos announced that it had received approval from the
Executive Board of EGPC for the consolidation of the El Fayum and North Beni
Suef Concession Agreements into a new consolidated concession agreement.
Pharos will retain a 45% working interest in the Consolidated Concession, with
IPR continuing as operator with a 55% working interest. In addition to the 12
development leases of the EF and NBS Concessions, the Consolidated Concession
will include three new exploration areas.
The Consolidated Concession will unlock significant value in the Western
Desert by improving certain fiscal terms, extending the duration of the
licenses, and committing the Contractor parties (Pharos Group and IPR) to
additional work programmes to deliver production growth. Based on Pharos'
Competent Person's Reports as at 31 December 2024, the Consolidated Concession
could result in moving approximately 3.1 MMstb from contingent resources to 2P
reserves, or a 25% increase from year-end 2024, net to Pharos working
interest.
The Consolidated Concession is subject to customary approvals and to Egyptian
Parliamentary ratification, which is expected to take place in late 2025 or
early 2026, but the new set of terms will start imminently.
The improved terms of the Consolidated Concession reset our investment into
the assets in order to unlock further value.
Egypt Exploration
North Beni Suef
The processing of c.130 km(2) of 3D seismic data on NBS is ongoing and
expected to complete by 4Q. The next steps are data mapping and
interpretation.
Financial Review
Finance strategy
There has been solid financial performance from our operations in the first
half of 2025 underpinning our strong liquidity position. Net cash has improved
to $22.6m from $16.5m as at 31 December 2024. The Group remains debt free
following the full and voluntary repayment of the RBL facility in September
2024. The El Fayum concession became profitable during 2024, reversing the
previous historical tax losses since first production, and this has led to a
gross-up of revenues and tax charge in the Income Statement by $1.1m in 1H
2025.
Returns to shareholders have been delivered through the completion in January
2025 of the third $3m share buyback programme and the payment of an interim
dividend for 2024 of 0.363 pence per share in January 2025. A final dividend
for 2024 of 0.847 pence per share was paid to shareholders in July 2025 and
the Board is pleased to also announce an interim dividend of 0.3993 pence per
share in respect of the year ended 31 December 2025. This dividend will be
paid on 21 January 2026 to shareholders on the Company's register of members
on 19 December 2025.
Key Data
1H 2025 1H 2024
Production Volumes (boepd) 5,642 5,851
Sales Volumes (boepd) 5,198 4,607
Oil Price Realised ($/bbl) 75.55 87.31
Oil & Gas Price Realised ($/boe) 68.48 77.71
Oil & Gas Sales ($m) 65.6 65.1
Total Revenue ($m)(1) 65.6 65.0
Gross Profit ($m) 16.7 32.0
Operating profit ($m) 12.2 35.2
Operating profit excluding impairment (reversal)/charge ($m)² 12.2 26.7
Net cash from operating activities (OCF $m) 16.1 27.9
Shareholder returns ($m) (2 3) 2.6 3.0
Cash operating cost per ($/boe)(2) 17.04 17.09
Net cash ($m)(2) 22.6 17.5
EBITDAX ($m)(2) 34.3 50.6
Gearing(2) - 0.05
(1) No realised hedge gains or losses in the period (1H 2024: realised hedge
losses of $0.1m)
(2) See Non-IFRS measures on page 30
(3) For 2025, includes $0.3m in respect of the $3m share buyback programme
(the Second Programme Extension), which completed in January 2025. Also,
Interim Group dividends of $2.3m in respect of the year ended 31 December
2025, announced in September 2025, will be paid to shareholders in January
2026.
Operating Performance - Income Statement
Revenue
Oil & gas revenues were maintained for the period at $65.6m (1H 2024:
$65.1m). This was despite a 12% decrease in Group average price realised.
Whilst Group production was down 4% to 5,642 boepd, actual sales volumes
increased 13% as additional cargoes were lifted from our oil inventories which
supported the revenues in the period.
In Vietnam, revenues increased 1% to $56.2m (1H 2024: $55.8m). Sales volumes
were higher by 14%, due to the timing of cargoes and maintenance shutdown at
the BSR-owned Dung Quat refinery in 1H 2024 to which TGT crude is sold. The
average realised crude oil price, including the premium received over Brent,
was $77.25/bbl (1H 2024: $89.07/bbl), a 13% decrease. The average premium to
Brent rose marginally to $5.67/bbl (1H 2024: $5.39/bbl).
In Egypt, revenues increased by 1% to $9.4m (1H 2024: $9.3m), inclusive of
$1.1m (1H 2024: $nil) gross-up for corporate income taxes to be paid by EGPC
on behalf of Pharos El Fayum. The average realised crude oil price, after
discounts, was $65.85/bbl (1H 2024: $78.30/bbl), a decrease of 16%. There are
two discounts applied to Egypt crude production - a general Western Desert
Discount and one related specifically to El Fayum and NBS fields. Both are set
by EGPC (the in-country regulator) and together increased to just over $6/bbl
(1H 2024: just under $6/bbl).
Hedging
For 2025, the Group entered into zero cost collar hedges to protect the Brent
component of forecast oil sales and to provide downside protection to cash
flows in the event of commodity prices falling. The commodity hedges run until
Dec 2025 and are settled monthly. Our hedging positions for the period
resulted in no realised gain or loss (1H 2024: $0.1m realised loss).
Additionally, the fair value as at 30 June 2025 was an unrealised gain of
$0.1m for the remaining hedges in place (1H 2024: unrealised loss of $0.8m).
For 2H 2025, 26% of the Group's total oil entitlement production has been
hedged, securing average floor and ceiling prices for the hedged volumes at
$61.3/bbl and $84.5/bbl, respectively.
Group operating costs, DD&A and expenses
Cost of sales, inclusive of cash and non-cash elements, were 48% higher at
$48.9m (1H 2024: $33.0m), and these results also capture the impairment
reversal of financial asset in relation to EGPC receivables. There was a
$16.7m change in inventories period on period as a result of the inventory
build in 1H 2024 due to maintenance shutdown at the BSR-owned refinery in
Vietnam and this build reduced in 1H 2025 with extra cargoes supporting the 1H
2025 revenue numbers. This effect, combined with a 20% reduction in June 2025
closing Brent price (plus premium) used for inventory valuation year on year
(June 2025: $73.77/bbl; June 2024: $92.61/bbl), increased cost of sales in the
period. Operating costs in Egypt increased 135% to $4.7m (1H 2024: $2.0m) and
this was principally due to a credit of $2.7m in 1H 2024 relating to reversal
of expected credit losses on EGPC trade receivables. However, the underlying
cash operating costs decreased in 1H 2025 to $17.4m versus $18.2m in 1H 2024,
see table below.
DD&A charges on production and development assets decreased to $21.8m (1H
2024: $23.8m), driven by the 4% reduction in Group production volumes.
DD&A per bbl is currently $21.35/boe (1H 2024: $22.35/boe).
Administrative expenses of $4.1m (1H 2024: $4.7m) were 13% lower. After
adjusting for non-cash share based payment charges of $0.3m (1H 2024: $0.3m),
the underlying administrative expenses were $3.8m (1H 2024: $4.4m).
Other operating expenses of $0.2m (1H 2024: $0.6m) were 67% lower. In the
prior year, $0.6m related to the posthumous vesting of share scheme awards to
the former CEO of the Company, which was formally approved by the Remuneration
Committee, settled in cash and paid to his estate with the agreement of the
executor.
Cash Operating Costs
Cash operating costs at Group level, defined in the Non-IFRS measures section
on page 30 and shown below, amounted to $17.4m (1H 2024: $18.2m), a 4%
decrease over the same period last year. On a barrel of oil equivalent basis,
this was $17.04/boe (1H 2024: $17.09/boe).
Cash operating costs in Vietnam decreased to $12.6m (1H 2024: $13.6m) in the
period which equates to $16.64/bbl (1H 2024: $16.77/bbl). The decrease is
primarily driven by lower costs relating to the FPSO as a result of higher
production from TLJOC, which shares the facilities and the costs of the FPSO
based on production rates (28.1% cost share in 1H 2025 compared to 23.0% in 1H
2024). This was partially offset by 6% lower production in 1H 2025.
Cash operating costs in Egypt were $4.8m (1H 2024: $4.6m) in the period, which
equates to $18.18/bbl (1H 2024: $18.12/bbl). The 4% increase in cash operating
costs was driven by increased transportation and chemical costs, and higher
cost of well workovers.
(unaudited) (unaudited)
six months ended six months ended
30 Jun 25 30 Jun 24
Cash operating costs per barrel $ million $ million
Cost of sales (1) 48.9 33.0
(Less)/add:
Depreciation, depletion and amortisation (21.8) (23.8)
Production based taxes (3.9) (4.9)
Change in inventories (5.0) 11.9
Trade receivables expected credit loss 0.1 2.7
Other cost of sales (0.9) (0.7)
Cash operating costs 17.4 18.2
Production (BOEPD) 5,642 5,851
Cash operating cost per BOE ($) 17.04 17.09
(1) Includes impairment reversal of financial asset
Financing costs
Finance costs for the period were significantly lower at $1.2m (1H 2024:
$2.6m) due to full voluntary repayment of the Group's RBL facility during
September 2024. The unwinding of discount on Vietnam decommissioning
provisions for 1H 2025 was $1.2m (1H 2024: $1.0m).
In 1H 2024, there was also interest expense and similar fees of $1.1m and
foreign exchange losses of $0.5m, primarily driven by the devaluation of EGP
against USD.
Taxation
The overall net tax charge of $13.3m (1H 2024: $18.3m) principally relates to
tax charges in Vietnam of $12.2m (1H 2024: Vietnam tax charges of $18.3m).
The Group's effective tax rate approximates the statutory tax rate in Vietnam
of 50%, after adjusting for non-deductible expenditure and tax losses not
recognised.
The Egypt concessions are subject to corporate income tax at the standard rate
of 40.55%, however responsibility for payment of corporate income taxes falls
upon EGPC on behalf of PEF and the other contractor parties. The Group records
a tax charge, with a corresponding increase in revenue, for the tax paid by
EGPC on its behalf. PEF became profitable at the end of 2024, reversing the
historic tax loss position since first production, and this led to a 1H 2025
tax charge of $1.1m (1H 2024: $nil).
One of the Group's companies entered into commodity zero cost collars
designated as cash flow hedges. In accordance with IAS 12, a deferred tax
asset has not been recognised in relation to historic hedging losses as it is
unlikely that the UK tax group will generate sufficient taxable profit in the
future, against which the deductible temporary differences can be utilised.
Net loss/profit
The post-tax loss for the period of $(2.8)m (1H 2024: $15.3m post-tax profit)
included $(0.6)m of restructuring expenses, re-measurements and impairments
(1H 2024: $12.6m) which are shown in the table below. Business performance
post-tax loss for the period was $(2.2)m (1H 2024: $2.7m post-tax profit).
Restructuring expenses, re-measurements and impairments are comprised of the
following:
Financial Statements Impact: 1H 2025 1H 2024
$m $m
(Loss)/profit for the period (2.8) 15.3
Impact of restructuring expense, re-measurements and impairments
Revenue - 0.1 Realised hedging losses
Cost of sales (0.1) (2.7) Trade receivables expected credit loss
Impairment reversal - Property, plant and equipment - (8.5)
Other/restructuring expenses - 0.4 Egypt redundancy cost following farm down
Loss/(gain) on fair value movement of financial asset 0.7 (1.2) Revision of contingent consideration in relation to Egypt farm-out
Finance costs - (0.7) Adjustment and amortisation of capitalised borrowing costs
0.6 (12.6)
Business performance post-tax (loss)/profit * (2.2) 2.7
* A non-GAAP measure of underlying net profit from operations, which takes out
the impact of unusual, non-recurring transactions and the impact of non-cash
re-measurements and impairments.
Balance Sheet
Impairments and Impairment Reversals
We have evaluated each of our oil and gas producing properties for impairment
or impairment reversal triggers. The average Brent price forecast as at HY
2025 fell by only 6.8% for 2025 to 2027 and 4.6% in the longer-term and does
not indicate a significant change in the underlying value of oil and gas
assets. Furthermore, there were no significant changes to the weighted average
cost of capital (WACC) and forecast production volumes for both Vietnam and
Egypt assets compared to 2024 year end.
As a result, after examining both internal and external indicators of
impairment, the Group determined that no impairments or impairment reversal
indicators were identified on any of the Group's oil and gas producing
properties and no impairment tests were considered necessary as at 30 June
2025.
As at 30 June 2025, the carrying amount of the TGT oil and gas producing
property, after additions of $0.9m, increase in decommissioning asset of $0.7m
and DD&A of $14.9m, is $140.3m (Jun 2024: $141.2m; Dec 2024: $153.6m). As
at 30 June 2025, the carrying amount of the CNV oil and gas producing
property, after additions of $0.5m, increase in decommissioning asset of $0.3m
and DD&A of $4.2m, is $56.8m (Jun 2024: $59.9m; Dec 2024: $60.2m).
As at 30 June 2025, the carrying amount of the El Fayum oil and gas producing
property, after additions of $0.7m, transfer from intangibles of $2.9m and
DD&A of $2.6m, is $59.5m (Jun 2024: $62.0m; Dec 2024: $58.5m). As at 30
June 2025, the carrying amount of the NBS oil and gas producing property,
after DD&A of $0.1m, is $1.0m (Jun 2024: $1.2m; Dec 2024: $1.1m).
Cash flow
Operating cash flow (before movements in working capital) was $33.5m (1H 2024:
$50.9m). After tax charges of $15.9m (1H 2024: $16.2m), other/restructuring
costs of $nil (1H 2024: $0.4m), working capital outflow of $1.6m (1H 2024:
$6.6m outflow) and interest received of $0.1m (1H 2024: $0.2m), the cash
generated from operations was $16.1m (1H 2024: $27.9m). This highlights the
continuing strong operating performance from the producing fields in Vietnam
and Egypt, despite 13% fall in Group realised oil price.
Cash generated from operations, after tax charges, exceptional expenses and
working capital movements, is the basis of our dividend framework.
There was an increase in receivables of $5.0m for the period (1H 2024:
decrease of $6.8m). $2.9m increase relates to Egypt trade receivables (2024:
$3.4m decrease) following reduced recovery from EGPC during the first half of
2025. Vietnam trade and other receivables increased by $1.6m (2024: decrease
of $3.3m), primarily linked to the timing of liftings (3 cargoes in June 2025
compared to 2 cargoes in December 2024). Inventory decreased by $5.0m (1H
2024: increase of $11.9m) and this was driven by Vietnam operations and the
timing of liftings from TGT. Vietnam revenue volumes overall were up 14%
compared to 1H 2024 and, combined with lower production and a reduced
commodity price environment, this led to a reduction in inventory compared to
the inventory build in 1H 2024. Trade and other payables were a cash outflow
of $1.6m (1H 2024: $1.5m).
Share Buyback and Dividends
In January 2025, the third and final $3.0m tranche of the Company's share
buyback programme initiated in July 2022 was completed. Although there is
currently no active share buyback programme, the Board will keep the
possibility of further buybacks under consideration as part of the Company's
commitment to shareholder returns.
Pharos has a clear sustainable policy for regular dividend payments and this
has been set at returning no less than 10% of Operating Cash Flow (OCF) each
year in two tranches
- An interim dividend payable in January of the following year;
and
- A final dividend payable in July of the following year.
An interim dividend of 0.363 pence per share in respect of the year ended 31
December 2024, $1.8m equivalent, was paid on 22 January 2025 to shareholders
on the Company's register as at 20 December 2024.
A final dividend of 0.847 pence per share in respect of the year ended 31
December 2024, $4.7m equivalent, was approved by the shareholders at the
Company's AGM in May 2025 and subsequently paid on 18 July 2025 to
shareholders on the register at the close of business on 13 June 2025. This
took the 2024 full year dividend to 1.21 pence per share.
The Board has resolved to pay an interim dividend of 0.3993 pence per share,
$2.3m equivalent, in respect of the year ended 31 December 2025 and this will
be paid on 21 January 2026 to shareholders on the Company's register as at 19
December 2025.
Liquidity risk management and going concern
The Group continuously monitors its business activities, financial position,
cash flows and liquidity. Cash forecasts are regularly produced, and stress
tested for several scenarios including a downturn in the oil price and adverse
changes in production rates. Given the current rapidly changing global
political and economic landscape, and fluctuations in oil price, inflation and
interest rates, the scope of our scenario planning remains extensive.
Accordingly, stress tests have been run for oil prices down to $45.2/bbl in
September 2025, 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 2025, the Group had a cash
balance of $22.6m with improved liquidity and no debt. 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. Based on this analysis, the
Directors have a reasonable expectation that the Group has adequate resources
to continue its operations in the foreseeable future. Therefore, they continue
to adopt the going concern basis of accounting in preparing these half-year
results.
Sue Rivett
Chief Financial Officer
Corporate Review
Environmental, Social, and Governance (ESG)
Pharos continues to prioritise sustainability in everything we do. We
recognise the importance of environmental stewardship, social responsibility,
and corporate governance in the energy industry, and continue to demonstrate
our commitment to our Net Zero by 2050 target by managing our emissions across
the portfolio.
In 1H 2025, the Group's Scope 1 and 2 emissions remained at the same level
compared to the same time last year. The continuation of various
emission-reduction projects to upgrade energy efficiency and reduce flaring in
Vietnam, and the continuous usage of our diesel replacement gas generators in
Egypt, were key drivers behind our stable emission level, which is a reduction
compared to our 2021 baseline. Most recently, our field operations in Egypt
are now connected to the national electrical grid, which further reduce the
consumption of carbon-intensive fuel in our field operations.
We are proud of our social initiatives which have been an important part of
Pharos since inception. For 1H 2025, the Company invested in 20 social and
community projects, ranging from providing educational support for children
with disabilities to supporting low-income communities. Pharos will continue
to work closely with our local partners and joint ventures to ensure our
social initiatives bring positive, sustainable impacts to host countries and
the local communities.
On corporate governance, over the past few years, the Board has undergone
leadership changes to maintain a high standard of governance. The Board is
refreshed, resilient, and strong. Pharos will continue to have positive and
regular engagements with shareholders and are grateful for their continued
trust and support.
Principal and emerging risks and uncertainties for the second half of 2025
The Board continues to fulfil its role in risk oversight by developing
policies and procedures around risks that are consistent with the
organisation's strategy and risk appetite.
Pharos carried out an assessment of its principal and emerging risks at half
year 2025. There has been no change in the principal and emerging risk from
December 2024. The key principal and emerging risks are:
· HSE & Social
· Political and regional instability, including conflicts and
ensuing sanctions
· Risk of rising inflation and stagflation
· Climate change
· Commodity price volatility
· Partners' alignment
· Sub-optimal capital allocation
· Cyber security
· Reserves downgrades
· Insufficient funds to meet commitments
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.
On behalf of the Board:
Katherine
Roe
Sue Rivett
Chief Executive Officer
Chief Financial Officer
23 September 2025
23 September 2025
INDEPENDENT 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 2025 which comprises the interim condensed consolidated income statement,
the interim condensed consolidated statement of other comprehensive income,
the interim condensed consolidated balance sheet, the interim condensed
consolidated statement of changes in equity, the interim condensed
consolidated cash flow statement and the related explanatory notes 1-15. We
have read the other information contained in the half yearly financial report
and considered whether it contains any apparent misstatements or material
inconsistencies with the information in the condensed set of financial
statements.
Based on our review, nothing has come to our attention that causes us to
believe that the condensed set of financial statements in the half-yearly
financial report for the six months ended 30 June 2025 is not prepared, in all
material respects, in accordance with UK 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 2410 (UK) "Review of Interim Financial Information Performed by
the Independent Auditor of the Entity" (ISRE) issued by the Financial
Reporting Council. A review of interim financial information consists of
making enquiries, 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 UK adopted international accounting standards. The
condensed set of financial statements included in this half-yearly financial
report has been prepared in accordance with UK adopted International
Accounting Standard 34, "Interim Financial Reporting".
Conclusions 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 management have
inappropriately adopted the going concern basis of accounting or that
management 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
this ISRE, 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 company'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 report, we are responsible for expressing to the
Company a conclusion on the condensed set of financial statements in the
half-yearly financial report. Our conclusion, including our Conclusions
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 guidance
contained in International Standard on Review Engagements 2410 (UK) "Review of
Interim Financial Information Performed by the Independent Auditor of the
Entity" issued by the Financial Reporting Council. To the fullest extent
permitted by law, we do not accept or assume responsibility to anyone other
than the company, for our work, for this report, or for the conclusions we
have formed.
Ernst & Young LLP
London
23 September 2025
interim Condensed consolidated income statement
(unaudited) (unaudited) Year ended
Six months ended Six months ended
30 Jun 2025 30 Jun 2024 31 Dec 2024
Notes $ million $ million $ million
Revenue 3, 13 65.6 65.0 136.0
Cost of sales 4 (49.0) (35.7) (89.8)
Impairment reversal - Financial asset 4 0.1 2.7 2.5
Gross profit 16.7 32.0 48.7
Administrative expenses (4.1) (4.7) (9.1)
Other operating costs 5 (0.2) (0.6) (0.8)
Pre-licence costs 3 (0.2) - (0.8)
Impairment charge - Intangible assets 3, 9 - - (2.0)
Impairment reversal - Property, plant and equipment 3, 10 - 8.5 28.3
Operating profit 12.2 35.2 64.3
Other/restructuring expense 5 - (0.4) (0.4)
(Loss)/gain on fair value movement of financial asset 3 (0.7) 1.2 0.3
Investment revenue 0.2 0.2 0.4
Finance costs 6 (1.2) (2.6) (3.9)
Profit for the period before tax 3 10.5 33.6 60.7
Income tax charge 7 (13.3) (18.3) (37.1)
(Loss)/profit for the period (2.8) 15.3 23.6
(Loss)/profit per share (cents) 8
Basic (0.7) 3.7 5.7
Diluted (0.7) 3.6 5.4
interim Condensed consolidated statement of OTHER comprehensive income
(unaudited) (unaudited) Year ended
Six months ended Six months ended
30 Jun 2025 30 Jun 2024 31 Dec 2024
Notes $ million $ million $ million
(Loss)/profit for the period (2.8) 15.3 23.6
Items that may be subsequently reclassified to profit or loss:
Fair value loss arising on hedging instruments 13 during the period - (0.9) (0.1)
Less: Loss arising on hedging instruments reclassified to profit or loss 0.1 0.1 0.1
Net currency exchange translation differences 0.1 - -
Total comprehensive (loss)/income for the period (2.6) 14.5 23.6
The above interim condensed consolidated income statement and interim
condensed consolidated statement of other comprehensive income should be read
in conjunction with the accompanying notes.
interim CONDENSED CONSOLIDATED Balance sheets
(unaudited) (unaudited)
30 Jun 25 30 Jun 24 31 Dec 24
Restated (1) Restated (1)
Notes $ million $ million $ million
Non-current assets
Intangible assets 9 23.7 20.1 21.8
Property, plant and equipment 10 257.7 264.3 273.5
Right of use asset 10 0.1 0.4 0.2
Other assets 57.8 57.3 57.8
339.3 342.1 353.3
Current assets
Inventories 4.3 15.2 9.3
Trade and other receivables 52.9 52.4 47.8
Derivative financial instruments 13 0.2 - 0.1
Tax receivables 0.4 0.3 0.3
Cash and cash equivalents 22.6 30.7 16.5
80.4 98.6 74.0
Total assets 419.7 440.7 427.3
Current liabilities
Trade and other payables (12.3) (14.6) (14.3)
Derivative financial instruments 13 - (0.7) -
Borrowings 14 - (13.8) -
Lease Liabilities (0.2) (0.3) (0.2)
Tax payables (2.8) (5.3) (3.2)
(15.3) (34.7) (17.7)
Net current assets 65.1 63.9 56.3
Non-current liabilities
Other payables - (0.2) (0.2)
Deferred tax liabilities (59.4) (64.3) (62.6)
Lease Liabilities - (0.1) -
Long term provisions (53.2) (52.9) (51.1)
(112.6) (117.5) (113.9)
Total liabilities (127.9) (152.2) (131.6)
Net assets 291.8 288.5 295.7
Equity
Share capital 33.0 33.4 33.1
Share premium 58.0 58.0 58.0
Other reserves 259.1 255.9 258.1
Retained deficit (58.3) (58.8) (53.5)
Total equity 291.8 288.5 295.7
(1) See Note 2
The above interim condensed consolidated balance sheets should be read in
conjunction with the accompanying notes.
interim CONDENSED consolidated STATEMENTs OF CHANGES IN EQUITY
Called up share capital Share Premium Other reserves Retained (deficit)/ Total
earnings
$ million $ million $ million $ million $ million
As at 1 January 2024, Restated (3) 33.7 58.0 255.4(1) (67.0) 280.1
Profit for the period - - - 15.3 15.3
Other comprehensive loss - - (0.8) - (0.8)
Share buy back (2) (0.3) - 0.3 (1.1) (1.1)
Distributions to shareholders - - - (5.8) (5.8)
Share-based payments - - 0.8 - 0.8
Transfer relating to share-based payments - - 0.2 (0.2) -
As at 30 June 2024 (unaudited), Restated (3) 33.4 58.0 255.9(1) (58.8) 288.5
Profit for the period - - - 8.3 8.3
Other comprehensive income - - 0.8 - 0.8
Share buy back (2) (0.3) - 0.3 (1.8) (1.8)
Shares purchased - - (0.9) - (0.9)
Distributions to shareholders - - - (0.1) (0.1)
Share-based payments - - 0.9 - 0.9
Transfer relating to share-based payments - - 1.1 (1.1) -
As at 1 January 2025, Restated (3) 33.1 58.0 258.1(1) (53.5) 295.7
Loss for the period - - - (2.8) (2.8)
Other comprehensive income - - 0.2 - 0.2
Share buy back (2) (0.1) - 0.1 (0.3) (0.3)
Distributions to shareholders - - - (1.8) (1.8)
Share-based payments - - 0.8 - 0.8
Transfer relating to share-based payments - - (0.1) 0.1 -
As at 30 June 2025 (unaudited) 33.0 58.0 259.1 (58.3) 291.8
(1 )Includes $137.1m as Merger Reserve which is fully distributable.( )
(2 )During 1H 2025, the Company repurchased 905,087 shares at an average
price of 26.46 pence per share (1H 2024: 4,073,265 shares at average price of
22.01 pence per share; 2024: 9,725,763 at an average price of 23.41 pence per
share).( )
(3 )See Note 2
The above interim condensed consolidated statements of changes in equity
should be read in conjunction with the accompanying notes.
interim condensed consolidated cash flow statements
(unaudited) (unaudited) Year ended
Six months ended Six months
ended
30 Jun 2025 30 Jun 2024 31 Dec 2024
Notes $ million $ million $ million
Net cash from operating activities 12 16.1 27.9 54.0
Investing activities
Purchase of intangible assets (3.0) (1.9) (5.4)
Purchase of property, plant and equipment (3.3) (3.8) (18.4)
Consideration in relation to farm out of Egyptian assets(1) - 5.0 5.0
Contingent consideration received in relation to farm out of Egyptian assets 0.7 3.6 3.6
Assignment fee in relation to farm out of Egyptian assets - (0.4) (0.4)
Payment to abandonment fund (1.9) (1.1) (2.3)
Net cash (used in)/from investing activities (7.5) 1.4 (17.9)
Financing activities
Proceeds from borrowings 14 - 2.2 2.2
Interest paid on borrowings 14 - (1.8) (2.4)
Repayment of borrowings 14 - (28.2) (41.4)
Lease payments (0.2) (0.2) (0.3)
Share buy back (0.3) (1.1) (2.9)
Share purchase - - (0.9)
Share-based payments - 0.1 -
Dividends paid to shareholders (1.8) (1.8) (5.9)
Net cash used in financing activities (2.3) (30.8) (51.6)
Net increase/(decrease) in cash and cash equivalents 6.3 (1.5) (15.5)
Cash and cash equivalents at beginning of period 16.5 32.6 32.6
Effect of foreign exchange rate changes (0.2) (0.4) (0.6)
Cash and cash equivalents at end of period 22.6 30.7 16.5
(1) During 2024 IPR, acting as operator and agent, was authorised to settle
its operating liabilities of $3.7m and investing liabilities of $1.3m against
the consideration due from the associated carry debtor amounting to $5.0m. The
Company has disclosed the underlying cash flows as operating, investing or
financing according to their nature on the basis that, as a principal, the
entity has the right to the cash inflows and/or the obligation to settle the
liability and ensure clarity of disclosure of the operating cash costs of the
business.
The above interim condensed consolidated cash flow statements should be read
in conjunction with the accompanying notes.
Notes to the interim condensed consolidated financial statements
1. General information
The Interim condensed financial statements for the six-month period ended 30
June 2025 have been prepared in accordance with International Accounting
Standards ("IAS") 34 Interim Financial Reporting as adopted by the UK and the
requirements of the Disclosure and Transparency Rules ("DTR") of the Financial
Conduct Authority (FCA) in the United Kingdom as applicable to interim
financial reporting.
The interim condensed financial statements represent a 'condensed set of
financial statements' as referred to in the DTR issued by the FCA.
Accordingly, they do not include all the information required for a full
annual financial report and are to be read in conjunction with the Group's
financial statements for the year ended 31 December 2024, which were prepared
in accordance with UK-adopted International Accounting Standards ("IFRSs") in
conformity with the requirements of the Companies Act 2006 and International
Financial Reporting Standards as issued by the International Accounting
Standard Board (IASB) and endorsed by the UK Endorsement Board (UKEB). The
interim condensed financial statements are unaudited and do not constitute
statutory accounts as defined in section 434 of the Companies Act 2006. The
financial information for the year ended 31 December 2024 does not constitute
statutory accounts as defined in section 434 of the Companies Act 2006. This
information was derived from the statutory accounts for the year ended 31
December 2024, a copy of which has been delivered to the Registrar of
Companies. The auditor's report on these accounts was unqualified, did not
include a reference to any matters to which the auditor drew attention by way
of an emphasis of matter and did not contain a statement under sections 498
(2) or (3) of the Companies Act 2006.
The half-year financial report for the six months ended 30 June 2025 was
approved by the Directors on 23 September 2025.
2. Accounting policies
The annual financial statements of Pharos Energy plc will be prepared in
accordance with UK-adopted IFRSs. The interim condensed set of financial
statements included in this half-yearly financial report has been prepared in
accordance with IAS 34 'Interim Financial Reporting' as adopted by the UK and
the Disclosure Guidance and Transparency Rules of the United Kingdom's FCA
DTR. The accounting policies adopted in the June 2025 interim condensed set of
financial statements are the same as those adopted in the Group's Annual
Report and Accounts as at 31 December 2024.
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 2024 and
any public announcements made by Pharos during the interim reporting period.
Restatement
Comparative information in respect of the deferred tax liability has been
restated in relation to an adjustment made to correct excess cost recovery
considered in the deferred tax calculations in respect of years prior to
2024. The deferred tax liability as at 31 December 2024 and 30 June 2024 was
overstated by $4.9m. As a result of the correction, the deferred tax liability
decreased from $67.5m to $62.6m as at 31 December 2024 and from $69.2m to
$64.3m as at 30 June 2024. As the error related to years prior to 2024, the
opening retained deficit has been restated, resulting in a decrease from
$(71.9)m to $(67.0)m as at 1 January 2024, from $(63.7)m to $(58.8)m as at 30
June 2024, and from $(58.4)m to $(53.5)m as at 31 December 2024.
Going Concern
The Group continuously monitors its business activities, financial position,
cash flows and liquidity through detailed forecasts. Scenarios and
sensitivities are also regularly presented to the Board, including changes in
commodity prices and in production levels from the existing assets, plus other
factors that could affect the Group's future performance and position. These
events include:
· A material reduction in the oil price putting pressure on the
Group's capital available for investment
· A reduction in production
· An unfavourable event resulting in lost production and oil price
shock
A base case forecast has been considered that utilises oil prices of $69.0/bbl
in 2025 and $67.2/bbl in 2026. The key assumptions and related sensitivities
include a "Reasonable Worst Case" (RWC) scenario, where the Board has taken
into account the risk of a significant fall in oil prices by a third to
$45.2/bbl in September 2025 and gradually recovers to the base case price over
the next 12 months, concurrent with 5% reductions in Vietnam and Egypt
production compared to our base case from September 2025. Both the base case
and RWC take into account effect of hedging that has already been put in place
at 30 June 2025 and subsequent hedges placed in 2025, now covering c. 26% of
the Group's 2H 2025 total oil entitlement production. We have secured an
average floor price and ceiling price of $61.3/bbl and $84.5/bbl respectively
for the entire hedged volumes. Under the RWC scenario, we have identified
appropriate mitigating actions which could look to reduce head office G&A
by $2.0m for 2025 and not making any dividend distributions during 2026.
In addition, a revere stress test has been performed to test for a further
decline in oil price, including mitigating actions, to determine at what
levels oil price would need to reach such that liquidity headroom runs out.
The likelihood of Brent price dropping to such levels throughout the going
concern period is considered to be remote.
As at 30 June 2025, the Group had a net cash balance and improved liquidity of
$22.6m (Dec 2024: $16.5m). On the basis of the forecasts provided above, the
Group is expected to have sufficient financial headroom for the period of 12
months from the date of approval of these half-year results. Based on this
analysis, the Directors have a reasonable expectation the Group has adequate
resources to continue its operations in the foreseeable future. Therefore, the
half-year results have been prepared using the going concern basis of
accounting.
New and amended standards adopted by the Group
Amendments that apply for the first time in 2025, but do not have an impact on
the interim condensed consolidated financial statements of the Group are:
· Lack of exchangeability - Amendments to IAS 21
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 were applied for oil and gas assets.
(b) Key sources of estimation uncertainty
The key assumptions concerning the future, and other key sources of estimation
uncertainty at the balance sheet date, 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, including the impact on DD&A; and (ii)
impairment of producing oil & gas assets.
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 (SE 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 2025 (unaudited) SE Asia Egypt Unallocated(1) Group
$ million $ million $ million $ million
Oil and gas sales 56.2 9.4 - 65.6
Realised loss on commodity hedges (see Note 13) - - - -
Total revenue 56.2 9.4 - 65.6
Cost of sales (41.1) (7.9) - (49.0)
Impairment reversal - Financial asset - 0.1 - 0.1
Administrative expenses - - (4.1) (4.1)
Depreciation, depletion and amortisation - oil and gas (19.1) (2.7) - (21.8)
Depreciation, depletion and amortisation - other - (0.1) - (0.1)
Other operating costs - - (0.2) (0.2)
Pre-licence costs - (0.2) - (0.2)
Loss on fair value movement of financial asset(2) - (0.7) - (0.7)
Profit/(loss) before tax 13.8 0.9 (4.2) 10.5
Tax charge on operations (see Note 7) (12.2) (1.1) - (13.3)
Non-current assets(3) 221.0 60.5 - 281.5
Six months ended 30 June 2024 (unaudited) SE Asia Egypt Unallocated(1) Group
$ million $ million $ million $ million
Oil and gas sales 55.8 9.3 - 65.1
Realised loss on commodity hedges (see Note 13) - - (0.1) (0.1)
Total revenue 55.8 9.3 (0.1) 65.0
Cost of sales (28.7) (7.0) - (35.7)
Impairment reversal - Financial asset - 2.7 - 2.7
Administrative expenses - - (4.7) (4.7)
Depreciation, depletion and amortisation - oil and gas (21.5) (2.3) - (23.8)
Depreciation, depletion and amortisation - other - (0.1) - (0.1)
Other operating costs - - (0.6) (0.6)
Impairment reversal - PP&E - 8.5 - 8.5
Gain on fair value movement of financial asset(2) - 1.2 - 1.2
Profit/(loss) before tax 25.9 14.0 (6.3) 33.6
Tax charge on operations (see Note 7) (18.3) - - (18.3)
Non-current assets(3) 219.2 65.6 - 284.8
Year end 31 December 2024 SE Asia Egypt Unallocated(1) Group
$ million $ million $ million $ million
Oil and gas sales 115.4 20.7 - 136.1
Realised loss on commodity hedges - - (0.1) (0.1)
Total revenue 115.4 20.7 (0.1) 136.0
Cost of sales (75.6) (14.2) - (89.8)
Impairment reversal - Financial asset - 2.5 - 2.5
Administrative expenses - - (9.1) (9.1)
Depreciation, depletion and amortisation - oil and gas (42.1) (5.0) - (47.1)
Depreciation, depletion and amortisation - other - (0.2) - (0.2)
Other operating costs - - (0.8) (0.8)
Pre-licence costs - - (0.8) (0.8)
Impairment charge - Intangibles assets - (2.0) - (2.0)
Impairment reversal - PP&E 23.4 4.9 - 28.3
Gain on fair value movement of financial asset(2) - 0.3 - 0.3
Profit/(loss) before tax 60.9 11.3 (11.5) 60.7
Tax charge on operations (see Note 7) (26.8) (1.9) - (28.7)
Tax charge on impairment reversal (see Note 7) (8.4) - - (8.4)
Non-current assets(3) 233.5 62.0 - 295.5
( )
(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) Relates to the revision of contingent consideration due from the farm-out
of the Egyptian concessions with IPR, partially offset by the movement in
contingent liability (assignment fee) owed to EGPC.
(3) Excludes Other assets.
4. Cost of sales
(unaudited) six months ended (unaudited) six months ended Year ended 31 Dec 2024
30 Jun 2025 30 Jun 2024
$ million $ million $ million
Depreciation, depletion and amortisation 21.8 23.8 47.1
Production based taxes 3.9 4.9 9.2
Production operating costs 18.3 18.9 39.5
Change in inventories 5.0 (11.9) (6.0)
49.0 35.7 89.8
Impairment reversal - financial asset (0.1) (2.7) (2.5)
48.9 33.0 87.3
5. Other Operating Costs and Other/restructuring expense
(unaudited) six months ended (unaudited) six months ended Year ended 31 Dec 2024
30 Jun 2025 30 Jun 2024
$ million $ million $ million
Other operating costs
Share based payments - 0.6 0.6
Other 0.2 - 0.2
0.2 0.6 0.8
Other/restructuring expense
Redundancy costs - 0.4 0.4
- 0.4 0.4
In 1H 2024, other operating costs of $0.6m relate to the posthumous vesting of
share scheme awards to the former CEO of the Company, settled in cash and paid
to his estate with the agreement of the executor. This cash settlement was
provided for in the relevant share scheme rules and formally approved by the
Remuneration Committee.
In 1H 2024, Other/restructuring expenses included $0.4m of redundancy costs
relating to the Egypt office in Cairo.
6. Finance Costs
(unaudited) six months ended (unaudited) six months ended Year ended 31 Dec 2024
30 Jun 2025 30 Jun 2024
$ million $ million $ million
Unwinding of discount on provisions 1.2 1.0 2.2
(1)
Interest expense and similar fees (2) (see Note - 1.1 1.1
14)
Net foreign exchange losses - 0.5 0.6
1.2 2.6 3.9
(1) For 1H 2025, $1.2m relates to the unwinding of discount on the provisions
for decommissioning (1H 2024: $1.0m). The provisions are based on the net
present value of the Group's share of the expenditure which will be incurred
at the end of the life of TGT and CNV (currently estimated to be 7-8 years) in
the removal and decommissioning of the facilities currently in place.
(2) Following the June 2024 redetermination and the $20.0m repayment of
principal in relation to the Group's reserve based lending facility, there was
a change in estimated future cash flows. As a result, in 1H 2024, a credit of
$(0.1)m was recognised in the income statement.
(2) The RBL loan facility was voluntarily repaid early and in full on 17
September 2024 and, in full year 2024, a credit of $1.3m was recognised in the
income statement.
7. Tax
(unaudited) six months ended (unaudited) six months ended Year ended 31 Dec 2024
30 Jun 2025 30 Jun 2024
$ million $ million $ million
Current tax
Corporation tax 16.5 15.8 36.0
Adjustments to tax charge in respect of previous periods - 1.5 1.8
16.5 17.3 37.8
Deferred tax
Deferred tax (credit)/charge on operations (3.2) 1.0 (9.1)
Deferred tax charge on net impairment reversal - - 8.4
(3.2) 1.0 (0.7)
Total tax charge 13.3 18.3 37.1
The Group's corporation tax is calculated at 50% (1H 2024: 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 on behalf of the
Group. During each period, both current and deferred taxation have arisen in
overseas jurisdictions only.
The charge for the period can be reconciled to the profit per the income
statement as follows:
(unaudited) six months ended (unaudited) six months ended Year ended 31 Dec 2024 $ million
30 Jun 2025 $ million 30 Jun 2024 $ million
Profit before tax 10.5 33.6 60.7
Tax at 50% (2024: 50%) 5.3 16.8 30.4
Effects of:
Non-taxable income - - (5.8)
Non-deductible expenses 6.3 4.0 8.1
Egypt taxation at a different rate to Vietnam effective tax rate (0.1) - (2.0)
Tax losses not recognised 1.8 (4.0) 4.9
Utilisation of tax losses - - (0.3)
Adjustments to current tax in respect of previous periods - 1.5 1.8
Tax charge for the period 13.3 18.3 37.1
The prevailing tax rate in Vietnam, where the Group produces oil and gas, is
50% (1H 2024: 50%). The tax charge in future periods may also be affected by
the factors in the reconciliation above.
In full year 2024, non-taxable income relates to the tax impact of Vietnam
impairment reversals of $(3.3)m in relation to the non-cost recovery pool and
Egypt impairment reversal of $(2.5)m.
Non-deductible expenses primarily relate to Vietnam DD&A charges
for costs previously capitalised, which are non-deductible for Vietnamese tax
purposes of $5.3m (1H 2024: $3.8m; Dec 2024: $6.2m). 1H 2025 also includes
$0.7m of non-deductible expenses for Egypt operations. A further $0.3m (1H
2024: $0.2m; Dec 2024: $0.9m) relates to non-deductible corporate costs
including share scheme incentives. In the year ended 31 December 2024,
non-deductible expenses also included the tax impact of Egypt intangible
impairment charges of $1.0m.
The Egypt concessions are subject to corporate income tax at the standard rate
of 40.55%, however responsibility for payment of corporate income taxes falls
upon EGPC on behalf of PEF. The Group records a tax charge, with a
corresponding increase in revenue, for the tax paid by EGPC on its behalf. As
PEF became profitable during 2024, reversing the historic tax loss position
since first production, this has resulted in $1.1m (1H 2024: $nil; Dec 2024:
$1.9m) tax charge being recorded in 1H 2025. The effect from tax losses not
recognised in 1H 2025 and 2024 relates to costs, primarily of the Company,
deductible for tax in the UK but not expected to be utilised in the
foreseeable future.
8. Earnings per share
The calculation of the basic and diluted earnings per share is based on the
following data:
(unaudited) six months ended (unaudited) Year ended 31 Dec 2024
30 Jun 2025 six months ended
30 Jun 2024
$ million $ million $ million
(Loss)/gain for the purposes of basic earnings per share (2.8) 15.3 23.6
Effect of dilutive potential ordinary shares - Cash settled share awards and - (0.3) (0.9)
options
(Loss)/gain for the purposes of diluted earnings per share (2.8) 15.0 22.7
(unaudited) six months ended
30 Jun 2025 (unaudited) six months ended Year ended 31 Dec 2024
30 Jun 2024
million million million
Weighted average number of ordinary shares 412.3 419.3 417.0
Effect of dilutive potential ordinary shares - Share awards and options - 1.8 2.7
Weighted average number of ordinary shares for the purpose of diluted 412.3 421.1 419.7
(loss)/profit per share
(unaudited) six months ended
30 Jun 2025 (unaudited) six months ended Year ended 31 Dec 2024
30 Jun 2024
million million million
Weighted average number of ordinary shares 412.3 419.3 417.0
Effect of dilutive potential ordinary shares - Share awards and options - 1.8 2.7
Weighted average number of ordinary shares for the purpose of diluted 412.3 421.1 419.7
(loss)/profit per share
In accordance with IAS 33 "Earnings per Share", the effects of 13.5m
antidilutive potential shares have not been included when calculating dilutive
earnings per share for the period ended 30 June 2025, as the Group was loss
making.
9. Intangible assets
Intangible assets comprise the Group's exploration and evaluation projects
which are pending determination. Included in the 1H 2025 additions are charges
for Blocks 125 & 126 in Vietnam of $4.1m, including $2.6m of drill casings
and long-lead items ahead of drilling the first commitment well, and Egypt of
$0.7m.
In Egypt, as part of the planned work programme for 2024, an exploration well
was drilled on El Fayum in August 2024. Testing of the East Saad well was
carried out at the beginning of February 2025. IPR, the operator of the El
Fayum Concession, applied to EGPC for commercial discovery declaration and
early production permission in February 2025. The development lease was
approved and first production commenced at the end of June 2025. As a result,
exploration costs of $2.9m were reclassified to property, plant and equipment
in 1H 2025.
In June 2025, having reviewed the triggers for impairment or impairment
reversal, 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 and Egypt.
While costs for exploration are forecast and funds are available for future
exploration, there is insufficient certainty of full recovery to justify the
reversal of the previous impairment charges in 2020. The accumulated
impairment charges against exploration and evaluation expenditure at 30 June
2025 stands at $28.9m (30 June 2024: $26.8m). This will be kept under review
as the exploration activity continues.
10. Property, plant and equipment
Oil and gas Other Total
properties
Jun 2025 $ million $ million $ million
Property, plant and equipment 257.5 0.2 257.7
Right of use asset 0.1 - 0.1
As at 30 Jun 2025 257.6 0.2 257.8
Oil and gas Other Total
properties
Jun 2024 $ million $ million $ million
Property, plant and equipment 263.9 0.4 264.3
Right of use asset 0.4 - 0.4
As at 30 Jun 2024 264.3 0.4 264.7
Oil and gas Other Total
properties
Dec 2024 $ million $ million $ million
Property, plant and equipment 273.2 0.3 273.5
Right of use asset 0.2 - 0.2
As at 31 Dec 2024 273.4 0.3 273.7
We have evaluated each of our oil and gas producing properties for impairment
or impairment reversal triggers. For each producing property with such
triggers, the recoverable amount held on the books would be determined using
the value in use method. The recoverable amount is calculated using a
discounted cash flow valuation of the 2P production profile.
The average Brent price forecast as at HY 2025 fell by only 6.8% for 2025 to
2027 and 4.6% in the longer-term and does not indicate a significant change in
the underlying value of oil and gas assets. Furthermore, there were no
significant changes to the weighted average cost of capital (WACC) and
forecast production volumes for both Vietnam and Egypt assets compared to 2024
year end.
As a result, after examining both internal and external indicators of
impairment, the Group determined that no impairments or impairment reversal
indicators were identified on any of the Group's oil and gas producing
properties and no impairment tests were considered necessary as at 30 June
2025.
Vietnam
As at 30 June 2025, the carrying amount of the TGT oil and gas producing
property, after additions of $0.9m, increase in decommissioning asset of $0.7m
and DD&A of $14.9m, is $140.3m (Jun 2024: $141.2m; Dec 2024: $153.6m). As
at 30 June 2025, the carrying amount of the CNV oil and gas producing
property, after additions of $0.5m, increase in decommissioning asset of $0.3m
and DD&A of $4.2m, is $56.8m (Jun 2024: $59.9m; Dec 2024: $60.2m).
Egypt
As at 30 June 2025, the carrying amount of the El Fayum oil and gas producing
property, after additions of $0.7m, transfer from intangibles of $2.9m and
DD&A of $2.6m, is $59.5m (Jun 2024: $62.0m; Dec 2024: $58.5m). As at 30
June 2025, the carrying amount of the NBS oil and gas producing property,
after DD&A of $0.1m, is $1.0m (Jun 2024: $1.2m; Dec 2024: $1.1m).
Other
Other fixed assets comprise office fixtures and fittings and computer
equipment of $0.2m (Jun 2024: $0.4m; Dec 2024: $0.3m).
11. Distribution to Shareholders
An interim dividend of 0.363 pence per share in respect of the year ended 31
December 2024, $1.8m equivalent, was paid on 22 January 2025 to shareholders
on the Company's register as at 20 December 2024.
A final dividend of 0.847 pence per share in respect of the year ended 31
December 2024, $4.7m equivalent, was approved by the shareholders at the
Company's AGM in May 2025 and subsequently paid on 18 July 2025 to
shareholders on the register at the close of business on 13 June 2025. This
took the 2024 full year dividend to 1.21 pence per share, an increase of 10%
on the prior year.
In accordance with dividend policy, the Board has resolved to pay an interim
dividend of 0.3993 pence per share, $2.3m equivalent, in respect of the year
ended 31 December 2025 and this will be paid on 21 January 2026 to
shareholders on the Company's register as at 19 December 2025.
12. Reconciliation of operating profit to operating cash flows
(unaudited) six months ended (unaudited) six months ended Year ended
30 Jun 2025 30 Jun 2024 31 Dec 2024
$ million $ million $ million
Operating profit 12.2 35.2 64.3
Share-based payments 0.5 0.3 0.9
Depreciation, depletion and amortisation 21.9 23.9 47.3
Impairment reversal - (8.5) (26.3)
Taxes paid-in-kind (1.1) - (1.9)
Operating cash flows before movements in working capital 33.5 50.9 84.3
Decrease/(increase) in inventories 5.0 (11.9) (6.0)
(Increase)/decrease in receivables(1) (5.0) 6.8 11.3
Decrease in payables (1.6) (1.5) (0.3)
Cash generated by operations 31.9 44.3 89.3
Interest received 0.1 0.2 0.4
Other/restructuring expense outflow - (0.4) (0.4)
Income taxes paid (15.9) (16.2) (35.3)
Net cash from operating activities 16.1 27.9 54.0
( )
(1) Includes $0.1m decrease (1H 2024: $2.7m) in risk factor provision in
respect of Egypt trade receivables.
During the period ended 30 June 2025, a total of $0.3m (1H 2024: $0.4m) of
trade receivables due from EGPC in Egypt and relating to training bonuses were
settled by way of non-cash offset. In 1H 2024, this was predominantly due to
the assignment bonus settled upon receipt of contingent consideration in
relation to the IPR Farm out.
13. Hedge transactions
During 1H 2025, Pharos entered into zero cost collar hedges to protect the
Brent component of forecast oil sales and to provide downside protection to
cash flows in the event of commodity prices falling. The commodity hedges run
until December 2025 and are settled monthly.
Our hedging positions for the period resulted in no realised gain or loss (1H
2024: $0.1m realised loss). The outstanding unrealised gain on open positions
at 30 June 2025 amounted to $0.1m (1H 2024: outstanding unrealised loss of
$0.8m).
For 2H 2025, 26% of the Group's total oil entitlement production has been
hedged, securing average floor and ceiling prices for the hedged volumes at
$61.3/bbl and $84.5/bbl, respectively.
Pharos has designated the zero cost collars as cash flow hedges. This means
that the effective portion of unrealised gains or losses on open positions
will be reflected in other comprehensive income. Every month, the realised
gain or loss will be reflected in the revenue line of the income statement.
The carrying amount of the zero cost collars are based on the fair value
determined by a financial institution. As all material inputs are observable,
they are categorised within Level 2 in the fair value hierarchy. It is
presented in "Derivative financial instruments" in the consolidated statement
of financial position. The net receivable position as at 30 June 2025 was
$0.2m (30 Jun 2024: net liability position of $0.7m; 31 Dec 2024: net
receivable position of $0.1m).
Please see below for a summary of hedges outstanding as at 30 June 2025, which
are all zero cost collar.
3Q25 4Q25
Production hedge per quarter - 000/bbls 120 90
Min. Average value of hedge - $/bbl 61.5 61.0
Max. Average value of hedge - $/bbl 84.7 84.3
14. Borrowings
Changes in liabilities arising from financing activities:
(unaudited) six months ended (unaudited) six months ended
30 Jun 2025 30 Jun 2024
$ million $ million
Total Borrowings Credit facility RBL Total Borrowings
Carrying value as of 1 January - 9.2 31.3 40.5
Proceeds from Uncommitted Revolving credit facility - 2.2 - 2.2
Repayments of borrowings - (8.2) (20.0) (28.2)
Interest expense and similar fees (see Note 6) - 0.3 0.8 1.1
Interest paid during the year - (0.3) (1.5) (1.8)
Carrying value as of 30 June - 3.2 10.6 13.8
Current - 3.2 10.6 13.8
Non-current - - - -
Carrying value as of 30 June - 3.2 10.6 13.8
Reserve Based Lending facility (RBL)
The RBL was secured over the Vietnam producing assets only and, as at 30 June
2024, had a one-year term maturing in June 2025. The loan bore a per annum
interest rate of 5.25% plus Compound SOFR plus CAS (Credit Adjustment Spread).
The RBL loan facility was repaid in full on 17 September 2024 and it was
agreed to voluntarily reduce the borrowing base to $0.1m. The RBL loan
facility was voluntarily cancelled in full on 30 June 2025.
The RBL was subject to a number of financial covenants, which continued to
apply up to the date of maturity and voluntary cancellation, all of which were
complied with during the 1H 2025 and 2024 reporting periods.
Uncommitted revolving credit facility - National Bank of Egypt (Credit
facility)
In June 2025, the Group renegotiated the uncommitted revolving credit facility
with NBE UK for discounting (with recourse) of up to $10m until 9 June 2026.
Loans are available for up to one year from the date of utilisation. The loan
bears a per annum interest rate of Term SOFR plus 3.50% for initial advances
and 4.00% for any extensions beyond 180 days from the date of the utilisation.
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. The facility was repaid in
full in August 2024.
15. Subsequent events
On 23 September 2025, the Group announced that it has received approval from
the Executive Board of EGPC for the consolidation of the El Fayum and North
Beni Suef Concession Agreements into a new consolidated concession agreement,
with improvement of certain fiscal terms. Pharos will retain 45% working
interest in the Consolidated Concession, with IPR continuing as operator with
a 55% working interest. In addition to the 12 development leases of the El
Fayum and NBS Concessions, the Consolidated Concession will include three new
exploration areas. The Consolidated Concession is subject to customary
approvals and ratification by the Egyptian Parliament, which is expected to
take place in late 2025 or early 2026. The financial statement effect of the
Consolidated Concession cannot be made as of the date of this announcement.
Non-IFRS measures
The Group uses certain measures of performance that are not specifically
defined under IFRS or other generally accepted accounting principles. These
non-IFRS measures include cash operating costs per barrel, DD&A per
barrel, gearing, free cash flow, operating cash per share and return on
capital employed.
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 are 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) Year ended 31 Dec 24
six months ended six months ended
30 Jun 25 30 Jun 24
$ million $ million $ million
Cost of sales (1) 48.9 33.0 87.3
(Less)/add:
Depreciation, depletion and amortisation (21.8) (23.8) (47.1)
Production based taxes (3.9) (4.9) (9.2)
Change in inventories (5.0) 11.9 6.0
Trade receivables expected credit loss 0.1 2.7 2.5
Other cost of sales (0.9) (0.7) (1.7)
Cash operating costs 17.4 18.2 37.8
Production (BOEPD) 5,642 5,851 5,801
Cash operating cost per BOE ($) 17.04 17.09 17.80
(1) Includes impairment reversal of financial asset
Cash operating costs per barrel by segment (1H 2025)
Vietnam (unaudited) (unaudited)
six months ended six months ended
30 Jun 25 30 Jun 24
$ million
$ million
Cost of sales 41.1 28.7
Less:
Depreciation, depletion and amortisation (19.1) (21.5)
Production based taxes (3.8) (4.8)
Change in inventories (5.0) 11.7
Other cost of sales (0.6) (0.5)
Cash operating costs 12.6 13.6
Production (BOEPD) 4,183 4,456
Cash operating cost per BOE ($) 16.64 16.77
Egypt (unaudited) (unaudited)
six months ended six months ended
30 Jun 25 30 Jun 24
$ million $ million
Cost of sales 7.8 4.3
Less:
Depreciation, depletion and amortisation (2.7) (2.3)
Production based taxes (0.1) (0.1)
Change in inventories - 0.2
Trade receivables expected credit loss 0.1 2.7
Other cost of sales (0.3) (0.2)
Cash operating costs 4.8 4.6
Production (BOEPD) 1,459 1,395
Cash operating cost per BOE ($) 18.18 18.12
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) Year ended 31 Dec 24
six months ended six months ended
30 Jun 25 30 Jun 24
$ million $ million $ million
Depreciation, depletion and amortisation 21.8 23.8 47.1
Production (BOEPD) 5,642 5,851 5,801
DD&A per BOE ($) 21.35 22.35 22.18
DD&A per barrel by segment (1H 2025)
Vietnam (unaudited) (unaudited) Year ended 31 Dec 24
six months ended six months ended
30 Jun 25 30 Jun 24
$ million $ million $ million
Depreciation, depletion and amortisation 19.1 21.5 42.1
Production (BOEPD) 4,183 4,456 4,361
DD&A per BOE ($) 25.23 26.51 26.38
Egypt (unaudited) (unaudited) Year ended 31 Dec 24
six months ended six months ended
30 Jun 25 30 Jun 24
$ million $ million $ million
Depreciation, depletion and amortisation 2.7 2.3 5.0
Production (BOEPD) 1,459 1,395 1,440
DD&A per BOE ($) 10.22 9.06 9.49
Gearing
Debt to equity ratio is calculated by dividing interest-bearing bank loans by
stockholder's equity. The debt to equity ratio expresses the relationship
between external equity (liabilities) and internal equity (stockholder
equity).
(unaudited) (unaudited)
six months ended six months ended Year ended 31 Dec 24
30 Jun 25 30 Jun 24
$ million $ million $ million
Total Debt - 13.2 -
Total Equity 291.8 283.6 290.8
Debt to Equity - 0.05 -
Free cash flow
Free cash flow is calculated by subtracting capital cash expenditure from net
cash from operating activities.
(unaudited) (unaudited) Year ended 31 Dec 24
six months ended six months ended
30 Jun 25 30 Jun 24
$ million $ million $ million
Net cash from operating activities 16.1 27.9 54.0
Capital cash expenditure (8.2) (6.8) (26.1)
Free cash flow 7.9 21.1 27.9
Operating cash per share
Operating cash per share is calculated by dividing net cash from continuing
operations by number of shares.
(unaudited) (unaudited) Year ended 31 Dec 24
six months ended six months ended
30 Jun 25 30 Jun 24
$ million $ million $ million
Net cash from continuing operating activities 16.1 27.9 54.0
Weighted number of shares in the year 412,341,532 419,333,288 417,019,506
Operating cash per share 0.04 0.07 0.13
Net Cash/(Debt)
Net Cash/(Debt) comprises cash and cash equivalents, less interest-bearing
bank loans.
(unaudited) (unaudited) Year ended 31 Dec 24
six months ended six months ended
30 Jun 25 30 Jun 24
$ million $ million $ million
Cash and cash 22.6 30.7 16.5
equivalents
Borrowings* - (13.2) -
Net Cash 22.6 17.5 16.5
*Excludes unamortised capitalised finance costs
EBITDAX
EBITDAX is earnings from continuing activities before interest, tax, DD&A,
impairment charge/(reversal) of PP&E and intangibles, exploration
expenditure, pre-licence costs and Other/restructuring expense items in the
period.
(unaudited) (unaudited) Year ended 31 Dec 24
six months ended six months ended
30 Jun 25 30 Jun 24
$ million $ million $ million
Operating profit 12.2 35.2 64.3
Depreciation, depletion and amortisation 21.9 23.9 47.3
Pre-licence costs 0.2 - 0.8
Impairment reversal - (8.5) (26.3)
EBITDAX 34.3 50.6 86.1
Return on capital employed (ROCE)
ROCE is calculated by dividing operating profit by total assets less current
liabilities. ROCE measures a company's profitability and the efficiency with
which its capital is employed.
(unaudited) (unaudited) Year ended 31 Dec 24
six months ended six months ended
30 Jun 25 30 Jun 24
$ million $ million $ million
Operating profit 12.2 35.2 64.3
Total assets less current liabilities 404.4 406.0 409.6
ROCE 3.0% 8.7% 15.7%
Glossary of Terms
boepd
Barrels of oil equivalent per day
bopd
Barrels of oil per day
cash
Cash, cash equivalent and liquid investments
capex
Capital expenditure
CNV
Ca Ngu Vang field located in Block 9-2, Vietnam
Company
Pharos Energy plc
EGP
Egyptian Pound
EGPC
Egyptian General Petroleum Corporation, an Egyptian state oil and gas company
and the industry regulator
El Fayum or the El Fayum Concession
The concession agreement for petroleum exploration and exploitation entered
into on 15 July 2004 between the Arab Republic of Egypt, EGPC and Pharos El
Fayum in respect of the El Fayum area, Western Desert, as amended from time to
time
FPSO
Floating production, storage and offloading vessel
Group
Pharos and its direct and indirect subsidiary undertakings
HLJOC
Hoang Long Joint Operating Company, the operator of TGT
HLHVJOC
The HLJOC and the HVJOC
HVJOC
Hoan Vu Joint Operating Company, the operator of CNV
IPR
The IPR Energy group of companies, including IPR Lake Qarun and IPR Energy AG,
or such of them as the context may require
IPR Lake Qarun
IPR Lake Qarun Petroleum Co, an exempted company with limited liability
organised and existing under the laws of the Cayman Islands (registration
number 379306), a wholly owned subsidiary of IPR Energy AG
JOC
Joint Operating Company
km
Kilometre
km(2)
Square kilometre
m
Million
MOIT
Ministry of Industry and Trade of Vietnam
NBS, North Beni Suef or the North Beni Suef Concession
The concession agreement for petroleum exploration and exploitation entered
into on 24 December 2019 between the Arab Republic of Egypt, EGPC and Pharos
El Fayum in respect of the North Beni Suef area, Nile Valley
Petrosilah
An Egyptian joint stock company held 50/50 between the El Fayum Contractor
parties (being the Pharos Group and IPR Lake Qarun) and EGPC
Prospect and lead
An identified trap that may contain hydrocarbons. A potential hydrocarbon
accumulation may be described as a lead or prospect depending on the degree of
certainty in that accumulation. A prospect is generally mature enough to be
considered for drilling
PSC
Production sharing contract or production sharing agreement
PVN
PetroVietnam, the principal state oil and gas company of Vietnam
RBL
Reserve Based Lending facility
share
Ordinary share of 5p in the capital of the Company, unless the context
otherwise requires
TGT
Te Giac Trang field located in Block 16-1, Vietnam
$ or USD
United States Dollar
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