Interim results for six months ended 30 June 2024

Pharos Energy PLC

Sep 18 2024 08:00 BSTSource: RNS

RNS Number : 5979E

Pharos Energy PLC

18 September 2024

Pharos Energy plc

("Pharos" or the "Company" or, together with its subsidiaries, the "Group")

Interim results for the six months ended 30 June 2024

Pharos Energy plc, an independent energy company with assets in Vietnam and Egypt, announces its interim results for the six months ended 30 June 2024. A conference call for analysts will take place at 09.00 BST today.

Katherine Roe, Chief Executive Officer, commented:

"Since joining as CEO in July, I have found a solid operational business with quality assets delivering stable production and robust cash flows, an impressive team, and a strong financial base. Alongside this, the improving macro environment in Egypt has seen our receivables position improve significantly with over $20m received year to date. This financial strength allows us to announce today the intention to pay an interim dividend of 0.363 pence per share for the current financial year, a continuation of the existing share buyback programme and, importantly, the repayment of all our outstanding debt. We are proud of our Company moving to a net cash position of $17.5m at 30 June and, subsequent to that, is now debt-free.

"We have a solid foundation from which to build on and move forward to grow value in both Vietnam and Egypt. We benefit from having assets with catalysts. In Vietnam, actively progressing the license extensions will unlock appraisal potential. In Egypt, our consolidation proposal will provide enhanced fiscal terms to encourage appropriate re-investment. This will all be considered within the framework of a strict and transparent capital allocation policy that is balanced appropriately and with the priority on evaluating opportunities that can deliver the highest return to shareholders.

"I want to thank shareholders for their continued support and look forward to updating the market on our upcoming activity."

1H Operational Highlights

· Group working interest 1H production was 5,851 boepd net (1H 2023: 6,915 boepd net), in line with full year guidance:

o Vietnam 1H production 4,456 boepd (1H 2023: 5,566 boepd)

o Egypt 1H production 1,395 bopd (1H 2023: 1,349 bopd)

· In Vietnam:

o Surface and subsurface optimisation to ensure stable TGT and CNV 1H production

o Approval of the TGT Revised Field Development Plan (RFDP) by the Ministry of Industry and Trade (MOIT)

o Agreement between Partners and PetroVietnam (PVN) on the terms and work programme commitments for the extension period of the TGT and CNV five-year licence extension applications; which now await formal approval

o Progressing the opportunity in Block 125 with long lead items ordered in August 2024

· In Egypt:

o Focus on workovers, recompletions, and water injection to bring low-cost barrels to production and build reservoir energy for future drilling

o Preparation for exploration and development drilling programmes

o Processing and interpretation of the recently acquired 3D Seismic in NBS

1H Financial and Corporate Highlights

· Net cash as at 30 June 2024 of $17.5m^1,2 (30 June 2023: net debt of $16.4m)^1,2

· Group revenue $65.0m³ (1H 2023: $86.2m)³

· Net profit $15.3m (1H 2023: $14.3m net loss), including $12.6m of restructuring expenses, re-measurements and impairments (1H 2023: $(15.2m))

· Cash generated from operations $44.3m³ (1H 2023: $43.4m)³

· Egypt receivables reduced with $14.8m received from EGPC in 1H 2024 and an additional $4m received on 1 July 2024

· Operating cash flow $27.9m⁴ (1H 2023: $21.3m)⁴

· Cash operating costs $17.09/bbl¹ (1H 2023: $14.14/bbl)¹

· Cash balances as at 30 June 2024 of $30.7m (30 June 2023: $35.9m)

· Forecast cash capex for the full year is $31m ($26m after Egyptian carry by IPR), of which $6.8m had been incurred by 30 June 2024

· Katherine Roe appointed CEO and Mohamed Sayed promoted to COO effective 1 July 2024

· Commitment to shareholder returns continues with an interim dividend of 0.363 pence per share in respect of the year ended 31 December 2024 and continuation of the current phase of the share buyback programme, with $1.1m of the $3m incurred by the end of June 2024

¹ See Non-IFRS measures on page 31

² Includes RBL and National Bank of Egypt working capital drawdown

³ Stated after realised hedge losses of $0.1m in the period (1H 2023: no realised hedge gains or losses)

⁴ Operating cash flow = Net cash from operating activities, as set out in the Cash Flow Statement

Outlook

· 2024 production guidance of 5,200 - 6,500 boepd net remains unchanged:

o Vietnam 2024 production guidance 3,900 - 5,000 boepd net; Egypt 2024 production guidance 1,300 - 1,500 bopd net

· Vietnam

o Two-well TGT infill drilling programme commenced on 26 August 2024

o Awaiting CNV RFDP approval, expected in Q4 2024, enabling further development drilling on CNV to commence in 2025

o TGT and CNV five-year licence extensions well advanced; once signed, this will enable commitment to further investment in both fields

o Discussions ongoing with potential farm-in partners and rig contractors required to progress Block 125

· Egypt

o Expected completion of the exploration commitment well on El Fayum in 4Q

o Processing of c.130km² of 3D seismic data on NBS underway and expected to complete in 4Q

o Discussions ongoing on the consolidation proposal following the initial feedback from EGPC

Enquiries

Pharos Energy plc Tel: 020 7747 2000

Katherine Roe, Chief Executive Officer

Sue Rivett, Chief Financial Officer

Mohamed Sayed, Chief Operating Officer

Camarco Tel: 020 3757 4980

Billy Clegg | Georgia Edmonds | Violet Wilson | Kirsty Duff

Notes to editors

Pharos Energy plc is an independent energy company with a focus on sustainable growth and returns to stakeholders, which is listed on the London Stock Exchange. Pharos has production, development and/or exploration interests in Egypt and Vietnam. In Egypt, Pharos holds a 45% working interest share in the El Fayum Concession in the Western Desert, with IPR Lake Qarun, part of the international integrated energy business IPR Energy Group, holding the remaining 55% working interest. The El Fayum Concession produces oil from 10 fields and is located 80 km southwest of Cairo. It is operated by Petrosilah, a 50/50 joint stock company between the contractor parties (being IPR Lake Qarun and Pharos) and the Egyptian General Petroleum Corporation (EGPC). Pharos also holds a 45% working interest share in the North Beni Suef (NBS) Concession in Egypt, which is located immediately south of the El Fayum Concession. The first development lease on the NBS Concession was awarded in September 2023 and production started in December 2023. 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.

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 and zero spillage incidents through the first half of 2024. 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 closely with our JV/JOC.

Vietnam

Vietnam Production

Production for the first half of 2024 from the TGT and CNV fields net to the Group's working interest averaged 4,456 boepd (1H 2023: 5,566 boepd), in line with our previously published guidance.

TGT 1H 2024 production averaged 11,086 boepd gross and 3,289 boepd net to Pharos (1H 2023: 13,423 boepd gross and 3,983 boepd net). CNV 1H 2024 production averaged 4,667 boepd gross and 1,167 boepd net to Pharos (1H 2023: 6,333 boepd gross and 1,583 boepd net).

Working interest production guidance in Vietnam for 2024 remains unchanged at 3,900 - 5,000 boepd.

Vietnam Development and Operations

TGT & CNV Fields

There were no new wells drilled on either field in 1H 2024. Overall production remained stable due to well interventions, including adding zonal perforations and the shut-off of high-water producing zones.

On Block 16-1 - TGT Field, operational activities in the first half of 2024 focused on adding low-cost production through well interventions and production optimisation opportunities. The TGT RFDP was approved by MOIT on 9 January 2024, enabling the two-well drilling programme to commence on 26 August 2024.

On Block 9-2 - CNV Field, the CNV RFDP, which includes two infill wells, was agreed by all partners in 1H 2024. Approval from MOIT is expected in Q4 2024.

Final discussions with PVN to agree terms and work programmes for the five-year licence extensions at TGT and CNV are well advanced. The extension, when granted, will allow the HLHVJOC to commit to further investment in both fields.

Vietnam Exploration

Blocks 125 & 126

On Blocks 125 & 126, discussions with potential farm-in parties and drilling contractors are ongoing. In 1H 2024, the Company continued to optimise its prospects and leads portfolio, and progress options to secure a drilling slot in Block 125. Detailed drilling engineering studies for the well on Prospect A commenced in 3Q 2024. Purchase orders placed for long lead items in August 2024.

Egypt

Egypt Production

Production for the first half of 2024 from the El Fayum and NBS fields net to the Group's working interest averaged 1,395 bopd (1H 2023: 1,349 bopd), in line with guidance.

El Fayum 1H 2024 production averaged 2,867 bopd gross and 1,290 bopd net to Pharos (1H 2023: 2,997 bopd gross and 1,349 bopd net). NBS 1H 2024 production averaged 232 bopd gross and 105 bopd net to Pharos.

Egypt production in the first half has been stable due to a strong focus on workovers, recompletions, and water injection to bring low-cost barrels to production and build reservoir energy for future drilling.

Working interest production guidance in Egypt for 2024 remains unchanged at 1,300 - 1,500 bopd net.

Egypt Development and Operations

El Fayum

One workover rig is in the field to contribute to El Fayum production in 1H 2024 through low-cost well repairs, recompletions, and deployment of water injection.

North Beni Suef

The NBS-SW1X well, which was declared a commercial discovery and put on production in December 2023, continued to contribute to total production in 2024.

Egypt Commercial

A proposal to combine both the El Fayum and NBS into one concession provided to EGPC in May 2024. Discussions on the proposal, which are aimed to achieve improved fiscal terms and longer licence duration for the new concession, were held between Pharos and our partner IPR following the initial feedback from EGPC.

Egypt Exploration

El Fayum

A high-impact exploration commitment well on El Fayum commenced drilling in August. The East Saad 1X well is located between the Saad and Ain Assillien producing fields and is targeting the Abu Roash "G" reservoir.

North Beni Suef

The processing of c.130 km² of 3D seismic data on NBS is ongoing and expected to complete by the end of 2024.

Financial Review

Finance strategy

Our finance strategy of building shareholder value through capital growth and sustainable dividends is supported by the Group's business model.

The first half of 2024 has seen strong financial performance from our operations and continued strengthening of our liquidity position, where we have moved into a positive net cash position of $17.5m compared to net debt of $6.6m previously reported at the end of December 2023. We have achieved solid USD cash flow from our Vietnam and Egypt portfolios and this has enabled us to accelerate the repayment of our borrowings. Following the farm down of Egypt concessions in 2022, the Company continued to benefit from a full carry of all contractor costs for G&A, opex and the capital programme through to April 2024. Whilst revenues are down when compared to 1H 2023, reductions in costs have resulted in a profit for the period of $6.8m versus a loss of $(4.2)m (prior to impairment). Returns to shareholders have been delivered through the commencement of an additional $3m share buyback programme and the payment of an interim dividend for 2023 of 0.33 pence per share in January 2024. A final dividend for 2023 of 0.77 pence per share was paid to shareholders in July 2024 and the Board is pleased to also announce a 2024 interim dividend of 0.363 pence per share in respect of the year ended 31 December 2024.

Highlights

	1H 2024	1H 2023
Production Volumes (boepd)	5,851	6,915
Production Volumes - Vietnam (boepd)	4,456	5,566
Production Volumes - Egypt (bopd)	1,395	1,349
Oil Price Realised ($/bbl)	87.31	84.89
Oil & Gas Price Realised ($/boe)	77.71	76.29

Oil & Gas Sales ($m)	65.1	86.2
Total Revenue ($m)¹	65.0	86.2
Gross Profit ($m)	32.0	28.0
Operating profit ($m)	35.2	13.3
Operating profit excluding impairment (reversal)/charge ($m)²	26.7	23.4
Net cash from operating activities (OCF $m)	27.9	21.3
Shareholder returns ($m) ^{2 3}	3.0	0.7
Cash operating cost per ($/boe)²	17.09	14.14
Net cash/(debt) ($m)²	17.5	(16.4)
EBITDAX ($m)²	50.6	53.4
Gearing²	0.05	0.17

¹ Realised hedge losses of $0.1m in the period (1H 2023: no realised hedge gains or losses)

² See Non-IFRS measures on page 31

³ For 2024, includes continuation of $3m share buyback programme (the Second Programme Extension), $1.1m of which had been incurred by 30 June 2024. Also, Interim Group dividends of $1.9m in respect of the year ended 31 December 2024, announced in September 2024, will be paid to shareholders in January 2025.

Operating Performance - Income Statement

Revenue

Oil & gas revenues for the period were down 24% to $65.1m (1H 2023: $86.2m). Production volumes were within guidance, though Group sales volumes were down which has led to an inventory build of $11.7m for the Vietnam producing fields. Additionally, the 2023 revenues were considerably enhanced by the new lateral CNV-2PST1 well drilled in February 2023. This peaked at c. 3,000 bopd (gross) and has now stabilised at c. 1,300 bopd (gross) which was the expected outcome. The well continues to contribute strongly to CNV revenues.

In Vietnam, revenues decreased 28% to $55.8m (1H 2023: $77.6m), which was predominantly due to 28% reduction in TGT sales volumes as a result of maintenance work to the receiving facilities at the BSR refinery. The average realised crude oil price, including the premium received over Brent, was $89.07/bbl (1H 2023: $86.14/bbl), a 3% increase. The premium to Brent fell to just over $5/bbl (1H 2023: just under $8/bbl).

In Egypt, revenues increased 8% to $9.3m (1H 2023: $8.6m). The average realised crude oil price, after discounts, was $78.30/bbl (1H 2023: $75.21/bbl), an increase of 4%. There are two discounts applied to Egypt crude production - a general Western Desert Discount and one related specifically to El Fayum. Both are set by EGPC (the in-country regulator) and together increased to just under $6/bbl (1H 2023: $5/bbl).

Hedging

For 2024, Pharos entered into zero cost collar hedges to protect the Brent component of forecast oil sales and to ensure future compliance with its obligations under the RBL over the producing assets in Vietnam and to provide downside protection to cash flows in the event of commodity prices falling. The commodity hedges run until June 2025 and are settled monthly. Our hedging positions for the period resulted in $0.1m realised loss (1H 2023: no realised hedge gains or losses). Additionally, the fair value as at 30 June 2024 was an unrealised loss of $0.8m for the remaining hedges in place (1H 2023: unrealised gain of $0.2m).

For 2024, 30% of the Group's total oil entitlement production has been hedged, securing average floor and ceiling prices for the hedged volumes at $63.4/bbl and $89.2/bbl, respectively. The Group's RBL requires the Company to hedge at least 35% of Vietnam RBL production volumes and the current hedging programme meets this requirement through to June 2025, leaving 71% of Group production unhedged as at 30 June 2024.

Please see below a summary of hedges outstanding as at 30 June 2024, which are all zero cost collar.

		3Q24	4Q24	1Q25	2Q25
Production hedge per quarter - 000/bbls	150		120	150	60
Average floor price of hedges - $/bbl	64.4		63.0	63.6	64.0
Average ceiling price of hedges - $/bbl	88.5		89.0	88.9	90.2

Group operating costs, DD&A and expenses

Cost of Sales were 43% lower at $33.0m (1H 2023: $58.2m), inclusive of impairment reversal/(charge) of financial asset in relation to EGPC receivables, and this was primarily driven by the $13.0m higher inventory build from Vietnam. Operating costs in Egypt fell 70% to $2.0m (1H 2023: $6.6m) and this was principally due to $5.1m reduction in the EGPC trade receivable risk factor provision, in light of improved liquidity and economic outlook in-country.

DD&A charges on production and development assets decreased to $23.8m (1H 2023: $29.9m), driven by a lower depreciating cost base following 2023 impairment charges taken on both TGT in Vietnam and the Egypt producing assets, combined with 15% reduction in group production volumes. DD&A per bbl is currently $22.35/boe (1H 2023: $23.89/boe).

Administrative expenses of $4.7m (1H 2023: $4.6m) are comparable period on period and include non-cash items such as depreciation and IFRS 2 Share Based Payments of $0.3m (1H 2023: $0.4m). Other operating expenses of $0.6m (1H 2023: $nil) 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.

Cash Operating Costs

Cash operating costs at Group level, defined in the Non-IFRS measures section on page 31, amounted to $18.2m (1H 2023: $17.7m), a 3% increase over the same period last year. On a barrel of oil equivalent basis, this was $17.09/boe (1H 2023: $14.14/boe).

Cash operating costs in Vietnam increased marginally to $13.6m (1H 2023: $13.4m) in the period which equates to $16.77/bbl (1H 2023: $13.30/bbl). The increase is primarily driven by lower production in 1H 2024 and higher costs relating to the FPSO as a result of lower production from TLJOC, which shares the facilities and the costs of the FPSO based on production rates. TLJOC had a 23.0% cost share in 1H 2024 compared to 26.0% in 1H 2023.

Cash operating costs in Egypt were $4.6m (1H 2023: $4.3m) in the period, which equates to $18.12/bbl (1H 2023: $17.61/bbl). The 3% increase in cost per bbl was mainly related to higher Petrosilah cost allocations as a result of minimal drilling and capital expenditure during 1H 2024, higher crude oil processing fees and chemical costs, offset by a decrease in fixed costs due to further EGP devaluation following full flotation of the currency by the Egyptian Government in March 2024.

Cash operating cost per barrel	1H 2024 $m	1H 2023 $m
Cost of sales ¹	33.0	58.2
Less
Depreciation, depletion and amortisation	(23.8)	(29.9)
Production based taxes	(4.9)	(6.3)
Inventories movement	11.9	(1.1)
Other cost of sales	(0.7)	(0.8)
Trade Receivable risk factor provision	2.7	(2.4)
Cash operating costs	18.2	17.7
Production (BOEPD)	5,851	6,915
Cash operating cost per BOE ($)	17.09	14.14

Cash operating cost per barrel by Segment	Vietnam $m	Egypt $m	Total $m
Cost of sales ¹	28.7	4.3	33.0
Less
Depreciation, depletion and amortisation	(21.5)	(2.3)	(23.8)
Production based taxes	(4.8)	(0.1)	(4.9)
Inventories movement	11.7	0.2	11.9
Other cost of sales	(0.5)	(0.2)	(0.7)
Trade Receivable risk factor provision	-	2.7	2.7
Cash operating costs	13.6	4.6	18.2
Production (BOEPD)	4,456	1,395	5,851
Cash operating cost per BOE ($)	16.77	18.12	17.09

¹ Includes impairment reversal/(charge) of financial asset

Financing costs

Finance costs for the period were significantly lower at $2.6m (1H 2023: $6.9m) due to accelerated, voluntary repayments on the Group's reserve based lending facility (RBL). Finance costs included a non-cash credit of $(0.1)m (1H 2023: $2.3m charge) following the June 2024 redetermination of the RBL, which led to a change in estimated future cash flows. There was also interest expense and similar fees of $1.2m (1H 2023: $3.1m), unwinding of discount of provisions $1.0m (1H 2023: $1.0m) and foreign exchange losses of $0.5m (1H 2023: $0.5m) primarily driven by the devaluation of EGP against USD.

Taxation

The overall net tax charge of $18.3m (1H 2023: $19.6m) relates to tax charges in Vietnam of $18.3m (1H 2023: Vietnam tax charges of $19.9m less the deferred tax credit on net impairment charge of $(0.3)m).

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. The Group records a tax charge, with a corresponding increase in revenue, for the tax paid by EGPC on its behalf. However, this is only valid if PEF is in a tax paying position and no such tax has been recorded in the period.

One of the Group's companies entered into commodity zero cost collars designated as cash flow hedges. In accordance with IAS 12, a deferred tax asset has not been recognised in relation to the hedging losses of $0.1m (2023: $nil) recorded in the period 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 profit/(loss)

The post-tax profit for the period of $15.3m (1H 2023: $(14.3)m post-tax loss) included $12.6m of restructuring expenses, re-measurements and impairments (1H 2023: $(15.2)m) which are shown in the table below. Business performance post-tax profit for the period was $2.7m (1H 2023: $0.9m).

Financial Statements Impact:	1H 2024 $m	1H 2023 $m
Profit/(loss) for the period	15.3	(14.3)

Impact of restructuring expense, re-measurements and impairments
Revenue	(0.1)	-	Realised hedging losses
Impairment reversal/(charge) - Financial asset	2.7	(2.4)	Trade receivable risk factor provision in Egypt
Impairment reversal/(charge) - Property, plant and equipment	8.5	(10.1)
Other/restructuring expenses	(0.4)	-	Egypt redundancy cost following farm down
Gain/(loss) on fair value movement of financial asset	1.2	(1.3)	Revision of contingent consideration in relation to Egypt farm-out
Finance costs	0.7	(1.7)	Adjustment and amortisation of capitalised borrowing costs
Income tax credit	-	0.3	Deferred tax on net impairment charge
	12.6	(15.2)

Business performance post-tax profit *	2.7	0.9

* 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

As a result of previously recognised impairment losses, review of oil prices, considerations on economic uncertainty leading to high inflation globally, changes in discount rates, and review of movements in 2P reserves, we have considered each of our oil and gas producing properties for impairment or impairment reversal triggers. For each producing property with such triggers, the recoverable amount has been determined using the value in use method. The recoverable amount is calculated using a discounted cash flow valuation of the 2P production profile.

The reserves and cost profiles for TGT and CNV fields remained consistent with 2023 year end. The average Brent price forecast for H1 2024 rose marginally by 1%, the discount rate fell to 11.6% (Dec 2023: 12.6%) and there was no change in the Vietnam economic or legal environment. As a result, for both TGT and CNV, management concluded that there were no impairment triggers and an impairment test was not considered necessary.

In Egypt, the weighted average cost of capital (WACC) fell to 15.1% as at June 2024 (Dec 2023: 18.0%) following a reduction in country risk premium and this led to an impairment reversal for El Fayum as follows:

Summary of Impairments - Oil and Gas properties	TGT $m	CNV $m	El Fayum $m	NBS $m	Total $m
1H 2024
Pre-tax impairment reversal	-	-	8.5	-	8.5
Deferred tax credit/(charge)	-	-	-	-	-
Post-tax impairment reversal	-	-	8.5	-	8.5

Reconciliation of carrying amount:
As at 1 January 2024	158.6	65.0	54.7	1.0	279.3
Additions	0.6	0.3	0.9	0.4	2.2
Changes in decommissioning asset ¹	(1.5)	(0.4)	-	-	(1.9)
DD&A	(16.5)	(5.0)	(2.1)	(0.2)	(23.8)
Impairment reversal	-	-	8.5	-	8.5
As at 30 June 2024	141.2	59.9	62.0	1.2	264.3


1H 2023
Pre-tax impairment (charge)/reversal	(11.2)	10.6	(9.5)	-	(10.1)
Deferred tax credit/(charge)	4.3	(4.0)	-	-	0.3
Post-tax impairment (charge)/reversal	(6.9)	6.6	(9.5)	-	(9.8)

Reconciliation of carrying amount:
As at 1 January 2023	242.4	76.4	62.5	-	381.3
Additions	0.7	2.6	5.8	-	9.1
Changes in decommissioning asset ¹	-	(2.3)	-	-	(2.3)
DD&A	(21.0)	(6.8)	(2.1)	-	(29.9)
Impairment (charge)/reversal	(11.2)	10.6	(9.5)	-	(10.1)
As at 30 June 2023	210.9	80.5	56.7	-	348.1

¹ Changes in decommissioning asset for TGT and CNV is due to a change in discount rate only (1H 2023: change in discount rate and field abandonment plan for CNV and change in discount rate only for TGT)

Net cash/debt

Strong financial performance from our operations contributed to significantly improved liquidity and the Group moved into a net cash position (31 Dec 2023: $6.6m net debt). As at the balance sheet date, $13.2m (RBL $10.0m and NBE $3.2m) was drawn under the Group's borrowing facilities and there was cash of $30.7m, giving a net cash figure of $17.5m (1H 2023: RBL $42.6m and NBE $9.7m; cash $35.9m and net debt of $16.4m). Gearing has been calculated as total debt to equity of 0.05x (1H 2023: 0.17x).

As at 30 June 2024, the trade receivables with EGPC stood at $31.3m (31 Dec 2023: $37.4m), of which $30.0m was overdue. $14.8m was received from EGPC in 1H 2024 and an additional $4m was received on 1 July 2024.

PEF is entitled under contract to be paid for hydrocarbon sales in US dollars. Until March 2024, the Group had opted to reject payment of any part of PEF's receivables balance in Egyptian Pounds (EGP) and continue to hold USD denominated receivables for two reasons: the continued devaluation of the currency to the USD and we had no need for EGP funds since our share of operational expenditures was covered by the carry with IPR. Following a decision by the Egyptian Government in early March 2024 to let the EGP fully float, the currency has devalued against the USD. Considering this devaluation, and in view of our carry being fully utilised, starting from April 2024 the Group opted to accept the payment of part receivables balance in EGP in order to cover operational expenditure and other expenses in local currencies.

Following the landmark agreement with ADQ (an Abu Dhabi sovereign wealth fund), whereby the latter invested $35 billion for the development of the new coastal city of Ras El Hekma, the significantly expanded new loan from the IMF ($8 billion, including the original $3 billion originally secured in December 2022, with an additional $1.2 billion from the IMF's Resilience and Sustainability Facility) and other concessional loans granted by the World Bank ($8 billion), the EU ($6 billion) and other institutions, the Egyptian Government's FX reserves have significantly improved ($46.5 billion at the end of July 2024 versus $35.2 billion at year end) and are expected to improve further by the end of 2024 (c. $53 billion according to Fitch). This has allowed EGPC to make industry wide payments of c. 20-25% of each Company's receivables balance (PEF received $10 million in March 2024 and $4 million on 1 July 2024) and the new Minister of Petroleum (Karim Badawi, who replaced Tarek El Molla in early July 2024) has committed to table a payment plan to progressively reduce arrears in the short term. In light of these considerations, the Group remains optimistic that its receivable position will continue to improve during 2024, through a combination of payments in USD, payments in EGP (to the extent needed to cover operational expenditures in local currency) and offsets.

Borrowings

Reserve Based Lending

The RBL is secured over the Vietnam producing assets only and, as at 30 June 2024, has a one-year term maturing in June 2025. The maximum borrowing base available under the RBL is revised every six months via a redetermination process by the relevant banks, based on an estimate of the value of the Group's reserves from its producing assets in Vietnam. For 1H 2024, the Group made voluntary early principal repayments of $20.0m to reduce finance costs (1H 2023: $22.4m) and the borrowing base as at 30 June 2024 was $11.6m (30 June 2023: $42.6m). After voluntary cancellation of $21.8m to date, the facility amount stood at $11.6m.

The loan bears a per annum interest rate of Compound SOFR plus CAS (Credit Adjustment Spread) plus 5.25%.

Uncommitted Revolving Credit Facility (National Bank of Egypt - NBE)

The amount repayable under the agreement at 30 June 2024 was $3.2m (30 June 2023: $9.7m) and it is presented as borrowings under current liabilities.

The facility was 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, of up to 60% of the value of each El Fayum oil sales invoice, presenting the 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.

In January 2024, the Group renegotiated the uncommitted revolving credit facility of up to $10m until 30 May 2025.

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.

Cash flow

Cash generated from operations was $44.3m (1H 2023: $43.4m) and prior to working capital movements was $50.9m (1H 2023: $53.7m). This highlights the strong operating performance from the producing fields in Vietnam and Egypt, combined with higher commodity prices, despite the 26% fall in Group sales volumes.

The decrease in receivables was $6.8m for the period (1H 2023: increase of $11.7m). The 2024 movement is mainly driven by $3.4m reduction in Egypt trade receivables, following increased recovery from EGPC during the period as a result of improved liquidity in-country. Vietnam trade receivables decreased by $3.3m, primarily linked to the timing of liftings (2 cargoes in June 2024 compared to 3 cargoes in December 2023). Inventory increased significantly by $11.9m (1H 2023: decrease of $1.1m) and this was driven by Vietnam operations and the timing of liftings from TGT. Vietnam revenue volumes overall were down 30% compared to 1H 2023, and the impact of the inventory build is expected to lead to a higher number of liftings in 2H 2024.

Share Buyback and Dividends

Following a period of relatively stable commodity prices and a strengthening of the Group's liquidity position, the Company committed to shareholder returns in the form of share buybacks and dividends. On 6 December 2023, the Company announced the continuation of a further $3m share buyback programme in 2024 (the Second Programme Extension), of which $1.1m had been incurred by the end of June 2024.

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 of 33% of the prior period's full year dividend, payable in January of the following year; and

- A final dividend payable in July of the following year.

On 6 December 2023, an interim dividend of 0.33 pence per share, $1.8m equivalent, was declared by the Board in respect of the year ended 31 December 2023 and paid on 24 January 2024 to shareholders on the register at the close of business on 22 December 2023. A final dividend of 0.77 pence per share in respect of the year ended 31 December 2023, $4.1m equivalent, was approved by the shareholders at the Company's AGM in May 2024 and subsequently paid on 19 July 2024 to shareholders on the register at the close of business on 14 June 2024. This took the 2023 full year dividend to 1.10 pence per share, an increase of 10% on the prior year.

The Board has resolved to pay an interim dividend of 0.363 pence per share, $1.9m equivalent, in respect of the year ended 31 December 2024 and this will be paid on 22 January 2025 to shareholders on the Company's register as at 20 December 2024.

Liquidity risk management and going concern

The Group continuously monitors its business activities, financial position, cash flow and liquidity. Cash forecasts are regularly produced, and stress tested for a number of scenarios including a downturn in the oil price, changes in production rates and capital expenditure. 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 $55/bbl in October 2024, 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 2024, the Group had a cash balance of $30.7m and improved liquidity with a net cash position of $17.5m. Forecasts show that the Group will have sufficient financial headroom for the period of 15 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

ESG

Climate remains a principal risk and uncertainty for Pharos. That is why we published a detailed Net Zero Roadmap in December 2023, which models emissions pathways - including interim targets - to achieve net zero in Scope 1 and 2 GHG emissions from all existing and future assets by no later than 2050.

In 1H 2024, the Group measured an approximate decline in Scope 1 and 2 emissions by 11% compared to the same time last year, partly driven by measures to reduce the consumption of carbon-intensive fuel in its field operations, and partly by a lower production volume. Pharos will continue to work closely with our operating partners to identify opportunities to reduce emissions to ensure we achieve our climate targets.

We are proud of our social initiatives which have been an important part of Pharos since inception. For 1H 2024, the HLHVJOC Donation Programme invested in 7 long-term social projects, ranging from providing educational support for children with disabilities to supporting low-income communities. In the first quarter, donations were focused on providing medical checks and essential medications for patients in need in rural areas, while support in 2Q was dedicated towards building adequate sanitation systems in public medical centres. 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.

Principal and emerging risks and uncertainties for the second half of 2024

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 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.

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 2024 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 - 16. 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 2024 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

17 September 2024

interim Condensed consolidated income statement
			(unaudited) Six months ended	(unaudited) Six months ended	Year ended
			30 Jun 2024	30 Jun 2023	31 Dec 2023
		Notes	$ million	$ million	$ million
Continuing operations
Revenue		3, 13	65.0	86.2	167.9
Cost of sales		4	(35.7)	(55.8)	(109.0)
Impairment reversal/(charge) - Financial asset			2.7	(2.4)	(2.2)
Gross profit			32.0	28.0	56.7

Administrative expenses			(4.7)	(4.6)	(9.0)
Pre-licence Costs		3	-	-	(0.4)
Impairment (charge)/reversal - Intangibles		3, 9	-	-	(6.5)
Impairment reversal/(charge) - PP&E		3, 10	8.5	(10.1)	(58.9)
Other operating costs		5	(0.6)	-	-
Operating profit/(loss)			35.2	13.3	(18.1)

Other/restructuring expense		5	(0.4)	-	(0.6)
Gain/(loss) on fair value movement of financial asset		15	1.2	(1.3)	(0.3)
Interest income			0.2	0.2	0.2
Finance costs		6	(2.6)	(6.9)	(10.2)
Profit/(loss) for the period before tax		3	33.6	5.3	(29.0)
Tax		7	(18.3)	(19.6)	(19.8)
Profit /(loss) for the period			15.3	(14.3)	(48.8)

Profit/(loss)per share (cents)		8
Basic			3.7	(3.3)	(11.4)
Diluted			3.6	(3.3)	(11.4)
interim Condensed consolidated statement of OTHER comprehensive income
			(unaudited) Six months ended	(unaudited) Six months ended	Year ended
			30 Jun 2024	30 Jun 2023	31 Dec 2023
	Notes		$ million	$ million	$ million

Profit /(loss) for the period			15.3	(14.3)	(48.8)
Items that may be subsequently reclassified to profit or loss:
Fair value (loss)/gain arising on hedging instruments during the period 13			(0.9)	0.9	0.6
Less: Loss arising on hedging instruments reclassified to profit or loss			0.1	-	0.2

Total comprehensive income/(loss) for the period			14.5	(13.4)	(48.0)

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 24	30 Jun 23	31 Dec 23 Restated ¹
	Notes	$ million	$ million	$ million
Non-current assets
Intangible assets	9	20.1	21.6	18.2
Property, plant and equipment	10	264.3	347.9	279.3
Right-of-use assets	10	0.4	0.7	0.5
Other assets		57.3	56.4	58.6
		342.1	426.6	356.6
Current assets
Inventories		15.2	6.1	3.3
Trade and other receivables		52.4	62.6	62.2
Derivative financial instruments	13	-	0.3	0.1
Tax receivables		0.3	2.3	2.2
Cash and cash equivalents		30.7	35.9	32.6
		98.6	107.2	100.4

Total assets		440.7	533.8	457.0
Current liabilities
Trade and other payables		(14.6)	(19.2)	(12.5)
Derivative financial instruments	13	(0.7)	-	-
Borrowings	14	(13.8)	(33.1)	(29.5)
Lease Liabilities		(0.3)	(0.3)	(0.3)
Tax payables		(5.3)	(4.6)	(5.8)
		(34.7)	(57.2)	(48.1)
Net current assets		63.9	50.0	52.3

Non-current liabilities
Trade and other payables		(0.2)	(0.4)	(0.5)
Deferred tax liabilities		(69.2)	(90.4)	(68.2)
Borrowings	14	-	(20.9)	(11.0)
Lease Liabilities		(0.1)	(0.4)	(0.2)
Long term provisions		(52.9)	(52.9)	(53.8)
		(122.4)	(165.0)	(133.7)

Total liabilities		(157.1)	(222.2)	(181.8)
Net assets		283.6	311.6	275.2

Equity
Share capital		33.4	34.1	33.7
Share premium		58.0	58.0	58.0
Other reserves		255.9	254.4	255.4
Retained deficit		(63.7)	(34.9)	(71.9)
Total equity		283.6	311.6	275.2

¹ Refer to 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

¹ Includes $137.1m as Merger Reserve which is fully distributable.

² During 1H 2024, the Company repurchased 4,073,265 shares at an average price of 22.01 pence per share (1H 2023: 2,716,308 shares at average price of 23.22 pence per share; 2023: 10,035,962 at an average price of 22.84 pence per share).

³ Refer to Note 2.

The above interim condensed consolidated statements of changes in equity should be read in conjunction with the accompanying notes.

	Called up share capital	Share Premium	Other reserves	Retained (deficit)/ earnings	Total
	$ million	$ million	$ million	$ million	$ million

As at 1 January 2023	34.3	58.0	253.6¹	(15.3)	330.6

Loss for the period	-	-	-	(14.3)	(14.3)
Other comprehensive income	-	-	0.9	-	0.9
Share buy back ²	(0.2)	-	0.2	(0.8)	(0.8)
Distributions to shareholders	-	-	-	(5.3)	(5.3)
Share-based payments	-	-	0.5	-	0.5
Transfer relating to share-based payments	-	-	(0.8)	0.8	-


As at 30 June 2023 (unaudited)	34.1	58.0	254.4¹	(34.9)	311.6

Loss for the period	-	-	-	(34.5)	(34.5)
Other comprehensive loss	-	-	(0.1)	-	(0.1)
Share buy back ²	(0.4)	-	0.4	(2.0)	(2.0)
Distributions to shareholders	-	-	-	(0.3)	(0.3)
Share-based payments	-	-	0.5	-	0.5
Transfer relating to share-based payments	-	-	0.2	(0.2)	-


As at 1 January 2024, Restated ³	33.7	58.0	255.4¹	(71.9)	275.2

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)	33.4	58.0	255.9¹	(63.7)	283.6

interim condensed consolidated cash flow statements

		(unaudited) Six months ended	(unaudited) Six months ended	Year ended
		30 Jun 2024	30 Jun 2023	31 Dec 2023
	Notes	$ million	$ million	$ million

Net cash from operating activities	12	27.9	21.3	44.9

Investing activities
Purchase of intangible assets		(1.9)	(4.4)	(9.7)
Purchase of property, plant and equipment		(3.8)	(9.3)	(13.5)
Consideration in relation to farm out of Egyptian assets¹	15	5.0	7.8	15.6
Contingent consideration received in relation to farm out of Egyptian assets	15	3.6	5.0	5.0
Assignment fee in relation to farm out of Egyptian assets	15	(0.4)	(0.5)	(0.5)
Payment to abandonment fund		(1.1)	(1.7)	(3.5)
Net cash from/(used in) investing activities		1.4	(3.1)	(6.6)

Financing activities
Proceeds from borrowings	14	2.2	1.9	9.2
Interest paid on borrowings	14	(1.8)	(3.7)	(6.4)
Repayment of borrowings	14	(28.2)	(23.8)	(44.2)
Lease payments		(0.2)	(0.2)	(0.3)
Share buy back		(1.1)	(0.8)	(2.8)
Share-based payments		0.1	-	-
Dividends paid to shareholders		(1.8)	-	(5.6)
Net cash used in financing activities		(30.8)	(26.6)	(50.1)

Net decrease in cash and cash equivalents		(1.5)	(8.4)	(11.8)

Cash and cash equivalents at beginning of period		32.6	45.3	45.3

Effect of foreign exchange rate changes		(0.4)	(1.0)	(0.9)

Cash and cash equivalents at end of period		30.7	35.9	32.6

¹ During 2024 IPR, acting as operator and agent, was authorised to settle its operating liabilities of $3.7m (1H 2023: $3.4m) and investing liabilities of $1.3m (1H 2023: $4.4m) against the consideration due from the associated carry (see Note 15) debtor amounting to $5.0m (1H 2023: $7.8m). 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 2024 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 2023, which were prepared in accordance with UK-adopted International Accounting Standards ("IFRSs"). 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 2023 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 2023, 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 2024 was approved by the Directors on 17 September 2024.

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 2024 interim condensed set of financial statements are the same as those adopted in the Group's Annual Report and Accounts as at 31 December 2023.

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 2023 and any public announcements made by Pharos during the interim reporting period.

Restatement

As at 31 December 2023, a $1.7m current liability was recognised in respect of the interim dividend announced in December 2023 and paid in January 2024. While preparing these interim financial statements the Group noted the guidance set out in the ICAEW Technical Release 02/17BL regarding "Guidance on Realised and Distributable Profits under the Companies Act 2006" (TR 02/17BL) which requires a legally binding liability to be established prior to the recognition of an interim dividend. Since this obligation was not legally binding as at 31 December 2023, the comparatives in the Interim Condensed Consolidated Balance Sheet and the Interim Condensed Consolidated Statement of Changes in Equity as at 31 December 2023 have been restated to remove the interim dividend liability. Going forward, the Group will recognise interim dividends only in the period in which they are paid unless applicable accounting practice, standards or guidance changes. This does not constitute any change in the Group's previously announced dividend policy.

Going Concern

The Directors consider the going concern assessment period to be fifteen months up to 31 December 2025, which takes into account the commitment well due to be drilled on Block 125 by November 2025. 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 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. A base case forecast has been considered that utilises oil prices of $82.6/bbl in 2024 and $79.8/bbl in 2025. The key assumptions and related sensitivities include a "Reasonable Worst Case" (RWC) scenario, where the Board has taken into account the risk of an oil price crash broadly similar to what occurred in 2020. It assumes the Brent oil price down by a third to $55.0/bbl in October 2024 and gradually recovers to base price in next 12 months, concurrent with 5% reductions in Vietnam and Egypt production compared to our base case from October 2024. Both the base case and RWC take into account effect of hedging that has already been put in place at 30 June 2024 and subsequent hedges placed in 2024, now covering c.30% for the full year 2024 and c.28% from July 2024 to June 2025 of the Group's total oil entitlement production. We have therefore secured an average floor price and ceiling price of c. $63/bbl and c. $89/bbl for 2024 and c. $64/bbl and c. $89/bbl for 2025, respectively, for the entire hedged volumes. Under the RWC scenario, we have included certain mitigating actions within our control, which could look to reduce head office G&A by $2.4m for 2025 and not making any dividend distributions during 2025.

In addition, we have conducted a reverse stress test sensitivity analysis that indicates the magnitude of the oil price decline required to breach our financial headroom, assuming all other variables remain unchanged and including the mitigation actions noted above. The likelihood of this scenario occurring was assessed as being remote.

As at 30 June 2024, the Group had a cash balance of $30.7m and improved liquidity with a net cash position of $17.5m (Jun 2023: $16.4m net debt; Dec 2023: $6.6m net debt), and on the basis of the forecasts provided above, the Group will have sufficient financial headroom for the period of 15 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.

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.

Several amendments apply for the first time in 2024, but do not have an impact on the interim condensed consolidated financial statements of the Group:

· Classification of Liabilities as Current or Non-current and Non-current Liabilities with Covenants - Amendments to IAS 1

· Lease Liability in a Sale and Leaseback - Amendments to IFRS 16

· Disclosures: Supplier Finance Arrangements - Amendments to IAS 7 and IFRS 7

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.

(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.

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 2024 (unaudited)	SE Asia	Egypt	Unallocated¹	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
Depreciation, depletion and amortisation - oil and gas	(21.5)	(2.3)	-	(23.8)
Depreciation, depletion and amortisation - other	-	(0.1)	-	(0.1)
Impairment reversal - PP&E (see Note 10)	-	8.5	-	8.5
Gain on fair value movement of financial asset	-	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 assets²	219.2	65.6	-	284.8

Six months ended 30 June 2023 (unaudited)	SE Asia	Egypt	Unallocated¹	Group
	$ million	$ million	$ million	$ million
Oil and gas sales	77.6	8.6	-	86.2
Realised loss on commodity hedges (see Note 13)	-	-	-	-
Total Revenue	77.6	8.6	-	86.2
Depreciation, depletion and amortisation - oil and gas	(27.8)	(2.1)	-	(29.9)
Depreciation, depletion and amortisation - other	-	(0.1)	-	(0.1)
Impairment charge - PP&E	(0.6)	(9.5)	-	(10.1)
Loss on fair value movement of financial asset	-	(1.3)	-	(1.3)
Profit/(Loss) before tax	26.6	(11.7)	(9.6)	5.3
Tax charge on operations (see Note 7)	(19.9)	-	-	(19.9)
Tax credit on impairment charge (see Note 7)	0.3	-	-	0.3
Non-current assets²	306.8	63.4	-	370.2


Year end 31 December 2023	SE Asia	Egypt	Unallocated¹	Group
	$ million	$ million	$ million	$ million
Oil and gas sales	149.2	18.9	-	168.1
Realised loss on commodity hedges	-	-	(0.2)	(0.2)
Total Revenue	149.2	18.9	(0.2)	167.9
Depreciation, depletion and amortisation - oil and gas	(51.0)	(4.4)	-	(55.4)
Depreciation, depletion and amortisation - other	-	(0.2)	-	(0.2)
Pre-licence costs	-	(0.4)	-	(0.4)
Impairment charge - Intangibles assets	-	(6.5)	-	(6.5)
Impairment charge - PP&E	(46.0)	(12.9)	-	(58.9)
Loss on fair value movement of financial asset	-	(0.3)	-	(0.3)
Profit/(Loss) before tax	5.6	(18.4)	(16.2)	(29.0)
Tax charge on operations (see Note 7)	(36.0)	-	-	(36.0)
Tax credit on impairment charge (see Note 7)	16.2	-	-	16.2
Non-current assets²	240.4	57.6	-	298.0

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.

4. Cost of sales

	(unaudited) six months ended 30 Jun 2024	(unaudited) six months ended 30 Jun 2023	Year ended 31 Dec 2023
	$ million	$ million	$ million
Depreciation, depletion and amortisation	23.8	29.9	55.4
Production based taxes	4.9	6.3	10.5
Production operating costs	18.9	18.5	39.1
Inventories movement	(11.9)	1.1	4.0
	35.7	55.8	109.0

5. Other Operating Costs and Other/restructuring expense

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 1Y 2024, Other/restructuring expenses included $0.4m of restructuring costs. In 2023, other expenses of $0.6m were due to changes in the best estimate of the adjustment relating to the interim period between the economic date of 1 July 2020 and the completion date of the disposal of 55% interest in the Egypt concessions.

6. Finance Costs

	(unaudited) six months ended 30 Jun 2024	(unaudited) six months ended 30 Jun 2023	Year ended 31 Dec 2023
	$ million	$ million	$ million
Unwinding of discount on provisions ¹	1.0	1.0	2.0
Interest expense and similar fees ² (see Note 14)	1.1	5.4	7.7
Net foreign exchange losses	0.5	0.5	0.5
	2.6	6.9	10.2

2019

2018

¹ For 1H 2024, $1.0m relates to the unwinding of discount on the provisions for decommissioning (1H 2023: $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 June 2024, a credit of $(0.1)m (1H 2023: $2.3m charge; Dec 2023: $2.7m charge) was recognised in the income statement (see Note 14).

7. Tax

	(unaudited) six months ended 30 Jun 2024	(unaudited) six months ended 30 Jun 2023	Year ended 31 Dec 2023
	$ million	$ million	$ million
Current tax	17.3	22.2	44.5
Deferred tax charge/(credit) on operations	1.0	(2.3)	(8.5)
Deferred tax credit on impairment charge	-	(0.3)	(16.2)
Total tax charge	18.3	19.6	19.8

The Group's corporation tax is calculated at 50% (1H 2023: 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 year can be reconciled to the profit / (loss) per the income statement as follows:


	(unaudited) six months ended 30 Jun 2024 $ million	(unaudited) six months ended 30 Jun 2023 $ million	Year ended 31 Dec 2023 $ million
Profit/(Loss) before tax	33.6	5.3	(29.0)
Profit/(Loss) before tax at 50% (2023: 50%)	16.8	2.6	(14.5)
Effects of:
Non-deductible expenses	4.0	6.5	18.0
Tax losses not recognised	(4.0)	10.5	16.5
Adjustments to tax charge in respect of previous periods	1.5	-	(0.2)
Tax charge for the period	18.3	19.6	19.8

2019

2018

The prevailing tax rate in Vietnam, where the Group produces oil and gas, is 50% (1H 2023: 50%). The tax charge in future periods may also be affected by the factors in the reconciliation above.

Non-deductible expenses primarily relate to Vietnam DD&A charges for costs previously capitalised, which are non-deductible for Vietnamese tax purposes of $3.8m (1H 2023: $6.3m; Dec 2023: $10.4m). A further $0.2m (1H 2023: $0.2m; Dec 2023: $0.8m) relates to non-deductible corporate costs including share scheme incentives. In the year ended 31 December 2023, non-deductible expenses also included the tax impact of Vietnam impairment charges of $6.8m.

Tax losses not recognised of $3.0m (1H 2023: $4.6m; Dec 2023: $7.3m) relate to costs deductible for tax in the UK but not expected to be utilised in the foreseeable future, as the UK tax group is loss-making. In addition, tax losses not recognised of $(7.0)m (1H 2023: $5.9m; Dec 2023: $9.2m) relate to Egypt. During 1H 2024, Egypt concessions recorded a net profit before tax of $14.0m (profit after tax impact of $7.0m) which has been offset against tax losses not recognised, as Egypt is in a historic loss making position. The group did not recognise deferred tax assets in relation to historical tax losses available to offset future taxable profits on the basis that there will be no future benefits arising from these losses as any taxes in the future will be paid by EGPC on behalf of the group.

8. Earnings/(loss) per share

The calculation of the basic and diluted earnings/(loss) per share is based on the following data:

	(unaudited) six months ended 30 Jun 2024	(unaudited) six months ended 30 Jun 2023	Year ended 31 Dec 2023
	$ million	$ million	$ million
Profit/(Loss) for the purposes of basic (loss)/profit per share	15.3	(14.3)	(48.8)
Effect of dilutive potential ordinary shares - Cash settled share awards and options	(0.3)	-	-
Profit/(Loss) for the purposes of diluted profit/(loss) per share	15.0	(14.3)	(48.8)

2019

2018

	(unaudited) six months ended 30 Jun 2024	(unaudited) six months ended 30 Jun 2023	Year ended 31 Dec 2023
	million	million	million
Weighted average number of ordinary shares	419.3	429.5	427.2
Effect of dilutive potential ordinary shares - Share awards and options	1.8	-	-
Weighted average number of ordinary shares for the purpose of diluted (loss)/profit per share	421.1	429.5	427.2

2019

2018

In accordance with IAS 33 "Earnings per Share", the effects of 1.7m and 2.8m antidilutive potential shares have not been included when calculating dilutive earnings per share for the period ended 30 June 2023 and the year ended 31 December 2023 respectively, 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 additions is Blocks 125 & 126 in Vietnam $1.2m and Egypt $0.7m, of which $0.3m relates to North Beni Suef.

In June 2024, 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 or Egypt.

Whilst ongoing costs for exploration are therefore 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 2024 stands at $26.8m (30 June 2023: $25.6m). This will be kept under review as the exploration activity continues.

10. Property, plant and equipment

As a result of previously recognised impairment losses, combined with a reduction in discount rate, we have tested our Egypt oil and gas producing properties for impairment or impairment reversal. For each producing property, the recoverable amount has been determined using the value in use method. The recoverable amount is calculated using a discounted cash flow valuation of the 2P production profile. No impairment triggers have been identified for other cash generating units in the Group.

Egypt

The key assumptions to which the recoverable amount measurement is most sensitive are oil price, discount rate, capital spend and 2P reserves. As at 30 June 2024, the fair value of the assets have been estimated based on a post-tax nominal discount rate of 15.1% (30 Jun 2023: 17.2%; 31 Dec 2023: 18.0%) and a Brent oil price of $82.6/bbl in 2H 2024 down to $77.2/bbl in 2027 plus inflation of 2% thereafter (30 Jun 2023: a Brent oil price of $84.2/bbl in 2H 2023 down to $75.2/bbl in 2026 plus inflation of 2% thereafter; 31 Dec 2023: a Brent oil price of $81.5/bbl in 2024 down to $76.3/bbl in 2027 plus inflation of 2% thereafter).

For El Fayum, an impairment reversal (pre and post-tax) in the amount of $8.5m has been reflected in the income statement, driven by the decrease in discount rate. As at 30 June 2024, the carrying amount of the El Fayum oil and gas producing property, after additions of $0.9m, DD&A $(2.1)m and after the impairment reversal of $8.5m, is $62.0m.

For NBS, no material impairment arose as a result of the above impairment considerations. As at 30 June 2024, the carrying amount of the NBS oil and gas producing property, after additions of $0.4m and DD&A $(0.2)m, is $1.2m.

Management consider fluctuations in Brent price and discount rates will have a material impact on the value of oil and gas producing assets. A reduction or increase of $5/bbl, based on average historical prices, and 1% change in post-tax discount rates, based on historical analysis of the Group's and peer group companies' impairments, could be reasonably possible for the purposes of sensitivity analysis. Testing of sensitivity cases for El Fayum indicated that a $5/bbl reduction in long term oil price used would result in an impairment of $7.0m (compared to new NBV). A 1% increase in discount rate would result in an impairment charge of $2.5m.

Vietnam

For TGT and CNV, there were no impairment triggers as at 30 June 2024 and the assets were not tested for impairment. As at 30 June 2024, the carrying amount of the TGT oil and gas producing property, after additions of $0.6m, changes in decommissioning asset $(1.5)m and DD&A $(16.5)m, is $141.2m. As at 30 June 2024, the carrying amount of the CNV oil and gas producing property, after additions of $0.3m, changes in decommissioning asset $(0.4)m and DD&A $(5.0)m, is $59.9m.

Other considerations

It is not considered possible to provide meaningful sensitivities in relation to 2P reserves and capital spend 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 of $0.4m (Dec 2023: $0.5m).

11. Distribution to Shareholders

A final dividend of 0.77 pence per share in respect of the year ended 31 December 2023, $4.1m equivalent, was formally approved by the shareholders at the Company's AGM in May 2024. The final dividend was paid in full on 19 July 2024 to shareholders on the register at the close of business on 14 June 2024.

In accordance with dividend policy, the Board has resolved to pay an interim dividend of 0.363 pence per share, $1.9m equivalent, in respect of the year ended 31 December 2024 and this will be paid on 22 January 2025 to shareholders on the Company's register as at 20 December 2024.

12. Reconciliation of operating profit to operating cash flows

	(unaudited) six months ended 30 Jun 2024	(unaudited) six months ended 30 Jun 2023	Year ended 31 Dec 2023
	$ million	$ million	$ million
Operating profit	35.2	13.3	(18.1)
Share-based payments	0.3	0.3	0.9
Depreciation, depletion and amortisation	23.9	30.0	55.6
Impairment charge - Intangibles	-	-	6.5
Impairment (reversal)/charge - PP&E	(8.5)	10.1	58.9
Operating cash flows before movements in working capital	50.9	53.7	103.8

(Increase)/decrease in inventories	(11.9)	1.1	3.9
Decrease/(increase) in receivables¹	6.8	(11.7)	(19.1)
(Decrease)/increase in payables	(1.5)	0.3	0.2

Cash generated by operations	44.3	43.4	88.8

Interest received	0.2	0.2	0.4
Other/redundancy expense outflow	(0.4)	-	-
Income taxes paid	(16.2)	(22.3)	(44.3)
Net cash from operating activities	27.9	21.3	44.9

¹ Includes $2.7m decrease (1H 2023: $2.4m increase) in risk factor provision in respect of Egypt trade receivables.

During the six months ended 30 June 2024, a total of $0.4m (1H 2023: $0.7m) of trade receivables due from EGPC in Egypt were settled by way of non-cash offset and relates to the assignment bonus settled upon receipt of contingent consideration in relation to IPR Farm out (1H 2023: $0.5m relates to the assignment bonus and $0.2m subscription to Egypt Upstream Gateway together with the purchase of the exploration and operation data package; there were no offsets against trade payables, see Note 15).

13. Hedge transactions

During 1H 2024, Pharos entered into zero cost collar hedges to protect the Brent component of forecast oil sales and to ensure future compliance with its obligations under the RBL over the producing assets in Vietnam. The commodity hedges run until June 2025 and are settled monthly.

Our hedging positions for the period resulted in $0.1m realised loss (1H 2023: no realised hedge gains or losses). The outstanding unrealised loss on open positions at 30 June 2024 amounts to $0.8m (1H 2023: outstanding unrealised gain of $0.2m).

During 1H 2024, 30% of the Group's total oil entitlement production has been hedged, securing average floor and ceiling prices for the hedged volumes at $63.4/bbl and $89.2/bbl, respectively. The Group's RBL requires the Company to hedge at least 35% of Vietnam RBL production volumes and the current hedging programme meets this requirement through to June 2025, leaving 71% of Group production unhedged as at 30 June 2024.

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 an external, third party commodities consultant. 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 liability position as at 30 June 2024 was $0.7m (30 Jun 2023: net receivable position of $0.3m; 31 Dec 2023: net receivable position of $0.1m).

Please see below for a summary of hedges outstanding as at 30 June 2024, which are all zero cost collar.

		3Q24	4Q24	1Q25	2Q25
Production hedge per quarter - 000/bbls	150		120	150	60
Average floor price of hedges - $/bbl	64.4		63.0	63.6	64.0
Average ceiling price of hedges - $/bbl	88.5		89.0	88.9	90.2

14. Borrowings

Changes in liabilities arising from financing activities:

	(unaudited) six months ended 30 Jun 2024 $ million			(unaudited) six months ended 30 Jun 2023 $ million
	Credit facility	RBL	Total Borrowings	Total Borrowings
Carrying value as of 1 January	9.2	31.3	40.5	74.2
Proceeds from Uncommitted Revolving credit facility	2.2	-	2.2	1.9
Repayments of borrowings	(8.2)	(20.0)	(28.2)	(23.8)
Interest expense and similar fees (see Note 6)	0.3	0.8	1.1	5.4
Interest paid during the year	(0.3)	(1.5)	(1.8)	(3.7)
Carrying value as of 30 June	3.2	10.6	13.8	54.0
Current	3.2	10.6	13.8	33.1
Non-current	-	-	-	20.9

Reserve Based Lending facility (RBL)

The RBL is secured over the Vietnam producing assets only and, as at 30 June 2024, has a one-year term maturing in June 2025. The loan bears a per annum interest rate of 5.25% plus Compound SOFR plus CAS (Credit Adjustment Spread). Until June 2023, the RBL bore a per annum interest of 4.75% plus USD LIBOR. For 1H 2024, the Group made voluntary early repayments of $20.0m ahead of the half year redetermination process.

The RBL is subject to a number of financial covenants, all of which have been complied with during the 1H 2024 and 2023 reporting periods.

Uncommitted revolving credit facility - National Bank of Egypt (Credit facility)

In January 2024, the Group renegotiated the uncommitted revolving credit facility with National Bank of Egypt for discounting (with recourse) of up to $10m until 30 May 2025 (1H 2023: $18m).

Loans are available for up to one year from the date of utilisation. The loan bore a per annum interest rate of USD LIBOR plus 3.00% for initial advances and 3.50% for any extensions beyond 180 days from the date of the utilisation until 30 June 2023. From 1 July 2023, 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.

15. Disposal of 55% interest in Egypt Concessions and fair value movement

Following the completion of the farm-out transaction of Egyptian assets to IPR, the accounting for the assets reflect the following:

The economic date of the transaction was 1 July 2020, with completion on 21 March 2022.

Pharos owned and managed the business up to completion. On completion, an adjustment to compensate for net cash flows since the economic date has been adjusted for in the level of carry to be provided by IPR to Pharos.

In the financial statements, for the period post completion, Pharos 45% share of field costs - capex, opex and G&A - are accounted for as incurred by Pharos, although all such costs are paid by IPR and set off against the carry.

All revenues earned are paid direct to Pharos.

The firm consideration was received in two tranches, $2.0m in September 2021 and $3.0m on 30 March 2022.

The carry of $35.9m is disproportionate funding contribution from IPR adjusted for working capital and interim period adjustments from the effective economic date of 1 July 2020 to the completion date.

The carry decreases every month against the cash calls received from IPR. The total amount utilised as at 30 June 2024 amounts to $35.9m, which reflects the full amount of the carry (2023: $23.2m). The movement during 1H 2024 was $5.0m, which has been disclosed in "Consideration in relation to farm out of Egyptian assets" in the cash flow as part of investing activities (combined with $3.6m contingent consideration received on 1 June 2023).

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. On 1 June 2024, contingent consideration of $3.6m in respect of average Brent price during 2023 was received from IPR. As at 30 June 2024, the contingent consideration receivable amounts to $6.3m, $3.8m in current trade and other receivables and $2.5m in non-current other assets (1H 2023: $7.9m, $3.5m in current trade and other receivables and $4.4m in non-current other assets). Testing of sensitivity for a $5/bbl reduction in long-term oil price used would result in $0.3m decrease in contingent consideration to $6.0m.

The fair value movement of $1.2m was credited to the income statement during 2024. This is due to $1.3m revision of the contingent consideration, partially offset by $0.1m reduction in contingent liability (assignment fee).

As at 30 June 2024, $0.6m (2023: $2.6m) relates to the assignment fee payable to EGPC 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. $0.4m is booked as current other payable and $0.2m as non-current other payable. Following receipt of contingent consideration amounting to $3.6m, an assignment bonus of $0.4m was offset against trade receivables from EGPC.

The final consideration is still being finalised between IPR and Pharos. The financial exposure from finalising the consideration to Pharos, reflecting the remaining amounts still under discussion, is considered immaterial to the financial statements.

16. Subsequent events

The RBL loan facility was repaid in full on 17 September 2024. The facility is currently scheduled to mature in July 2025.

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 shareholder returns.

For the RBL covenant compliance, three Non-IFRS measures are included: Net cash/(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) six months ended 30 Jun 24	(unaudited) six months ended 30 Jun 23	Year ended 31 Dec 23
	$ million	$ million	$ million
Cost of sales ¹	33.0	58.2	111.2
Less:
Depreciation, depletion and amortisation	(23.8)	(29.9)	(55.4)
Production based taxes	(4.9)	(6.3)	(10.5)
Inventories movement	11.9	(1.1)	(4.0)
Trade Receivable risk factor provision	2.7	(2.4)	(2.2)
Other cost of sales	(0.7)	(0.8)	(1.8)
Cash operating costs	18.2	17.7	37.3
Production (BOEPD)	5,851	6,915	6,508
Cash operating cost per BOE ($)	17.09	14.14	15.70

¹ Includes impairment reversal/(charge) of financial asset

Cash operating costs per barrel by segment (1H 2024)

	Vietnam		Egypt	Total
	$ million		$ million	$ million
Cost of sales	28.7		4.3	33.0
Less:
Depreciation, depletion and amortisation	(21.5)	(2.3)		(23.8)
Production based taxes	(4.8)	(0.1)		(4.9)
Inventories movement	11.7	0.2		11.9
Trade Receivable risk factor provision	-	2.7		2.7
Other cost of sales	(0.5)	(0.2)		(0.7)
Cash operating cost	13.6		4.6	18.2
Production (BOEPD)	4,456		1,395	5,851
Cash operating cost per BOE ($)	16.77		18.12	17.09

Vietnam	(unaudited) six months ended 30 Jun 24	(unaudited) six months ended 30 Jun 23
	$ million	$ million
Cost of sales	28.7	49.4
Less:
Depreciation, depletion and amortisation	(21.5)	(27.8)
Production based taxes	(4.8)	(6.2)
Inventories movement	11.7	(1.3)
Other cost of sales	(0.5)	(0.7)
Cash operating costs	13.6	13.4
Production (BOEPD)	4,456	5,566
Cash operating cost per BOE ($)	16.77	13.30

Egypt	(unaudited) six months ended 30 Jun 24	(unaudited) six months ended 30 Jun 23
	$ million	$ million
Cost of sales	4.3	8.8
Less:
Depreciation, depletion and amortisation	(2.3)	(2.1)
Production based taxes	(0.1)	(0.1)
Inventories movement	0.2	0.2
Trade Receivable risk factor provision	2.7	(2.4)
Other cost of sales	(0.2)	(0.1)
Cash operating costs	4.6	4.3
Production (BOEPD)	1,395	1,349
Cash operating cost per BOE ($)	18.12	17.61

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) six months ended 30 Jun 24	(unaudited) six months ended 30 Jun 23	Year ended 31 Dec 23
	$ million	$ million	$ million
Depreciation, depletion and amortisation	23.8	29.9	55.4
Production (BOEPD)	5,851	6,915	6,508
DD&A per BOE ($)	22.35	23.89	23.32

DD&A per barrel by segment (1H 2024)

	Vietnam	Egypt	Total
	$ million	$ million	$ million
Depreciation, depletion and amortisation	21.5	2.3	23.8
Production (BOEPD)	4,456	1,395	5,851
DD&A per BOE ($)	26.51	9.06	22.35

Vietnam	(unaudited) six months ended 30 Jun 24	(unaudited) six months ended 30 Jun 23	Year ended 31 Dec 23
	$ million	$ million	$ million
Depreciation, depletion and amortisation	21.5	27.8	51.0
Production (BOEPD)	4,456	5,566	5,127
DD&A per BOE ($)	26.51	27.59	27.25

Egypt	(unaudited) six months ended 30 Jun 24	(unaudited) six months ended 30 Jun 23	Year ended 31 Dec 23
	$ million	$ million	$ million
Depreciation, depletion and amortisation	2.3	2.1	4.4
Production (BOEPD)	1,395	1,349	1,381
DD&A per BOE ($)	9.06	8.60	8.73

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) six months ended 30 Jun 24	(unaudited) six months ended 30 Jun 23	Year ended 31 Dec 23 Restated ¹
	$ million	$ million	$ million
Total Debt	13.2	52.3	39.2
Total Equity	283.6	311.6	275.2
Debt to Equity	0.05	0.17	0.14

¹ Refer to Note 2.

Free cash flow

Free cash flow is calculated by subtracting capital cash expenditure from net cash from operating activities.

	(unaudited) six months ended 30 Jun 24	(unaudited) six months ended 30 Jun 23	Year ended 31 Dec 23
	$ million	$ million	$ million
Net cash from operating activities	27.9	21.3	44.9
Capital cash expenditure	(6.8)	(15.4)	(26.7)
Free cash flow	21.1	5.9	18.2

Operating cash per share

Operating cash per share is calculated by dividing net cash from continuing operations by number of shares.

	(unaudited) six months ended 30 Jun 24	(unaudited) six months ended 30 Jun 23	Year ended 31 Dec 23
	$ million	$ million	$ million
Net cash from continuing operating activities	27.9	21.3	44.9
Weighted number of shares in the year	427,953,678	439,346,597	427,170,044
Operating cash per share	0.07	0.05	0.11

Shareholder returns

Shareholder returns are calculated as a total of distributions to Shareholders and share buy backs.

	(unaudited) six months ended 30 Jun 24	(unaudited) six months ended 30 Jun 23	Year ended 31 Dec 23
	$ million	$ million	$ million
Interim dividend	1.9	-	1.8
Final dividend	-	-	4.1
Share buy backs	1.1	0.8	2.8
Shareholder returns	3.0	0.8	8.7

Net Cash/(Debt)

Net Cash/(Debt) comprises cash and cash equivalents, less interest-bearing bank loans.

	(unaudited) six months ended 30 Jun 24	(unaudited) six months ended 30 Jun 23	Year ended 31 Dec 23
	$ million	$ million	$ million
Cash and cash equivalents	30.7	35.9	32.6
Borrowings*	(13.2)	(52.3)	(39.2)
Net Cash/(Debt)	17.5	(16.4)	(6.6)

*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 including pre-licence costs and Other/restructuring expense items.

	(unaudited) six months ended 30 Jun 24	(unaudited) six months ended 30 Jun 23	Year ended 31 Dec 23
	$ million	$ million	$ million
Operating profit/(loss)	35.2	13.3	(18.1)
Depreciation, depletion and amortisation	23.9	30.0	55.6
Pre-licence costs	-	-	0.4
Impairment (reversal)/charge	(8.5)	10.1	65.4
EBITDAX	50.6	53.4	103.3

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. For H1 2024, the Company is in a net cash position overall and no data has therefore been presented.

	(unaudited) six months ended 30 Jun 24	(unaudited) six months ended 30 Jun 23	Year ended 31 Dec 23
	$ million	$ million	$ million
Net Debt	-	(16.4)	(6.6)
EBITDAX	-	53.4	103.3
Net Debt/EBITDAX	-	(0.31)	(0.06)

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) six months ended 30 Jun 24	(unaudited) six months ended 30 Jun 23	Year ended 31 Dec 23
	$ million	$ million	$ million
Operating profit/(loss)	35.2	13.3	(18.1)
Impairment charge	-	20.7	65.4
Impairment reversal	(8.5)	(10.6)	-
Operating profit excluding impairment (reversal)/charge	26.7	23.4	47.3

Glossary of Terms

boepd

Barrels of oil equivalent per day

bopd

Barrels of oil per day

CASH or cash

Cash, cash equivalent and liquid investments

CAPEX or capex

Capital expenditure

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

GHG

Greenhouse gas(es)

Group

Pharos and its direct and indirect subsidiary undertakings

HLJOC

Hoang Long Joint Operating Company, the operator of TGT

HVJOC

Hoan Vu Joint Operating Company, the operator of CNV

IPR or IPR Energy Group

The IPR Energy group of companies, including IPR Lake Qarun and IPR Energy AG, or such of them as the context may require

IPR Lake Qarun

IPR Lake Qarun Petroleum Co, an exempted company with limited liability organised and existing under the laws of the Cayman Islands (registration number 379306), a wholly owned subsidiary of IPR Energy AG

JOC

Joint Operating Company

Kilometre

km²

Square kilometre

Million

mmbbl

Million barrels

mmboe

Million barrels of oil equivalent

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

RFDP

Revised Field Development Plan

Ordinary share of 5p in the capital of the Company

TGT

Te Giac Trang field located in Block 16-1, Vietnam

$ or USD

United States Dollar

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Interim results for six months ended 30 June 2024