Pharos Energy plc

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

Interim results for the Half-year to 30 June 2023

Pharos Energy plc, an independent oil and gas exploration and production company, announces its interim results for the six months ended 30 June 2023. An analyst conference call will take place at 11.00 BST today.

 

Jann Brown, Chief Executive Officer, commented:

 "The first half of the year has been marked by strong operational performance. In Vietnam, the lateral well drilled on CNV came on production significantly above expectation and this success is now being factored into future development plans. In Egypt, The first exploration well drilled on the NBS concession was successful and efforts are underway to secure approval for production to commence in 4Q this year. An exploration well in a new zone of the main producing asset in Egypt, El Fayum, has also been successful. 

"Vietnam continues to deliver robust revenues and cash flows to support the business and our returns to shareholders. We are progressing the licence extensions through the system enabling us to prolong the lives of these fields. In Egypt, capital is being allocated carefully to reflect the economic situation. In the short term, we continue to be supported by the terms of the deal struck with IPR, with full carry plus the oil price based contingent consideration, the first payment for which we received in June.  Looking to the future, the potential of our Egyptian assets has been enhanced with exploration successes delivered this year. 

"Finally, we were delighted to secure a two-year extension to the term of our exciting frontier exploration position, Blocks 125/126 in Vietnam.  This extension gives us time to bring in the right farm in partner and to complete the necessary work to drill this basin opening play. The size of the prize has company making potential and the risk reward dynamic for investors from drilling is asymmetric. We will pursue drilling on Block 125 as soon as we have secured a partner and a rig.

"The company continues to focus on delivering returns to shareholders through our commitment to a regular dividend, our ongoing share buybacks, and by driving value throughout the portfolio to grow the business."

 

Corporate Highlights                                                                                                                                                        

·      Final dividend for the 2022 financial year of 1p per share, totalling $5.3m, approved by shareholders at the AGM and paid out on 12 July 2023

·      Continuation of $3m share buyback programme announced back in January, with a total of $0.7m spent as at 30 June 2023

·      First contingent payment of $5m from the deal with IPR received

 

 

Operational Highlights

·      Group working interest 1H production was 6,915 boepd net (1H 2022: 7,962 boepd) in line with full year guidance

·      Vietnam

-       Production 5,566 boepd net (1H 2022: 5,861 boepd net)

-       Recently drilled well CNV-2PST1 has been strongly contributing to CNV field production

-       TGT Revised Field Development Plan (RFDP) approved by MOIT, drilling rig tender is in progress for 2024 drilling campaign  

-       Applications for five-year extensions to the TGT & CNV licences, including terms and work programme commitments for the extension period, have been agreed by the partners and are currently with PVN for approval

-       Approval received from the Vietnamese Government for the two-year extension to Phase One of the Exploration Period under the Blocks 125 & 126 PSC to 8 November 2025

-       CPR for Block 125 confirms a range of gross unrisked prospective oil resources of between 1,178 MMstb (1U) and 29,785 MMstb (3U) with a Mean value of 13,328 MMstb

 

 

 

·      Egypt

-       Production 1,349 bopd (1H 2022: 2,101 bopd, working interest 100% up to 21 March 2022 )

-       Egypt production has been stable in the first half of the year underpinned by a small development drilling campaign plus a  focus on workovers, recompletions, and water injection to bring low-cost barrels to production and build reservoir energy for future drilling

-       Four development wells and one exploration commitment well were drilled in the El Fayum concession in 1H 2023

-       The first exploration commitment well in the El Fayum Concession encountered oil-bearing reservoirs in the Abu Roash G and Upper Bahariya formations. The well will be tested to confirm deliverability using one of the workover rigs  

-       The first exploration commitment well in the North Beni Suef Concession (NBS-SW1X) was declared a commercial discovery after encountering multiple pay zones in the Abu Roash G formation. The stabilised production test rate pre-frac is 470 bopd (gross). The operator has requested approval from the regulator for the grant of the NBS Development Lease with a view to starting commercial production in 4Q 2023

-       Acquisition of c.130 km² of additional 3D seismic at NBS is completed and a second well will be drilled this year

 

Financial Highlights

·      Group revenue $86.2m (1H 2022: $129.6m) with no realised hedging gains or losses (1H 2022: prior to realised hedging losses of $17.3m)

·      Net loss of $14.3m (1H 2022: $54.3m profit), including non-cash impairment charge after tax of $9.8m (1H 2022: impairment reversal after tax $49.2m)

·      Cash generated from operations $43.4m¹ (1H 2022: $57.0m)¹

·      Operating cash flow $21.3m⁴  (1H 2022: $27.6m)⁴

·      Cash operating costs $14.14/bbl² (1H 2022: $15.82/bbl)² 

·      Cash balances as at 30 June 2023 of $35.9m (30 June 2022: $47.5m)

·      Forecast cash capex for the full year pre-carry is $27.4m (post carry $13.2m), of which $15.4m (post carry $8.3m) had been incurred by 30 June 2023

·      Net debt as at 30 June 2023 of $16.4m^2,3 (30 June 2022: $37.9m)^2,3

·      Net debt to EBITDAX of 0.31x ² (1H 2022: 0.51x) ²

¹ Stated after realised hedging gain/loss of $nil (1H 2022: loss of $17.3m)

² See Non-IFRS measures on page 30

³ Includes RBL and National Bank of Egypt working capital drawdown

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

 

 

Outlook

·      2023 full year Group working interest production guidance updated to 6,350 - 6,750 boepd net from 6,050 - 7,500 boepd net

·      Vietnam

-       2023 production guidance narrowed to 5,000 - 5,300 boepd net from 4,700 - 5,700 boepd net

-       TGT RFDP currently with the Government for approval; drilling programme, which includes two wells, expected to commence following approval of the RFDP

-       CNV RFDP to be submitted to partners for approval in 4Q 2023

-       Work ongoing to progress well planning, with discussions ongoing to secure a partner ahead of drilling the commitment well on Block 125

-       Additional independent work is being undertaken by ERCE to extend the review to identify leads and mature these into Prospects

·      Egypt

-       2023 production guidance narrowed to 1,350 - 1,450 bopd net from 1,350 - 1,800 bopd net

-       Additional workover and waterflood projects to be completed in 2H 2023

-       NBS first commitment well targeted to be on production in 4Q 2023

-       Second exploration commitment well on NBS is expected to be drilled this year

·      Net Zero roadmap to be published in 4Q 2023

 

Enquiries

 

Pharos Energy plc                                                                                                                                   Tel: 020 7747 2000

Jann Brown, Chief Executive Officer      

Sue Rivett, Chief Financial Officer 

 

Camarco                                                                                                                                                 Tel: 020 3757 4980

Billy Clegg | Andrew Turner | Rebecca Waterworth | Kirsty Duff

 

Notes to editors

Pharos Energy plc is an independent energy company with a focus on sustainable growth and returns to stakeholders, which is listed on the London Stock Exchange. Pharos has production, development and/or exploration interests in Egypt and Vietnam. In Egypt, Pharos holds a 45% working interest share in the El Fayum Concession in the Western Desert, with IPR Lake Qarun, part of the international integrated energy business IPR Energy Group, holding the remaining 55% working interest. The El Fayum Concession produces oil from 10 fields and is located 80 km southwest of Cairo. It is operated by Petrosilah, a 50/50 joint stock company between the contractor parties (being IPR Lake Qarun and Pharos) and the Egyptian General Petroleum Corporation (EGPC). Pharos also holds a 45% working interest share in the North Beni Suef (NBS) Concession in Egypt, which is located immediately south of the El Fayum Concession. IPR Lake Qarun operates and holds the remaining 55% working interest in the NBS Concession. In Vietnam, Pharos has a 30.5% working interest in Block 16-1 which contains 97% of the Te Giac Trang (TGT) field and is operated by the Hoang Long Joint Operating Company. Pharos' unitised interest in the TGT field is 29.7%. Pharos also has a 25% working interest in the Ca Ngu Vang (CNV) field located in Block 9-2, which is operated by the Hoan Vu Joint Operating Company. Blocks 16-1 and 9-2 are located in the shallow water Cuu Long Basin, offshore southern Vietnam. Pharos also holds a 70% interest in, and is designated operator of, Blocks 125 & 126, located in the moderate to deep water Phu Khanh Basin, north east of the Cuu Long Basin, offshore central Vietnam.

 

Operational Review

Health, Safety

Safety continues to be the top priority for our business, and we are committed to operating safely and responsibly at all times and to providing a safe and healthy working environment for staff and contractors. We work closely with our JV/JOC partners to ensure work safety practices are adhered to. We provide regular training and conduct test exercises to ensure the workforce remains updated and prepared at all times.  

 

We are pleased to report that in Egypt and Vietnam, we have worked with our partners to maintain our record of zero Lost Time Injury

(LTI) frequency rate through the first half of 2023. Two spillage incidents involving crude oil shipping trucks occurred in Egypt in the first quarter of the year and a thorough internal investigation was conducted which led to changing of the crude oil shipping contractor. No injuries occurred during these two incidents.

 

 

Vietnam

Vietnam Production

Production for the first half of 2023 from the TGT and CNV fields net to the Group's working interest averaged 5,566 boepd (1H 2022: 5,861 boepd), in line with our previously published guidance on 22 March 2023 of 4,700-5,700 boepd net.

 

TGT 1H 2023 production averaged 13,423 boepd gross and 3,983 boepd net to Pharos (1H 2022: 15,133 boepd gross and 4,490 boepd net). CNV 1H 2023 production averaged 6,333 boepd gross and 1,583 boepd net to Pharos (1H 2022: 5,483 boepd gross and 1,371 boepd net).

 

Working interest production guidance in Vietnam is now narrowed to 5,000 - 5,300 boepd net to reflect CNV-2PST1 well performance, which came on above expectations and is offset by the shifting of TGT well activities from 4Q 2023 to 1Q 2024 as a result of the delay in full field shut down to October 2023.

 

 

Vietnam Development and Operations  

On Block 9-2 - CNV Field, well CNV-2PST1 was completed and put on stream on 18 February 2023. Production results peaked at c. 3,000 bopd (gross) in 1H compared to pre-drill estimates of c. 1,000 bopd (gross), and are still stabilising. Discussions are ongoing with our partners to incorporate the lessons learned from this successful well into the Revised Field Development Plan (RFDP) under preparation.

 

On Block 16-1 - TGT Field, the RFDP for two new wells has been approved by MOIT, awaiting final government approval.  Planning underway for 2024 TGT drilling campaign of the two new wells, drilling rig tender is in progress.

 

Applications for five-year extensions to the TGT & CNV licences, including terms and work programme commitments for the extension period, are with PVN and are expected to be submitted to Government for approval.

 

Vietnam Exploration

Approval received from the Vietnamese Government in June 2023 for the two-year extension to Phase One of the Exploration Period under the Blocks 125 & 126 PSC to 8 November 2025.

 

On 20 July 2023, the Company published an independent assessment by ERCE for Block 125, which confirms a range of gross unrisked prospective oil resources of between 1,178 MMstb (1U) and 29,785 MMstb (3U) with a Mean value of 13,328 MMstb for the Prospects in the North West area of Block 125 currently covered fully or partially by 3D seismic. These resources do not include Leads already identified in Blocks 125 & 126 but not yet covered by 3D seismic.

 

The full ERCE report, including the analysis of the estimated geological chance of success (COS), can be found at https://www.pharos.energy/operations/vietnam/blocks-125-126/ and at https://www.pharos.energy/investors/results-reports-and-presentations/.

 

Vietnam outlook & operational focus for remainder of 2023  

 

·      Vietnam

-       2023 production guidance narrowed to 5,000 - 5,300 boepd net from 4,700 - 5,700 boepd net

-       TGT RFDP drilling programme, which includes two wells, expected to commence in 2H 2024

-       CNV RFDP to be submitted to partners for approval

-       Work ongoing to progress well planning, with discussions ongoing to secure a partner ahead of drilling the commitment well on Block 125

-       Additional independent work is being undertaken by ERCE to extend the review to identify Leads and mature these into Prospects

 

Egypt

El Fayum Production

Production for the first half of 2023 from El Fayum averaged 1,349 bopd net to Pharos (1H 2022: 2,101 bopd, net WI 100% up to 21 March 2022).

El Fayum Development and Operations 

Three wells have been put on production, one exploration well drilled and one new injection well was put on injection in the period to 30 June 2023.

 

In addition to drilling new wells, the operations team has focused on recompletions to bring new zones to production and implement new water injection projects, which have supported production in the first half and are expected to continue to contribute to production in the second half.

 

Our work programme in Egypt is expected to be fully carried throughout 2023 and the partners have agreed a measured approach to capital allocation and drilling in El Fayum, with an eye on the receivables balance. As a result, we decided to use the same rig for drilling in both El Fayum and NBS which will mean reduced drilling in El Fayum in 2H 2023.

 

The partners continue to refine additional exploration prospects in the deep, shallow and unconventional reservoirs.

 

El Fayum Exploration

 

The first exploration commitment well in the El Fayum Concession has reached total depth and encountered oil-bearing reservoirs in the Abu Roash G and Upper Bahariya formations. The well will be tested to confirm deliverability using one of the workover rigs. 

 

North Beni Suef (NBS) Exploration

 

The first exploration commitment well in the North Beni Suef Concession (NBS-SW1X) was declared a commercial discovery after encountering multiple pay zones in the Abu Roash G formation. The stabilised production test rate pre-frac is 470 bopd (gross). The operator has requested approval from EGPC for the grant of the NBS development lease with a view to starting commercial production in 4Q 2023.

 

Acquisition of c.130 km² of additional 3D seismic at NBS is completed. The next steps are processing and interpretation of the seismic data, which is expected to be completed in 2024.

 

Egypt outlook & operational focus for remainder of 2023

 

·      Egypt

-       2023 production guidance narrowed to 1,350 - 1,450 bopd net from 1,350 - 1,800 bopd net

-       Additional workover and waterflood projects to be completed in 2H 2023

-       NBS first commitment well targeted to be on production in 4Q 2023

-       Second exploration commitment well on NBS is expected to be drilled this year

-       3D Seismic to be completed in 3Q 2023

 

 

Financial Review

Finance strategy

Our finance strategy continues to underpin the Group's business model and goes hand in hand with our commitment to building shareholder value through capital growth and sustainable dividends.

The first half of 2023 has seen strong operational delivery across our portfolio, with the low-cost lateral well on CNV exceeding expectations and the completion of three development wells on the El Fayum Concession, with drilling ongoing in the multi-well development programme. The successful completion of the farm down in Egypt last year has allowed the Company to continue to benefit from a full carry of all contractor costs for G&A, opex and the capital programme in the first half of 2023. This activity has been supported by stable oil prices and has allowed us to deliver strong positive cash flow and growth in value, as well as significantly reducing net debt. Returns to shareholders have been delivered through the commencement of an additional $3m share buyback programme in January and the payment of a final dividend for 2022 of 1.00 pence per share, based on operating cash flow of $53.4m which was approved by shareholders at the AGM in May.

 

 

Highlights

	1H 2023	1H 2022
Production Volumes (boepd)	6,915	7,962
Production Volumes - Vietnam (boepd)	5,566	5,861
Production Volumes  - Egypt (boepd)3	1,349	2,101
Oil Price Realised ($/bbl)	84.89	109.47
Oil & Gas Price Realised ($/boe)	76.29	99.49
Oil & Gas Sales ($m)	86.2	129.6
Total Revenue ($m)1	86.2	112.3
Gross Profit ($m)	28.0	52.4
Operating profit ($m)	13.3	110.2
Operating profit excluding impairment (reversal)/charge ($m)²	23.4	47.4
Net cash from operating activities (OCF)	21.3	27.6
Shareholder returns 4	0.7	-
Cash operating cost per ($/boe)2	14.14	15.82
Net debt ($/m)2	16.4	37.9
EBITDAX ($/m)2	53.4	75.0
Gearing2	0.17	0.24

¹ No realised hedge gains or losses in the period (1H 2022: loss of $17.3m)

² See Non-IFRS measures on page 30

³ From 21 March 2022, includes 45% Pharos share of production

⁴ Includes continuation of $3m share buyback programme, $0.7m of which had been incurred by 30 June 2023. Final Group dividends of $5.3m in respect of the year ended 31 December 2022 were paid to shareholders in July 2023

 

 

 

 

Cash operating cost per barrel	1H 2023 $m	1H 2022 $m
Cost of sales	58.2	59.9
Less
Depreciation, depletion and amortisation	(29.9)	(27.6)
Production based taxes	(6.3)	(8.8)
Export duty	-	(3.2)
Inventories	(1.1)	5.1
Other cost of sales	(0.8)	(1.1)
Trade Receivable risk factor provision	(2.4)	(1.5)
Cash operating costs	17.7	22.8
Production (BOEPD)	6,915	7,962
Cash operating cost per BOE ($)	14.14	15.82

 

 

Cash operating cost per barrel by Segment	Vietnam     $m	Egypt     $m	Total     $m
Cost of sales	49.4	8.8	58.2
Less
Depreciation, depletion and amortisation	(27.8)	(2.1)	(29.9)
Production based taxes	(6.2)	(0.1)	(6.3)
Inventories	(1.3)	0.2	(1.1)
Other cost of sales	(0.7)	(0.1)	(0.8)
Trade Receivable risk factor provision	-	(2.4)	(2.4)
Cash operating costs	13.4	4.3	17.7
Production (BOEPD)	5,566	1,349	6,915
Cash operating cost per BOE ($)	13.30	17.61	14.14

 

Operating Performance

Revenue

Oil & gas sales for the period were down 33% to $86.2m (1H 2022: $129.6m) with no realised hedge gains or losses in the period (1H 2022: $17.3m realised losses). Two factors impacted the Egyptian revenue being a one off catch up invoice to EGPC for $7m in 2022 which improved our overall contractor take by c.20% and the farm down to IPR in March 22 of 55% of the concession. Removing these elements means that the main driver on reduced revenue is the Brent price decreasing by 27% period on period.

In Vietnam, revenues decreased 25% to $77.6m (1H 2022: $103.8m). The average realised crude oil price, including the premium received over Brent, was $86.14/bbl (1H 2022: $111.50/bbl), a 23% decrease. The premium to Brent rose to just under $8/bbl (1H 2022: just over $3/bbl). Production decreased from 5,861 boepd to 5,566 boepd, a reduction of 5%.

In Egypt, revenues decreased 67% to $8.6m (1H 2022: $25.8m) which, in part, was a result of invoicing for an additional $7m in January 2022 following approval of the third amendment to the El Fayum Concession agreement which increased the cost recovery from 30% to 40% from November 2020. In addition, the Company had 100% share of reported production up to 20^th March 2022 upon completion of the farm-out transaction to IPR. Our share of production moved from 2,101 bopd net to 1,349 bopd net. The average realised crude oil price, after discounts, was $75.21/bbl (1H 2022: $99.57/bbl), a decrease of 24%. There are two discounts applied to the El Fayum crude production - a general Western Desert Discount and one related specifically to El Fayum. Both are set by EGPC (the in-country regulator) and together decreased to under $5/bbl (1H 2022: $6/bbl).

 

 

 

Group operating costs, DD&A and expenses

Cash operating costs at Group level, defined in the Non-IFRS measures section on page 30, amounted to $17.7m (1H 2022: $22.8m), a 22% decrease over the same period last year. On a barrel of oil equivalent basis, this was $14.14/boe (1H 2022: $15.82/boe).

Cash operating costs in Vietnam decreased to $13.4m (1H 2022: $16.5m) in the period which equates to $13.30/bbl (1H 2022: $15.55/bbl). The decrease is due to lower costs relating to the FPSO as a result of higher production from the TLJOC, which shares the facilities and the costs of the FPSO based on production rates. TLJOC had a 26.0% cost share in 1H 2023 compared to 11.5% in 1H 2022. In addition, all cargos were sold locally and therefore no export tax was incurred.

Cash operating costs in Egypt were $4.3m (1H 2022: $6.3m) in the period, which equates to $17.61/bbl (1H 2022: $16.57/bbl). The 6% increase in cost per bbl was mainly related to increase in the number of workover jobs carried out during the 1H 2023 compared to 1H 2022, offset by decrease in fixed costs due to EGP devaluation. Cash operating costs from 1 January 2022 up to 20 March 2022 are 100% share and from 21 March 2022 include 45% Pharos share. On a 100% equivalent basis the cash operating costs for 1H 23 were $9.3m (1H 2022: $10.9m).

DD&A charges on production and development assets increased to $29.9m (1H 2022: $27.6m), driven by a higher depreciating cost base following 2022 impairment reversals taken on both Vietnam and Egypt, partially offset by 13% reduction in group production volumes. DD&A per bbl is currently $23.89/boe (1H 2022: $19.15/boe).

Administrative expenses of $4.6m (1H 2022: $5.0m) are lower than the comparative period. After adjusting for the non-cash items such as depreciation and IFRS 2 Share Based Payments of $0.4m (1H 2022: $0.9m), the administrative expense is $4.2m (2022: $4.1m).  

 

Impairments and Impairment Reversals

 

As a result of previously recognised impairment losses, combined with the ongoing oil price volatility, economic uncertainty leading to an increase in inflation and discount rates, and movements in 2P reserves, we have tested each of our oil and gas producing properties for impairment. For each producing property, the recoverable amount has been determined using the value in use method derived from a discounted cash flow valuation of the 2P production profile. The results of these impairment tests are summarised below.

Summary of Impairments  - Oil and Gas properties	TGT $m	CNV $m	Egypt $m	Total $m
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: 1
As at 1 Jan 2023	242.4	76.4	62.5	381.3
Additions	0.7	2.6	5.8	9.1
Changes in decommissioning asset 2	-	(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 Jun 2023	210.9	80.5	56.7	348.1

 

1H 2022
Pre-tax impairment reversal	24.8	13.6	24.5	62.9
Deferred tax charge	(8.6)	(5.1)	-	(13.7)
Post-tax impairment reversal	16.2	8.5	24.5	49.2
Reconciliation of carrying amount: 1
As at 1 Jan 2022	266.0	84.2	49.2	399.4
Additions	0.5	0.2	6.7	7.4
Changes in decommissioning asset 2	(8.7)	(1.7)	-	(10.4)
DD&A	(20.6)	(5.3)	(1.7)	(27.6)
Impairment reversal	24.8	13.6	24.5	62.9
As at 30 Jun 2022	262.0	91.0	78.7	431.7

¹ Egypt carrying value reflects 45% share (1H 2022: 45%)

² Changes in decommissioning asset for TGT is due to a change in discount rate only, whereas CNV reflects the change in field abandonment plan and discount rate (1H 2022: change in discount rate and field abandonment plan for TGT and change in discount rate only for CNV)

It should be noted that the CNV impairment reversal at 1H 2023 was restricted to reflect the remaining balance of historic impairment charges previously recorded against the field. The impairment reversal test calculated NPV12.7 of $45.2m which would have been a pre-tax reversal of $11.6m, but this was restricted to $10.6m. Further details of these impairment charges, including key assumptions in relation to oil price and discount rate are provided in Note 10 of the interim financial statements.

 

Hedging

For 2023, 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. Our hedging positions for the period resulted in no realised gains or losses (1H 2022: loss of $17.3m). Additionally, the fair value as at 30 June 2023 was an unrealised gain of $0.2m for the remaining hedges in place (1H 2022: unrealised loss of $11.3m).

For 2023, 35% of the Group's total oil entitlement production has been hedged, securing average floor and ceiling prices for the hedged volumes at $64.5/bbl and $100.8/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 2024, leaving 75% of Group production unhedged as at 30 June 2023.

Please see below a summary of hedges outstanding as at 30 June 2023, which are all zero cost collar.

 

		3Q23	4Q23	1Q24	2Q24
Production hedge per quarter - 000/bbls	180		141	120	60
Average floor price of hedges - $/bbl	63.33		63.96	63.00	63.00
Average ceiling price of hedges - $/bbl	102.23		93.66	91.50	91.00

 

Financing costs

Finance costs for the period were $6.9m (1H 2022: $5.6m) and included a non-cash charge of $2.3m (1H 2022: $0.7m) following the June 2023 redetermination of the Group's reserve-based lending facility, which lead to a change in estimated future cash flows. This impact was offset by an amortisation adjustment of capitalised borrowing costs in relation to the RBL of $(0.6)m (1H 2022: $1.3m charge) and, in addition, there was interest expense payable and similar fees of $3.7m (1H 2022: $2.4m), unwinding of discount of provisions $1.0m (1H 2022: $0.5m) and foreign exchange losses of $0.5m (1H 2022: $0.7m) primarily driven by the devaluation of EGP against USD.

 

 

 

 

 

Taxation

The overall net tax charge of $19.6m (1H 2022: $43.9m) relates to tax charges in Vietnam of $19.9m less the deferred tax credit on net impairment charge of $(0.3)m (1H 2022: Vietnam tax charges of $30.2m plus the deferred tax charge on impairment reversal of $13.7m).

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. No tax has been recorded for 1H 2023 due to PEF recording a net loss of $(11.7)m, inclusive of $(9.5)m pre and post-tax impairment charge.

One of the Group's companies entered into commodity hedges designated as cash flow hedges. In accordance with IAS 12, no deferred tax asset has been recognised in relation to the historic hedging losses as it is unlikely that the UK tax group will generate sufficient taxable profit in the future, against which the deductible temporary differences can be utilised.

Net loss

A net loss was recorded for the period from continuing operations of $(14.3)m, which is after $(9.8)m post-tax impairment charge on PPE (1H 2022: profit $54.3m, which is after $49.2m post-tax impairment reversal on PPE and $(0.1)m impairment of intangibles in Israel).

 

Balance Sheet

Net cash/debt

As at the balance sheet date, $52.3m (RBL $42.6m and NBE $9.7m) was drawn under the Group's borrowing facilities and there was cash of $35.9m, giving a net debt figure of $16.4m (1H 2022: RBL $77.8m and NBE $7.6m; cash $47.5m and net debt of $37.9m).  Gearing has been calculated as total debt to equity of 0.17x (1H 2022: 0.24x).

As at 30 June 2023, the trade receivables with EGPC stood at $30.9m (31 Dec 22: $24.2m), of which $29.6m was overdue. As noted in previous updates to the market, the Group has opted not to accept the payment of PEF's receivables balance in EGP unless required for operations. PEF is entitled under contract to be paid for hydrocarbon sales in US dollars. The further devaluation of EGP against USD since year end plus the lack of ability to convert EGP into USD means that it remains preferable to continue to hold USD denominated receivables.

Following the approval of the International Monetary Fund's (IMF) $3 billion loan and the disbursement of the first $347 million tranche, progress between the IMF and the Egyptian Government has been slow due to delays in the implementation of the agreed structural reforms. However, FX reserves have remained stable (c. $34.8 billion). More recently, the Government has announced it has signed a number of deals to sell off $1.9 billion worth of stakes in state-owned entities, signalling that the privatisation efforts are finally underway. The Company remains optimistic that the outstanding receivables will start to be recovered in the near future.

Borrowings 

Reserve Based Lending (RBL)

The RBL is secured over the Vietnam producing assets only and, as at 30 June 2023, has a two-year term maturing in July 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 2023, the principal repayment made amounted to $22.4m (1H 2022: $0.2m) and the borrowing base as at 30 June 2023 was $42.6m (30 June 2022: $77.8m).

Agreement reached with the RBL banking group to amend the reference benchmark interest rate of USD LIBOR to the Secured Overnight Financing Rate (SOFR), with effect from 30 June 2023. The loan now 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 2023 was $9.7m (30 June 2022: $7.6m) 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 using the El Fayum oil sales invoices as evidence to support its ability to repay the facility. The oil sales invoices remain due to Pharos and it retains the credit risk.  The Group therefore continue to recognise the receivables in their entirety in its balance sheet. 

In May 2023, the Group renegotiated the uncommitted revolving credit facility with National Bank of Egypt for discounting (with recourse) of up to $18m until 31 May 2024 (1H 2022: $18m).

The loan bears a per annum interest rate of Term SOFR plus CAS 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 $43.4m (1H 2022: $57.0m) and prior to working capital movements was $53.7m (1H 2022: $75.8m). There were no realised hedging gains or losses (1H 2022: $17.3m loss), so stripping out the impact of the hedging positions to the underlying operations numbers does not affect the total of $53.7m (1H 2022: $93.1m), which is in-line with the decline in commodity prices and the Group production decrease period on period.

The increase in receivables was $11.7m for the period (1H 2022: increase of $10.4m). The 2023 movement is mainly driven by $6.4m trade receivables from Vietnam due to a higher number of TGT cargoes lifted in June 2023 compared to December 2022, partially offset by a reduction in realised oil prices.  Payment for these cargoes was received in July. Egypt trade receivables with EGPC increased by $4.2m due to the ongoing economic issues causing EGP to devalue and continued restrictions on outgoing USD transfers (1H 2022: the average oil price realised from YE21 increased from $70.95/bbl to $109.47/bbl therefore increasing the receivables balance held at half-year). 

Share Buyback and Dividends

Following a period of improved commodity prices and a strengthening of the Group's liquidity position, we have committed to shareholder returns in the form of share buybacks and dividends. The Company announced the continuation of a further $3m share buyback programme in January 2023, of which $0.7m had been incurred by the end of June 2023.

 

In September 2022, we announced a clear sustainable policy for the recommencement of 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 previous year's final dividend, payable in January of the following year; and

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

 

A final dividend of 1.00 pence per share was recommended by the Board in respect of the year ended 31 December 2022.  This was formally approved by the shareholders at the Company's 2023 AGM in May and paid in full on 12 July 2023 to shareholders on the register at the close of business on 16 June 2023.

 

 

Liquidity risk management and going concern

The Group closely monitors its liquidity risk. Cash forecasts are regularly produced, and stress tested for a number of scenarios including a downturn in the oil price, changes in production rates, operating costs and capital expenditure. Given the current rapid-changing global political and economic landscape, the fluctuating yet strengthening oil prices, and the persisting economic uncertainties with escalating inflation and interest rates, the scope of our scenario planning remains extensive. Accordingly, stress tests have been run for oil prices down to $56/bbl in November 2023, 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%, assumptions regarding payments in local currency, and the Egypt receivable balance building-up further. As at 30 June 2023, the Group had a cash balance of $35.9m and the forecasts show that the Group will have sufficient financial headroom for the period of 12 months from the date of approval of these half-year results. The Directors therefore have a reasonable expectation that the Company has adequate resources to continue in operational existence for the foreseeable future. Thus, they continue to adopt the going concern basis of accounting in preparing these half-year results.

 

 

Sue Rivett

Chief Financial Officer

Corporate Review

 

ESG

 

The management of our Greenhouse Gas (GHG) Emissions remains a key issue for the Group. We continue our journey to implementing the TCFD recommendations and, during the first half of 2023, we have made good progress on the development of our Net Zero roadmap, which will be published in Q4 2023. Current consideration for the roadmap includes mapping out emission reduction frameworks that can be achieved without the use of carbon offsetting or carbon credits in the near term, interim targets over the short, medium and long term, as well as the capital resourcing needed to achieve our goals.

                                                                                                                                                                                                                               

 

Pharos remains committed to creating value in a sustainable manner for host countries and local communities. We continue to invest in long-term social projects through the HLHVJOC Charitable Donation programme. For 2023, 14 charitable projects have been approved, ranging from providing healthcare and educational support for children with disabilities to supporting local communities in areas hit hardest by flash flooding and hurricane damage, with 4 projects already completed in 1H 2023 and 10 more to be completed in the latter half of the year. In 1Q 2023, the Group provided financial support to families with difficult financial situations in the Thai Binh and Hoa Binh province for the Vietnamese Lunar New Year. In 2Q 2023, the Donation programme helped fund special education programme for secondary and high school students with hearing-impairments. We work closely with our local and joint venture partners in order to make sure that our social initiatives bring positive impacts to the region, and will keep stakeholders updated on progress.

 

Principal and Emerging risks and Uncertainties for the second half of 2023

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 2023. The key principal and emerging risks are:

·      HSE & Social

·      Prolonged War in Ukraine / ensuing sanctions

·      Risk of rising inflation and stagflation

·      Inability to repatriate cash earned from Egypt

·      Further devaluation of the Egyptian pound

·      Legal risks - Sanctions related

·      Climate Change

·      Commodity price volatility

·      Volatility in production levels

·      Partners' alignment

·      Sub-optimal capital allocation

·      Political and Regional

·      Cyber security

·      Reserves downgrades

·      Insufficient funds to meet commitments

·      Inability to optimise value from portfolio *

 

* New/emerging risks identified at HY 2022.

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 2023 which comprises the condensed consolidated income statement, the condensed consolidated statements of comprehensive income, the condensed consolidated balance sheets, the condensed consolidated statements of changes in equity, the condensed consolidated cash flow statements and related notes 1 to 16.

 

Based on our review, nothing has come to our attention that causes us to believe that the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2023 is not prepared, in all material respects, in accordance with United Kingdom adopted International Accounting Standard 34 and the Disclosure Guidance and Transparency Rules of the United Kingdom's Financial Conduct Authority.

 

Basis for Conclusion

 

We conducted our review in accordance with International Standard on Review Engagements (UK) 2410 "Review of Interim Financial Information Performed by the Independent Auditor of the Entity" issued by the Financial Reporting Council for use in the United Kingdom (ISRE (UK) 2410). A review of interim financial information consists of making inquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures. A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing (UK) and consequently does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion.

 

As disclosed in note 2, the annual financial statements of the group are prepared in accordance with United Kingdom adopted international accounting standards. The condensed set of financial statements included in this half-yearly financial report has been prepared in accordance with United Kingdom adopted International Accounting Standard 34, "Interim Financial Reporting".

 

Conclusion Relating to Going Concern

 

Based on our review procedures, which are less extensive than those performed in an audit as described in the Basis for Conclusion section of this report, nothing has come to our attention to suggest that the directors have inappropriately adopted the going concern basis of accounting or that the directors have identified material uncertainties relating to going concern that are not appropriately disclosed.

 

This Conclusion is based on the review procedures performed in accordance with ISRE (UK) 2410; however future events or conditions may cause the entity to cease to continue as a going concern.

 

Responsibilities of the directors

 

The directors are responsible for preparing the half-yearly financial report in accordance with the Disclosure Guidance and Transparency Rules of the United Kingdom's Financial Conduct Authority.

 

In preparing the half-yearly financial report, the directors are responsible for assessing the group's ability to continue as a going concern, disclosing as applicable, matters related to going concern and using the going concern basis of accounting unless the directors either intend to liquidate the company or to cease operations, or have no realistic alternative but to do so.

 

Auditor's Responsibilities for the review of the financial information

 

In reviewing the half-yearly financial report, we are responsible for expressing to the group a conclusion on the condensed set of financial statements in the half-yearly financial report. Our Conclusion, including our Conclusion Relating to Going Concern, are based on procedures that are less extensive than audit procedures, as described in the Basis for Conclusion paragraph of this report.

 

Use of our report

 

This report is made solely to the company in accordance with ISRE (UK) 2410. Our work has been undertaken so that we might state to the company those matters we are required to state to it in an independent review report and for no other purpose. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the company, for our review work, for this report, or for the conclusions we have formed.

 

 

 

Deloitte LLP

Statutory Auditor

London, United Kingdom

13 September 2023

 

 

 

Condensed consolidated income statement
										(unaudited) Six months ended	(unaudited) Six months ended		Year ended
										30 Jun 2023	30 Jun 2022		31 Dec 2022
									Notes	$ million	$ million		$ million
Continuing operations
Revenue									3, 13	86.2	112.3		199.1
Cost of sales									4	(58.2)	(59.9)		(116.8)
Gross profit										28.0	52.4		82.3
Administrative expenses										(4.6)	(5.0)		(10.0)
Impairment (charge)/reversal - Intangibles									3, 9	-	(0.1)		0.8
Impairment (charge)/reversal - PP&E									3, 10	(10.1)	62.9		27.1
Operating profit										13.3	110.2		100.2
Other/restructuring expense									5	-	(0.6)		(0.8)
Loss on disposal									15	(1.3)	(5.8)		(6.3)
Investment revenue										0.2	-		0.2
Finance costs									6	(6.9)	(5.6)		(12.7)
Profit for the period before tax									3	5.3	98.2		80.6
Tax									7	(19.6)	(43.9)		(56.2)
(Loss)/Profit for the period										(14.3)	54.3		24.4
(Loss)/Earnings per share (cents)									8
Basic										(3.3)	12.3		5.6
Diluted										(3.3)	12.3		5.4
Condensed consolidated statements of comprehensive income
										(unaudited) Six months ended	(unaudited) Six months ended		Year ended
										30 Jun 2023	30 Jun 2022		31 Dec 2022
								Notes		$ million	$ million		$ million
(Loss)/Profit for the period										(14.3)	54.3		24.4
Items that may be subsequently reclassified to profit or loss:
Fair value gain/(loss) arising on hedging instruments during the period										0.9	(24.2)		(18.9)
Less: Loss arising on hedging instruments reclassified to profit or loss							13			-	17.3		22.5
Total comprehensive (loss)/income for the period										(13.4)	47.4		28.0

 

The above condensed consolidated income statement and condensed consolidated statement of comprehensive income should be read in conjunction with the accompanying notes.

CONDENSED CONSOLIDATED Balance sheets
						(unaudited)	(unaudited)
						30 Jun 23	30 Jun 22	31 Dec 22
					Notes	$ million	$ million	$ million
Non-current assets
Intangible assets					9	21.6	14.3	16.5
Property, plant and equipment					10	347.9	432.0	381.0
Right-of-use assets					10	0.7	-	0.8
Other assets						56.4	58.2	59.1
						426.6	504.5	457.4
Current assets
Inventories						6.1	10.7	7.2
Trade and other receivables						62.6	72.1	60.9
Derivative financial instruments					13	0.3	-	-
Tax receivables						2.3	1.1	2.1
Cash and cash equivalents						35.9	47.5	45.3
						107.2	131.4	115.5
Total assets						533.8	635.9	572.9
Current liabilities
Trade and other payables						(19.2)	(15.2)	(12.9)
Derivative financial instruments					13	-	(14.9)	(1.1)
Borrowings					14	(33.1)	(35.3)	(39.6)
Lease Liabilities						(0.3)	-	(0.3)
Tax payables						(4.6)	(4.8)	(5.2)
						(57.2)	(70.2)	(59.1)
Net current assets						50.0	61.2	56.4
Non-current liabilities
Trade and other payables						(0.4)	(0.9)	(0.9)
Deferred tax liabilities						(90.4)	(106.4)	(92.9)
Borrowings					14	(20.9)	(48.0)	(34.6)
Lease Liabilities						(0.4)	-	(0.5)
Long term provisions						(52.9)	(57.4)	(54.3)
						(165.0)	(212.7)	(183.2)
Total liabilities						(222.2)	(282.9)	(242.3)
Net assets						311.6	353.0	330.6
Equity
Share capital						34.1	34.9	34.3
Share premium						58.0	58.0	58.0
Other reserves						254.4	242.5	253.6
Retained (deficit)/earnings						(34.9)	17.6	(15.3)
Total equity						311.6	353.0	330.6

 

 

The above condensed consolidated balance sheets should be read in conjunction with the accompanying notes.

 

 

CONDENSED consolidated STATEMENTs OF CHANGES IN EQUITY

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

 

 

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

 

 

							Called up share capital		Share Premium		Other reserves	Retained (deficit)/ earnings		Total
							$ million		$ million		$ million	$ million		$ million
As at 1 January 2022							34.9		58.0		250.5	(39.0)		304.4
Profit for the period							-		-		-	54.3		54.3
Other comprehensive loss							-		-		(6.9)	-		(6.9)
Share-based payments							-		-		1.2	-		1.2
Transfer relating to share-based payments							-		-		(2.3)	2.3		-
As at 30 June 2022 (unaudited)							34.9		58.0		242.51	17.6		353.0
Loss for the period							-		-		-	(29.9)		(29.9)
Other comprehensive income							-		-		10.5	-		10.5
Share buy back							(0.6)		-		0.6	(2.9)		(2.9)
Treasury share repurchased							-		-		(0.6)	-		(0.6)
Share-based payments							-		-		0.5	-		0.5
Transfer relating to share-based payments							-		-		0.1	(0.1)		-
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							(0.2)		-		0.2	(0.8)		(0.8)
Distributions							-		-		-	(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

 

condensed consolidated cash flow statements

 

						(unaudited) Six months ended	(unaudited) Six months ended	Year ended
						30 Jun 2023	30 Jun 2022	31 Dec 2022
					Notes	$ million	$ million	$ million
Net cash from operating activities					12	21.3	27.6	53.4
Investing activities
Purchase of intangible assets						(4.4)	(2.3)	(4.4)
Purchase of property, plant and equipment						(9.3)	(11.5)	(25.4)
Consideration in relation to farm out of Egyptian assets1					15	12.8	10.1	18.4
Assignment fee in relation to farm out of Egyptian assets					15	(0.5)	(0.5)	(0.5)
Payment to abandonment fund						(1.7)	(1.1)	(2.1)
Net cash used in investing activities						(3.1)	(5.3)	(14.0)
Financing activities
Proceeds from borrowings					14	1.9	7.5	16.7
Interest paid on borrowings					14	(3.7)	(2.4)	(6.0)
Repayment of borrowings					14	(23.8)	(6.7)	(27.1)
Lease payments						(0.2)	-	(0.1)
Share buy back						(0.8)	-	(2.9)
Share-based payments						-	0.1	(0.4)
Net cash used in financing activities						(26.6)	(1.5)	(19.8)
Net (decrease)/increase in cash and cash equivalents						(8.4)	20.8	19.6
Cash and cash equivalents at beginning of period						45.3	27.1	27.1
Effect of foreign exchange rate changes						(1.0)	(0.4)	(1.4)
Cash and cash equivalents at end of period						35.9	47.5	45.3

¹ During 2023 IPR, acting as operator and agent, was authorised to settle its operating liabilities of $3.4m (2022: $6.6m) and investing liabilities of $4.4m (2022: $8.8m) against the consideration due from the associated carry (Note 15) debtor amounting to $7.8m (2022: $15.4m). The Company has disclosed the underlying cash flows as operating, investing or financing according to their nature on the basis that, as a principal, the entity has the right to the cash inflows and/or the obligation to settle the liability and ensure clarity of disclosure of the operating cash costs of the business.

 

The above condensed consolidated cash flow statements should be read in conjunction with the accompanying notes.

Notes to the condensed consolidated financial statements

1.   General information

The information for the year ended 31 December 2022 does not constitute statutory accounts as defined in section 434 of the Companies Act 2006.  A copy of the statutory accounts for that year has been delivered to the Registrar of Companies.  The auditor's report on those accounts was not qualified, did not include a reference to any matters to which the auditors drew attention by way of emphasis without qualifying the report and did not contain statements under section 498(2) or (3) of the Companies Act 2006.

The half-year financial report is presented in US dollars because that is the currency of the primary economic environment in which the Group operates.

The half-year financial report for the six months ended 30 June 2023 was approved by the Directors on 12 September 2023.

 

2.   Significant accounting policies

The condensed set of financial statements included in this half year financial report has been prepared on a going concern basis of accounting for the reasons set out in the Financial Results section of this report and in accordance with United Kingdom adopted International Accounting Standard IAS 34 'Interim Financial Reporting', and the requirements of the UK Disclosure and Transparency Rules of the Financial Services Authority in the United Kingdom as applicable to interim financial reporting.

The accounting policies and methods of computation applied in the half-year financial report are consistent with the accounting policies disclosed in the Group's latest annual financial statements.

A number of judgements were taken in concluding that this basis of preparation was appropriate and that there were no material uncertainties in this regard. These included applying appropriate estimates of future production and oil price together with ensuring that the forecasts included all expenditure that was either committed or expected to be incurred in relation to estimated production volumes.

The interim report does not include all the notes of the type normally included in an annual financial report. Accordingly, this report is to be read in conjunction with the annual report for the year ended 31 December 2022 and any public announcements made by Pharos during the interim reporting period.

Going Concern

The Group closely monitors its liquidity risk. Cash forecasts are regularly produced, and stress tested for a number of scenarios including a downturn in the oil price, changes in production rates, operating costs and capital expenditure. Given the current rapid-changing global political and economic landscape, the fluctuating yet strengthening oil prices, and the persisting economic uncertainties with escalating inflation and interest rates, the scope of our scenario planning remains extensive. Accordingly, stress tests have been run for oil prices down to $56/bbl in November 2023, 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%, assumptions regarding payments in local currency, and the Egypt receivable balance building-up further. As at 30 June 2023, the Group had a cash balance of $35.9m and the forecasts show that the Group will have sufficient financial headroom for the period of 12 months from the date of approval of these half-year results.

The Directors therefore have a reasonable expectation that the Company has adequate resources to continue in operational existence for the foreseeable future. Thus, they continue to adopt the going concern basis of accounting in preparing these half-year results.

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 2023, but do not have an impact on the interim condensed consolidated financial statements of the Group.

IFRS 17 Insurance contracts

Definition of Accounting Estimates - Amendments to IAS 8

Disclosure of Accounting Policies - Amendments to IAS 1 and IFRS Practice Statement 2

Deferred Tax related to Assets and Liabilities arising from a Single Transaction - Amendments to IAS 12

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 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 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 (see Note 10)							(0.6)	(9.5)	-		(10.1)
Loss on disposal (see Note 15)							-	(1.3)	-		(1.3)
Profit/(Loss) before tax1							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

 

 

Six months ended 30 June 2022 (unaudited)							SE Asia	Egypt	Unallocated1		Group
							$ million	$ million	$ million		$ million
Oil and gas sales							103.8	25.83	-		129.6
Realised loss on commodity hedges (see Note 13)							-	-	(17.3)		(17.3)
Total Revenue							103.8	25.8	(17.3)		112.3
Depreciation, depletion and amortisation - oil and gas							(25.9)	(1.7)	-		(27.6)
Impairment charge - Intangibles							-	-	(0.1)		(0.1)
Impairment reversal - PP&E							38.4	24.5	-		62.9
Loss on disposal							-	(5.8)	-		(5.8)
Profit/(Loss) before tax1							91.7	35.3	(28.8)		98.2
Tax charge on operations (see Note 7)							(30.2)	-	-		(30.2)
Tax charge on impairment reversal (see Note 7)							(13.7)	-	-		(13.7)
Non-current assets2							365.1	81.2	-		446.3
Year end 31 December 2022							SE Asia	Egypt	Unallocated1		Group
							$ million	$ million	$ million		$ million
Oil and gas sales							184.8	36.8	-		221.6
Realised loss on commodity hedges							-	-	(22.5)		(22.5)
Total Revenue							184.8	36.8	(22.5)		199.1
Depreciation, depletion and amortisation - oil and gas							(51.0)	(4.1)	-		(55.1)
Depreciation, depletion and amortisation - other							-	(0.1)	-		(0.1)
Impairment reversal/(charge) - Intangibles4							1.0	-	(0.2)		0.8
Impairment reversal - PP&E							23.3	3.8	-		27.1
Loss on disposal (see Note 15)							-	(6.3)	-		(6.3)
Profit/(Loss) before tax1							108.3	16.9	(44.6)		80.6
Tax charge on operations (see Note 7)							(47.9)	-	-		(47.9)
Tax charge on impairment reversal (see Note 7)							(8.3)	-	-		(8.3)
Non-current assets2							332.5	65.8	-		398.3

 

¹ Unallocated amounts included in profit/(loss) before tax comprise corporate costs not attributable to an operating segment, investment and hedging revenue, other gains and losses and finance costs.

² Excludes other assets.

³ On 19 January 2022, the Third Amendment to the El Fayum Concession Agreement was signed by His Excellency Eng. Tarek El Molla (Minister of Petroleum & Mineral Resources of the Arab Republic of Egypt), EGPC and the Company.

Under the terms, the cost recovery percentage was increased from 30% to 40% allowing Pharos a significantly faster recovery of all its past and future investments. In return, Pharos agreed to waive its rights to recover a portion of the past costs pool ($115m) and reduce its share of Excess Cost Recovery Petroleum from 15% to 7.5%. While in full cost recovery mode, Contractor's share of revenue increases from 42.6% to 50.8% as from November 2020 (corresponding to additional net revenues to Contractor of $7.0m to 31 December 2021). ⁴ Includes $1.0m reversal of impairment of Block 125&126 tax receivable (other receivable - current), offset by $(0.2)m write-off of seismic costs relating to Israel exploration Zones A and C.

 

 

4.   Cost of sales

										(unaudited) six months ended 30 Jun 2023	(unaudited) six months ended 30 Jun 2022	Year ended 31 Dec 2022
										$ million	$ million	$ million
Depreciation, depletion and amortisation										29.9	27.6	55.1
Production based taxes										6.3	8.8	14.7
Export duty										-	3.2	3.2
Production operating costs										20.9	25.4	45.6
Inventories										1.1	(5.1)	(1.8)
										58.2	59.9	116.8

 

5.   Other/restructuring expense

(unaudited) six months ended 30 Jun 2023 (unaudited) six months ended 30 Jun 2022 Year ended 31 Dec 2022       $ million $ million $ million   Redundancy costs       - 0.1 0.1   Premium - lease transfer       - 0.5 0.7           - 0.6 0.8

2019

2018

 

6.   Finance Costs

(unaudited) six months ended 30 Jun 2023 (unaudited) six months ended 30 Jun 2022 Year ended 31 Dec 2022       $ million $ million $ million   Unwinding of discount on provisions                                                        1.0 0.5 1.3   Interest expense payable (see Note 14)                                      3.7 2.4 6.0   Adjustment and amortisation of capitalised borrowing costs (see Note 14) 1.7 2.0 4.1   Net foreign exchange losses   0.5 0.7 1.3           6.9 5.6 12.7

2019

2018

 

As at 30 June 2023, $1.0m relates to the unwinding of discount on the provisions for decommissioning (1H 2022: $0.5m). The provisions are based on the net present value of the Group's share of the expenditure which may be incurred at the end of the life of TGT and CNV (currently estimated to be 8-9 years) in the removal and decommissioning of the facilities currently in place.

Following the June 2023 redetermination and the $22.4m 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 2023, a charge of $2.3m (1H 2022: $0.7m; Dec 2022: $2.6m), offset by an amortisation adjustment of $(0.6)m (1H 2022: amortised cost of $1.3m; Dec 2022: amortised cost of $1.5m), was recognised in the income statement (see Note 14).

 

 

7.   Tax

									(unaudited) six months ended 30 Jun 2023	(unaudited) six months ended 30 Jun 2022	Year ended 31 Dec 2022
									$ million	$ million	$ million
Current tax									22.2	28.7	54.5
Deferred tax (credit)/charge on operations									(2.3)	1.5	(6.6)
Deferred tax (credit)/charge on impairment (charge)/reversal									(0.3)	13.7	8.3
Total tax charge									19.6	43.9	56.2

 

The Group's corporation tax is calculated at 50% (1H 2022: 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.

For CNV, a pre-tax impairment reversal in the amount of $10.6m has been reflected in the income statement with an associated deferred tax charge of $(4.0)m (1H 2022: pre-tax impairment reversal $13.6m, deferred tax charge of $(5.1)m). For TGT, a pre-tax impairment charge in the amount of $(11.2)m has been reflected in the income statement with an associated deferred tax credit of $4.3m (1H 2022: pre-tax impairment reversal $24.8m, deferred tax charge of $(8.6)m).

The charge for the year can be reconciled to the profit / (loss) per the income statement as follows:

(unaudited) six months ended 30 Jun 2023 $ million (unaudited) six months ended 30 Jun 2022 $ million Year ended 31 Dec 2022                     $ million Profit before tax 5.3 98.2 80.6 Profit before tax at 50% (2022: 50%) 2.6 49.1 40.3 Effects of:   Non-taxable income - (5.6) (3.3) Non-deductible expenses 6.5 4.7 5.6 Tax losses not recognised/(utilised) 10.5 (4.6) 13.8 Adjustments to tax charge in respect of previous periods - 0.3 (0.2) Tax charge for the period       19.6 43.9 56.2

2019

2018

 

The prevailing tax rate in Vietnam, where the Group produces oil and gas, is 50% (1H 2022: 50%). The tax charge in future periods may also be affected by the factors in the reconciliation above.

Non-taxable income principally relates to Vietnam impairment reversal of $nil (1H 2022: $(5.5)m), as the impact of the impairment reversal for CNV associated with the non-cost recovery pool offset the impairment charge recorded on TGT. Non-deductible expenses primarily relate to Vietnam DD&A charges for costs previously capitalised, which are non-deductible for Vietnamese tax purposes of $6.3 m (1H 2022: $3.3m). A further $0.2m (1H 2022: $1.4m) relates to non-deductible corporate costs including share scheme incentives.

Tax losses not recognised of $4.6m (1H 2022: $13.1m) 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 2022, this also includes the tax impact of realised hedging losses during the period. In addition, tax losses not recognised of $5.9m (1H 2022: $(17.7)m) relate to Egypt. During 1H 2022, Egypt concessions recorded a net profit before tax of $35.3m (profit after tax impact of $17.7m) 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.  

The Egypt concessions are subject to corporate income tax at the standard rate of 40.55%, however responsibility for payment of corporate income taxes falls upon EGPC on behalf of our local subsidiary Pharos El Fayum (PEF). The Group records a tax charge, with a corresponding increase in revenue, for the tax paid by EGPC on its behalf. However, this is only valid if PEF is in an historic profit making position and no such tax has been recorded this period.

 

8.   Earnings/(loss) per share

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

(unaudited) six months ended 30 Jun 2023 (unaudited) six months ended 30 Jun 2022 Year ended 31 Dec 2022       $ million $ million $ million   (Loss)/Profit for the purposes of basic (loss)/profit per share (14.3) 54.3 24.4   Effect of dilutive potential ordinary shares - Cash settled share awards and options (0.4) -   (0.3)   (Loss)/Profit for the purposes of diluted (loss)/profit per share (14.7) 54.3 24.1									2019			2018
(unaudited) six months ended 30 Jun 2023   (unaudited) six months ended 30 Jun 2022   Year ended 31 Dec 2022       $ million $ million $ million   Weighted average number of ordinary shares 429.5 441.7 439.3   Effect of dilutive potential ordinary shares - Share awards and options 1.7 0.5 0.9   Weighted average number of ordinary shares for the purpose of diluted (loss)/profit per share 431.2 442.2 440.2									2019			2018

 

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 $1.8m and Egypt $3.3m, of which $2.6m relates to North Beni Suef.

In June 2023, having reviewed the triggers for impairment, Management are of the view that none of the impairment indicators under IFRS 6 have been triggered and therefore no impairment testing is required for Vietnam or Egypt.

Whilst ongoing costs for exploration are therefore forecast and funds available for future exploration, there is insufficient certainty of full recovery to justify the reversal of the previous impairment charges in 2020. The accumulated impairment charges against exploration and evaluation expenditure at 30 June 2023 stands at $25.6m (30 June 2022: $25.5m). This will be kept under review as the exploration activity continues.

 

10.  Property, plant and equipment

As a result of previously recognised impairment losses, combined with the ongoing oil price volatility, economic uncertainty leading to an increase in inflation and discount rates, and movements in 2P reserves, we have tested each of our oil and gas producing properties for impairment. For each producing property, the recoverable amount has been determined using the value in use method derived from a discounted cash flow valuation of the 2P production profile. The results of these impairment tests are summarised below, as well as the key assumptions and sources of estimation uncertainty at the end of the reporting period.

 

Vietnam

The key assumptions to which the recoverable amount measurement is most sensitive are oil price, discount rate and 2P reserves (2022: oil price, discount rate and 2P reserves). As at 30 June 2023, the fair value of the assets are estimated based on a post-tax nominal discount rate of 12.7% (1H 2022: 13%) and a Brent oil price of $84.2/bbl in 2H 2023 down to $75.2/bbl in 2026 plus inflation of 2% thereafter (1H 2022: a Brent oil price of $107.6/bbl in 2H 2022 down to $77.0/bbl in 2025 plus inflation of 2% thereafter).

For CNV, a pre-tax impairment reversal in the amount of $10.6m has been reflected in the income statement with an associated deferred tax charge of $4.0m. As at 30 June 2023, the carrying amount of the CNV oil and gas producing property, after additions of $2.6m, changes in decommissioning asset $(2.3)m, DD&A $(6.8)m and impairment reversal of $10.6m, is $80.5m. It should be noted that the CNV impairment reversal at 30 June 2023 has been restricted to reflect the remaining balance of historic impairment charges previously recorded against the field. The impairment reversal test calculated net present value at a 12.7% discount rate of $45.2m which would have implied a pre-tax reversal of $11.6m, but this was restricted to $10.6m.

For TGT, a pre-tax impairment charge in the amount of $11.2m has been reflected in the income statement with an associated deferred tax credit of $4.3m. As at 30 June 2023, the carrying amount of the TGT oil and gas producing property, after additions of $0.7m, DD&A $(21.0)m and after impairment charge of $(11.2)m, is $210.9m.

Testing of sensitivity cases indicated that a $5/bbl reduction in long-term oil price used when determining the value in use method would result in post-tax impairment charges (compared to new Net Book Value, "NBV") of $24.3m on TGT. A 1% increase in discount rate would result in post-tax impairments of $10.3m on TGT.

We have also run sensitivities utilising the IEA (International Energy Agency) scenarios described as being consistent with achieving the COP26 agreement goal to reach net zero by 2050 (the "Net Zero price scenario"). The nominal Brent prices used in this scenario were as follows; 2023:$81.9/bbl, 2024:$80.8/bbl, 2025:$77.5/bbl, 2026:$71.2/bbl, 2027:$64.5/bbl, 2028:$57.5/bbl, 2029:$50.2/bbl. 2030:$42.7/bbl. Using these prices and a 12.7% discount rate would result in additional post-tax impairments of $27.2m on TGT.

For CNV, if these downside scenarios are applied, a $5/bbl reduction in long-term oil price, a 1% increase in discount rate and Net Zero price scenario, would result in a post-tax impairment reversal of $3.4m, $6.4m and $1.9m, respectively.

Egypt

The key assumptions to which the recoverable amount measurement is most sensitive are oil price, discount rate and 2P reserves (2022: oil price, discount rate and 2P reserves). As at 30 June 2023, the fair value of the asset is estimated based on a post-tax nominal discount rate of 17.2% (1H 2022: 15.1%) and a Brent oil price of $84.2/bbl in 2H 2023 down to $75.2/bbl in 2026 plus inflation of 2% thereafter (1H 2022: a Brent oil price of $107.6/bbl in 2H 2022 down to $77.0/bbl in 2025 plus inflation of 2% thereafter).

For Egypt, an impairment charge (pre and post tax) in the amount of $9.5m has been reflected in the income statement. As at 30 June 2023, the carrying amount of the Egypt oil and gas producing property, after additions of $5.8m, DD&A $(2.1)m and after the impairment charge of $(9.5)m, is $56.7m.

Testing of sensitivity cases indicated that a $5/bbl reduction in long term oil price used would result in an impairment of $17.1m (compared to new NBV). A 1% increase in discount rate would result in an impairment charge of $11.9m. We have also run a sensitivity using a 17.2% discount rate and the Net Zero price scenario which would result in an additional impairment of $41.7m.

Other considerations

It is not considered possible to provide separate summary sensitivities in relation to 2P reserves for any of the Group's oil and gas producing properties, as the impact of any changes in 2P reserves on recoverable amount would depend on a variety of factors, including the timing of changes in production profile and the consequential effect on the expenditure required to both develop and extract the reserves.

Other fixed assets ($0.5m) comprise office fixtures and fittings and computer equipment.

 

 

11.  Distribution to Shareholders

 

A final dividend of 1.00 pence per share was recommended by the Board in respect of the year ended 31 December 2022 and this was formally approved by the shareholders at the Company's 2023 AGM in May. The final dividend was paid in full on 12 July 2023 to shareholders on the register at the close of business on 16 June 2023.

In accordance with the dividend policy, the Board will declare an interim dividend of 33% of the previous year's final dividend, which will be payable to shareholders in January 2024.

 

12.  Reconciliation of operating profit to operating cash flows

									(unaudited) six months ended 30 Jun 2023	(unaudited) six months ended 30 Jun 2022	Year ended 31 Dec 2022
									$ million	$ million	$ million
Operating profit									13.3	110.2	100.2
Share-based payments									0.3	0.8	1.3
Depreciation, depletion and amortisation									30.0	27.6	55.2
Impairment charge/(reversal) - Intangibles									-	0.1	(0.8)
Impairment charge/(reversal) - PP&E									10.1	(62.9)	(27.1)
Operating cash flows before movements in working capital									53.7	75.8	128.8
Decrease/(increase) in inventories									1.1	(4.4)	(0.9)
Increase in receivables1									(11.7)	(10.4)	(7.7)
Increase/(decrease) in payables									0.3	(4.0)	(9.5)
Cash generated by operations									43.4	57.0	110.7
Interest received/(paid)									0.2	(0.1)	0.1
Other/redundancy expense outflow									-	(2.3)	(2.7)
Income taxes paid									(22.3)	(27.0)	(54.7)
Net cash from operating activities									21.3	27.6	53.4

 

¹ Includes $2.4m (1H 2022: $1.5m) increase in risk factor provision in respect of Egypt trade receivables.

During the six months ended 30 June 2023 a total of $0.7m (1H 2022: $4.3m) of trade receivables due from EGPC in Egypt were settled by way of non-cash offset, out of which $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 (1H 2022: $1.0m 3rd Amendment signature bonus, $2.0m Assignment bonus settled on behalf of the Farm out partner, IPR, $0.5m Group's share of NBS Concession assignment bonus and $0.8m set against trade payables, see Note 15).

13.  Hedge transactions

During 1H 2023, Pharos entered into different commodity (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 2024 and are settled monthly. The hedging positions in place at the balance sheet date cover 25% of the Group's forecast oil entitlement production until June 2024, securing a minimum floor price for this hedged volume of $63.00/bbl (1H 2022: cover was 30% of the Group's forecast oil entitlement production until June 2023, securing a minimum floor price for this hedged volume of $67.0/bbl).

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. For the period ended 30 June 2023, there were no realised gains or losses (1H 2022: loss of $17.3m). The outstanding unrealised gain on open positions as at 30 June 2023 amounts to $0.2m (1H 2022: loss of $11.3m).

The carrying amount of the zero collars are based on the fair value determined with the assistance of external advice. As all material inputs are observable, they are categorised within Level 2 in the fair value hierarchy. It is presented in "Derivative financial instruments" in the consolidated statement of financial position. The net receivable position as at June 2023 was $0.3m (1H 2022: liability position $14.9m of which $3.6m was realised).

Please see below for a summary of hedges outstanding as at 30 June 2023, which are all zero cost collar.

 

		3Q23	4Q23	1Q24	2Q24
Production hedge per quarter - 000/bbls	180		141	120	60
Average floor price of hedges - $/bbl	63.33		63.96	63.00	63.00
Average ceiling price of hedges - $/bbl	102.23		93.66	91.50	91.00

 

14.  Borrowings

Changes in liabilities arising from financing activities:

	(unaudited) six months ended 30 Jun 2023 $ million			(unaudited) six months ended 30 Jun 2022 $ million
	Credit      facility	RBL	Total Borrowings	Total Borrowings
Carrying value as of 1 January	9.2	65.0	74.2	80.5
Proceeds from Uncommitted Revolving credit facility	1.9	-	1.9	7.5
Repayments of borrowings	(1.4)	(22.4)	(23.8)	(6.7)
RBL modification charge and amortisation of capitalised borrowing costs (see Note 6)	-	1.7	1.7	2.0
Interest payable (see Note 6)	0.4	3.3	3.7	2.4
Interest paid during the year	(0.4)	(3.3)	(3.7)	(2.4)
Carrying value as of 30 June	9.7	44.3	54.0	83.3
Current	9.7	23.4	33.1	35.3
Non-current	-	20.9	20.9	48.0

 

Reserve Based Lending facility (RBL)

Discussions were finalised with the RBL banking group to amend the reference benchmark interest rate of USD LIBOR to the Secured Overnight Financing Rate (SOFR). The loan bears a per annum interest rate of Compound SOFR plus CAS (Credit Adjustment Spread) plus 5.25% effective from the next redetermination in December 2023. The change from LIBOR to SOFR did not have any impact on the 1H 2023 interim results.

The RBL is subject to a number of financial covenants, all of which have been complied with during the 1H 2023 and 2022 reporting periods.

The RBL is secured against the Group's producing assets in Vietnam.

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

In May 2023, the Group renegotiated the uncommitted revolving credit facility with National Bank of Egypt for discounting (with recourse) of up to $18m until 31 May 2024 (1H 2022: $18m).

The loan bears 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 will loan bears a per annum interest rate of Term SOFR plus CAS 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.  Loss on disposal

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 and completion date.

The carry decreases every month against the cash calls received from IPR. The total amount utilised as at 30 June 2023 amounts to $23.2m (2022: $15.4m). The movement during 1H 2023 was $7.8m, 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 $5.0m contingent consideration received on 1 June 2023). No cash outflow is required until we utilise the whole amount.

The Group is entitled to contingent consideration depending on the average Brent Price each year from 2022 to the end of 2025 (with floor and cap at $62/bbl and c.$90/bbl respectively). The contingent consideration is calculated yearly and is capped at a maximum total payment of $20.0m. On 1 June 2023, contingent consideration of $5.0m in respect of average Brent price during 2022 was received from IPR. As at 30 June 2023, the contingent consideration receivable amounts to $7.9m, $3.5m in current trade and other receivables and $4.4m in non-current other assets (2022: $13.9m, $5.0m in current trade and other receivables and $8.9m in non-current other assets). Testing of sensitivity for a $5/bbl reduction in long-term oil price used would result in $0.9m decrease in contingent consideration to $7.0m.

The loss on disposal has increased by $1.3m from $6.3m at 31 December 2022 to $7.6m at 30 June 2023. This is due to $0.4m reduction in the amount classified as the carry element from $36.3m to $35.9m following a change in the best estimate of the adjustment relating to the interim period between the economic date of 1 July 2020 and the completion date, $1.0m revision of the contingent consideration offset by $0.1m reduction in contingent liability (assignment fee).

As at 30 June 2023, $2.6m (2022: $3.7m) relates to the assignment fee for the sale of 55% of the Group's operated interest in each of our Egyptian Concessions, El Fayum and North Beni Suef, to IPR. $2.2m is booked as current other payable and $0.4m as non-current other payable. Following receipt of contingent consideration amounting to $5.0m an assignment bonus of $0.5m 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

There have been no significant events after the reporting period that require disclosure.

Non-IFRS measures

The Group uses certain measures of performance that are not specifically defined under IFRS or other generally accepted accounting principles. These non-IFRS measures include cash operating costs per barrel, DD&A per barrel, gearing and operating cash per share. For the RBL covenant compliance, three Non-IFRS measures are included: Net debt, EBITDAX and Net debt/EBITDAX.

Cash operating costs per barrel

Cash operating costs are defined as cost of sales less DD&A, production based taxes, movement in inventories and certain other immaterial cost of sales.

Cash operating costs for the period is then divided by barrels of oil equivalent produced. This is a useful indicator of cash operating costs incurred to produce oil and gas from the Group's producing assets.

									(unaudited) six months ended 30 Jun 23	(unaudited) six months ended 30 Jun 22	Year ended 31 Dec 22
									$ million	$ million	$ million
Cost of sales									58.2	59.9	116.8
Less:
Depreciation, depletion and amortisation									(29.9)	(27.6)	(55.1)
Production based taxes									(6.3)	(8.8)	(14.7)
Export duty									-	(3.2)	(3.2)
Inventories									(1.1)	5.1	1.8
Trade Receivable risk factor provision									(2.4)	(1.5)	(1.5)
Other cost of sales									(0.8)	(1.1)	(1.3)
Cash operating costs									17.7	22.8	42.8
Production (BOEPD)									6,915	7,962	7,166
Cash operating cost per BOE ($)									14.14	15.82	16.36

 

Cash operating costs per barrel by segment (1H 2023)

											Vietnam			Egypt			Total
											$ million			$ million			$ million
Cost of sales											49.4			8.8			58.2
Less:
Depreciation, depletion and amortisation											(27.8)		(2.1)				(29.9)
Production based taxes											(6.2)		(0.1)				(6.3)
Inventories											(1.3)		0.2				(1.1)
Trade Receivable risk factor provision											-		(2.4)				(2.4)
Other cost of sales											(0.7)		(0.1)				(0.8)
Cash operating cost											13.4			4.3			17.7
Production (BOEPD)											5,566			1,349			6,915
Cash operating cost per BOE ($)											13.30			17.61			14.14

 

 

Vietnam									(unaudited) six months ended 30 Jun 23	(unaudited) six months ended 30 Jun 22
									$ million	$ million
Cost of sales									49.4	50.0
Less:
Depreciation, depletion and amortisation									(27.8)	(25.9)
Production based taxes									(6.2)	(8.7)
Export duty									-	(3.2)
Inventories									(1.3)	5.1
Other cost of sales									(0.7)	(0.8)
Cash operating costs									13.4	16.5
Production (BOEPD)									5,566	5,861
Cash operating cost per BOE ($)									13.30	15.55

 

Egypt									(unaudited) six months ended 30 Jun 23	(unaudited) six months ended 30 Jun 22
									$ million	$ million
Cost of sales									8.8	9.9
Less:
Depreciation, depletion and amortisation									(2.1)	(1.7)
Production based taxes									(0.1)	(0.1)
Inventories									0.2	-
Trade Receivable risk factor provision									(2.4)	(1.5)
Other cost of sales									(0.1)	(0.3)
Cash operating costs									4.3	6.3
Production (BOEPD)									1,349	2,1011
Cash operating cost per BOE ($)									17.61	16.57

 

¹ From 21 March 2022 includes 45% Pharos share of production; 1H 2022 100% production: 3,142 boepd

 

 

DD&A per barrel

DD&A per barrel is calculated as net book value of oil and gas assets in production, together with estimated future development costs over the remaining 2P reserves. This is a useful indicator of ongoing rates of depreciation and amortisation of the Group's producing assets.

									(unaudited) six months ended 30 Jun 23	(unaudited) six months ended 30 Jun 22	Year ended 31 Dec 22
									$ million	$ million	$ million
Depreciation, depletion and amortisation									(29.9)	(27.6)	(55.1)
Production (BOEPD)									6,915	7,962	7,166
DD&A per BOE ($)									23.89	19.15	21.07

 

DD&A per barrel by segment (1H 2023)

									Vietnam		Egypt		Total
									$ million		$ million		$ million
Depreciation, depletion and amortisation									(27.8)		(2.1)		(29.9)
Production (BOEPD)									5,566		1,349		6,915
DD&A per BOE ($)									27.59		8.60		23.89

 

Vietnam									(unaudited) six months ended 30 Jun 23	(unaudited) six months ended 30 Jun 22
									$ million	$ million
Depreciation, depletion and amortisation									(27.8)	(25.9)
Production (BOEPD)									5,566	5,861
DD&A per BOE ($)									27.59	24.41

 

Egypt									(unaudited) six months ended 30 Jun 23	(unaudited) six months ended 30 Jun 22
									$ million	$ million
Depreciation, depletion and amortisation									(2.1)	(1.7)
Production (BOEPD)									1,349	2,101
DD&A per BOE ($)									8.60	4.47

 

 

 

 

 

Net Debt

Net debt comprises interest-bearing bank loans, less cash and cash equivalents.

									(unaudited) six months ended 30 Jun 23	(unaudited) six months ended 30 Jun 22	Year ended 31 Dec 22
									$ million	$ million	$ million
Cash and cash equivalents									35.9	47.5	45.3
Borrowings*									(52.3)	(85.4)	(74.2)
Net Debt									(16.4)	(37.9)	(28.9)

 

*Excludes unamortised capitalised set-up costs

 

EBITDAX

EBITDAX is earnings from continuing activities before interest, tax, DD&A, impairment (reversal)/charge of PP&E and intangibles, loss on disposal and exploration expenditure.

									(unaudited) six months ended 30 Jun 23	(unaudited) six months ended 30 Jun 22	Year ended 31 Dec 22
									$ million	$ million	$ million
Operating profit									13.3	110.2	100.2
Depreciation, depletion and amortisation									30.0	27.6	55.2
Impairment reversal/(charge)									10.1	(62.8)	(27.9)
EBITDAX									53.4	75.0	127.5

 

Net Debt/EBITDAX

Net Debt/EBITDAX ratio expresses how many years it would take to repay the debt, if net debt and EBITDAX stay constant.

									(unaudited) six months ended 30 Jun 23	(unaudited) six months ended 30 Jun 22	Year ended 31 Dec 22
									$ million	$ million	$ million
Net Debt									(16.4)	(37.9)	(28.9)
EBITDAX									53.4	75.0	127.5
Net Debt/EBITDAX									(0.31)	(0.51)	(0.23)

 

 

Gearing

Debt to equity ratio is calculated by dividing interest-bearing bank loans by stockholder's equity. The debt to equity ratio expresses the relationship between external equity (liabilities) and internal equity (stockholder's equity).

									(unaudited) six months ended 30 Jun 23	(unaudited) six months ended 30 Jun 22	Year ended 31 Dec 22
									$ million	$ million	$ million
Total Debt									52.3	85.4	74.2
Total Equity									311.6	353.0	330.6
Debt to Equity									0.17	0.24	0.22

 

 

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 23	(unaudited) six months ended 30 Jun 22	Year ended 31 Dec 22
									$ million	$ million	$ million
Net cash from continuing operating activities									21.3	27.6	53.4
Weighted number of shares in the year									439,346,597	441,743,462	439,253,641
Operating cash per share									0.05	0.06	0.12

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 23	(unaudited) six months ended 30 Jun 22	Year ended 31 Dec 22
									$ million	$ million	$ million
Operating profit									13.3	110.2	100.2
Impairment charge									20.7	0.1	0.2
Impairment reversal									(10.6)	(62.9)	(28.1)
Operating profit excluding impairment (reversal)/charge									23.4	47.4	72.3

 

 

 

 

 

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

COS

Geological chance of success

CPR

Competent Persons Report

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

ERCE

ERC Equipoise Limited, an independent technical and commercial evaluation and consultancy company

FPSO

Floating production, storage and offloading vessel

Group

Pharos and its direct and indirect subsidiary undertakings

HLJOC

Hoang Long Joint Operating Company, the operator of TGT

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

km

Kilometre

km²

Square kilometre

m

Million

mmbbl

Million barrels

mmboe

Million barrels of oil equivalent

Mmstb

Million stock tank barrel (42 US gallons measured at 14.7 pounds per square inch and 60 degrees Fahrenheit)

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 Contractor parties (being the Pharos Group and IPR Lake Qarun) and EGPC

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

Share

Ordinary Shares

TGT

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

$ or USD

United States Dollar

1U

Denotes the unrisked low estimate qualifying as prospective resources

3U

Denotes the unrisked high estimate qualifying as prospective resources.