14 September 2022

Pharos Energy plc

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

Interim results for the Half-year to 30 June 2022

Pharos Energy plc, an independent oil and gas exploration and production company, announces its interim results for the six months ended 30 June 2022. An analyst conference call will take place at 11.00 BST today.

 

Jann Brown, Chief Executive Officer, commented:

"Our results for this half year underscore the cash generation potential of our portfolio of assets, with operating cash flow of $27.6m achieved. In Vietnam, further development drilling on both TGT and CNV is due to commence imminently, with the rig on location and preparing to spud. In Egypt, a rig on long-term contract has been secured and is due to arrive in Q4 to continue the development drilling programme. These activities are set to add to production levels and cash flow in H2 and beyond.

We continue to focus our efforts on driving efficiencies, controlling costs and making judicious investments to maximise the value of our portfolio. The share buyback programme, which we announced in July, continues as part of the Company's broader strategy to deliver value to our shareholders and is expected to run for a further four to six months.

Pharos is now in a materially improved financial position, has an accelerating programme in Egypt and significant growth potential in Vietnam. Together, these put us in a strong position and I am pleased to be able to reward shareholder patience with the announcement of a return to a regular dividend, based on operating cash flow, with the first payment set for 2023. With our strengthened balance sheet, a portfolio of cash generative assets with substantial upside in both near term developments and exploration potential plus a commitment to capital discipline, we are well placed to create sustainable shareholder value."

 

Corporate Highlights                                                                                                                                                        

·    Signature of the Third Amendment to the El Fayum Concession Agreement in January 2022, increasing Contractor's share of revenue from c.42% to c.50%

·      Completion of farm-out transaction and transfer of operatorship of Egyptian assets to IPR in March 2022, delivering Pharos a 45% carry over its remaining interest

·      Reshaping of Board structure and composition from 9 to 6 Board members

·      Initiation of share buyback programme in July 2022, of which $1.6m has now been used

·      Commitment to achieve Net Zero GHG emissions from all our assets by no later than 2050 announced today

·     Establishment of an Emissions Management Fund, under which we will set aside $0.25 for each barrel sold at an oil price above $75/bbl to support emissions management projects

 

Operational Highlights

·     Group working interest production 7,962 boepd net (1H 2021: 9,147 boepd) in line with full year guidance

·      Vietnam

-       Production 5,861 boepd net (1H 2021: 5,429 boepd net)

-       Drilling of first of two TGT development wells due to commence

-       Work on submission of TGT & CNV licence extension requests progressing within the JOCs

-       Work ongoing to progress well planning and to secure a partner before drilling the commitment well on Block 125 in 2023

·      Egypt

-       Production 2,101 bopd^* (1H 2021: 3,718 bopd)

-       Development activities continues in El Fayum, targeting recovery of c.17 Mbbl 2P

-       Four wells on production in the period

-       Drilling rig secured on long-term contract

-       North Beni Suef (NBS) first exploration commitment well planned for Q4 2022  

 

 

Financial Highlights

·      Group revenue $129.6m^** prior to hedging losses of $17.3m (1H 2021: $72.9m^** prior to hedging losses of $13.7m)

·     Net profit of $54.3m (1H 2021: $6.4m profit), including non-cash impairment reversal after tax of $49.2m (1H 2021: impairment reversal after tax $19.4m)

·      Cash generated from operations $57.0m¹ (1H 2021: $18.2m)¹

·      Operating cash flow $27.6m⁴  (1H 2021: 0.1m)

·      Cash operating costs $15.82/bbl² (1H 2021: $14.74/bbl)² 

·      Cash balances as at 30 June 2022 of $47.5m (30 June 2021: $28.4m)

·      Forecast cash capex for the full year c.$29m of which $14.9m had been incurred by 30 June 2022

·      Net debt as at 30 June 2022 of $37.9m^2,3 (30 June 2021: $32.9m)²

·      Net debt to EBITDAX of 0.51x ² (1H 2021: 1.26x) ²

 

^* The farm-out transaction and transfer of operatorship of Pharos' Egyptian assets to IPR completed on 21 March 2022. Working interest production for Egypt is therefore reported as 100% through to completion and 45% thereafter

^** Egyptian revenues are given post government take including corporate taxes

¹ Stated after realised hedging loss of $17.3m (1H 2021:  loss of $13.7m)

² See Non-IFRS measures at page 32

³ Includes RBL and National Bank of Egypt working capital drawdown

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

 

 

Outlook

·      2022 full year Group working interest production guidance remains unchanged at 6,350 - 7,800 boepd net

·      Vietnam

-       2022 production guidance range unchanged at 5,000 - 6,000 boepd net

-       Three well drilling programme, including  two development wells at TGT and one development well at CNV, is on track to commence with the rig on location at TGT

-       Work ongoing to progress well planning, with discussions ongoing to secure a partner ahead of drilling the commitment well on Block 125 in 2023

·      Egypt

-       2022 production guidance range unchanged at 1,350 - 1,800 bopd (equivalent to gross production of 3,000 - 4,000 bopd)

-       Rig secured on a long-term contract due to start in mid-October 2022, focusing on ramping up activities in El Fayum from developed resource base

-       Progressing work on conventional and unconventional exploration prospects to further enhance the value of our acreage

-       NBS commitment well due to be drilled in Q4 2022

-       Request for an extension to the NBS exploration period has been submitted to EGPC

·      Net Zero commitment on all assets by 2050, detailed roadmap coming in 2023

·     Recommending recommencement of regular dividend payments starting in 2023, subject to shareholder approval at AGM 2023, returning no less than 10% of Operating Cash Flow (OCF)

 

 

 

 

 

 

Enquiries

Pharos Energy plc                                                                                                                                   Tel: 020 7747 2000

Jann Brown, Chief Executive Officer      

Sue Rivett, Chief Financial Officer  

 

Camarco                                                                                                                                                 Tel: 020 3757 4980

Billy Clegg | Georgia Edmonds | Rebecca Waterworth

 

Notes to editors

Pharos Energy plc is an independent oil and gas exploration and production company with a focus on sustainable growth and returns to stakeholders, which is listed on the London Stock Exchange. Pharos has production, development and/or exploration interests in Egypt, Vietnam and Israel. In Egypt, Pharos holds a 45% working interest share in the El Fayum Concession in the Western Desert, with IPR Lake Qarun, part of the international integrated energy business IPR Energy Group, holding the remaining 55% working interest. The El Fayum Concession produces oil from 10 fields and is located 80 km southwest of Cairo. It is operated by Petrosilah, a 50/50 joint stock company between the contractor parties (being IPR Lake Qarun and Pharos) and the Egyptian General Petroleum Corporation (EGPC). Pharos also holds a 45% working interest share in the North Beni Suef (NBS) Concession in Egypt, which is located immediately south of the El Fayum Concession. IPR Lake Qarun operates and holds the remaining 55% working interest in the NBS Concession. In Vietnam, Pharos has a 30.5% working interest in Block 16-1 which contains 97% of the Te Giac Trang (TGT) field and is operated by the Hoang Long Joint Operating Company. Pharos' unitised interest in the TGT field is 29.7%. Pharos also has a 25% working interest in the Ca Ngu Vang (CNV) field located in Block 9-2, which is operated by the Hoan Vu Joint Operating Company. Blocks 16-1 and 9-2 are located in the shallow water Cuu Long Basin, offshore southern Vietnam. Pharos also holds a 70% interest in, and is designated operator of, Blocks 125 & 126, located in the moderate to deep water Phu Khanh Basin, north east of the Cuu Long Basin, offshore central Vietnam. In July 2022 Capricorn, Ratio and Pharos reached agreement to relinquish the Israeli licences, and Capricorn as operator has informed the Israeli Ministry of Energy of the parties' intention.

 

Operational Review

Vietnam

Vietnam Production

Production for the first half of 2022 from the TGT and CNV fields net to the Group's working interest averaged 5,861 boepd (1H 2021: 5,429 boepd), in line with our previously published guidance of 5,000-6,000 boepd.

 

TGT 1H 2022 production averaged 15,133 boepd gross and 4,490 boepd net to Pharos (1H 2021: 13,401 boepd gross and 3,976 boepd net). CNV 1H 2022 production averaged 5,483 boepd gross and 1,371 boepd net to Pharos (1H 2021: 5,813 boepd gross and 1,453 boepd net).

 

Vietnam Development and Operations.  

Velesto's Naga 3 rig has been contracted for this year's drilling program, which includes the two development wells at TGT and one CNV well.

On Block 16-1 - TGT Field, the drilling programme for two development wells in H2 2022 is due to commence with the rig on location at TGT.

 

On Block 9-2 - CNV Field, one development well is planned in H2 2022. The revised field development plan, including the additional well, was approved by the Vietnam Ministry of Industry and Trade on 19 April 2022.

 

Work on the submission of licence extension requests for both TGT & CNV is progressing within the JOCs.

 

Vietnam Exploration

On Block 125, the 3D seismic processing is substantially complete and the ongoing interpretation of this data has resulted in the mapping of a variety of interesting Leads in this relatively unexplored basin, with further work needed to refine them into Prospect sizes pre-drill. Well location(s) will be presented to the Management Committee in December 2022. Well planning has started to meet the timeline of drilling in H2 2023, and we are already in discussions with a number of parties interested in farming in to support the funding of this commitment well.

 

Vietnam outlook & operational focus for remainder of 2022  

 

·      Vietnam

-       2022 production guidance range remains unchanged at 5,000 - 6,000 boped net.

-       Three well drilling programme, including two development wells at TGT and one development well at CNV, is on track to commence with the rig on location at TGT

-       Work ongoing to progress well planning and to secure a partner before drilling the commitment well on Block 125 in 2023.

Egypt

El Fayum Production

The transaction with IPR and transfer of operatorship completed on 21 March 2022. Working interest production is therefore reported as 100% through to completion of the farm-out and 45% thereafter.

Production for the first half of 2022 from El Fayum averaged 3,142 bopd gross (1H 2021: 3,718 bopd) and 2,101 bopd net to Pharos.

El Fayum Development and Operations 

The multi-well development drilling in El Fayum continues. Four wells have been put on production in the period to 30 June 2022 (including one well drilled in 2021), two more wells drilled after 30 June 2022 are currently being completed, and two to three additional wells are planned before year end, subject to rig scheduling. IPR is focusing on ramping up drilling and workover activities, focusing on waterflood implementation and securing long-lead items to minimize supply chain interruption.

 

Petrosilah, the El Fayum joint operating company (JOC), secured a rig on a long-term contract in July, one year firm plus an option for a second year, starting in mid-October 2022. The new rig will allow a continuous drilling campaign which is essential to adding new barrels to production as well as providing a stable platform for additional drilling activities.  

 

The rig currently in use will be released some time in Q4 2022, allowing a short time of overlap between the two rigs.

In addition, one workover rig continues to contribute to production through low-cost well repairs and recompletions and a second workover rig will be added in Q4 2022.

 

North Beni Suef (NBS)

Planning for the commitment well due to be drilled in Q4 2022 is advancing, and the request for a short extension to the exploration period has been submitted to EGPC. This extension will give us additional time to drill high-ranked prospects, including all work programme commitments. Several prospects have been identified from the existing 3D seismic and c.110 km² of additional 3D seismic is planned to be acquired in Q1 2023.

 

 

Egypt outlook & operational focus for remainder of 2022

 

·      Egypt

-       2022 production guidance unchanged at 1,350-1,800 bopd, equivalent to gross production of 3,000-4,000 bopd

-       Rig secured on a long-term contract due to start in mid-October 2022, focusing on ramping up activities in El Fayum from developed resource base

-       Progressing work on conventional and unconventional exploration prospects to further enhance the value of our acreage

-       NBS commitment well due to be drilled in Q4 2022

-       Request for an extension to the NBS exploration period has been submitted to EGPC

 

Israel

Following completion of the seismic processing in order to mature prospectivity ahead of a drilling decision, Capricorn as the operator along with the JV partners, has informed the Ministry of Energy of the JV's intention to relinquish the licences.

 

Health, Safety & ESG

Health and Safety

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

We are pleased to report that in Egypt and Vietnam, we have worked with our partners to maintain our record of zero Lost Time Injury (LTI) frequency rate through the first half of 2022. Unfortunately, there were two recent incidents involving sub-contractors that occurred in Q3 2022 and which are under investigation.       

 

ESG

The management of our Greenhouse Gas (GHG) Emissions remains a key issue for the Group. We continue our journey to implementing the TCFD recommendations and, during the first half of 2022, Pharos carried out physical climate and transition risk analyses to identify risks / opportunities for the business under different climate scenarios and pathways.

 

Today, we formalise our commitment to achieve Net Zero Scope 1 and Scope 2 GHG emissions from our assets by no later than 2050. Further details of this commitment can be found in the Corporate Review section on page 13.                                                                                                                                                                                                                               

 

Social Engagement

Pharos remains committed to creating value in a sustainable manner for host countries and local communities. We continue to invest in long-term social projects through the HLHVJOC Charitable Donation programme. For 2022, 11 charitable projects have been approved, ranging from providing healthcare and educational support for children with disabilities to supporting local communities in areas hit hardest by flash flooding and COVID-19, with 4 projects already completed in H1 2022 and 7 more to be completed in the latter half of the year. In Q1 2022, the Group provided financial support to help children unfortunately orphaned by the COVID-19 pandemic. In Q2 2022, the Donation programme helped fund the physical improvement education programme for children with disabilities. We work closely with our local and joint venture partners and joint ventures in order to make sure that our social initiatives bring positive impacts to the region, and will keep stakeholders updated on progress.

 

Principal and Emerging risks and Uncertainties for the second half of 2022

The Board continues to fulfil its role in risk oversight by developing policies and procedures around risks that are consistent with the organization's strategy and risk appetite, taking steps to foster risk awareness and encouraging a company culture of risk adjusting awareness throughout the Group.

The Group risk management activity in H1 2022 focused on the ramifications of the ongoing war in Ukraine with increased uncertainties and volatilities on world commodity markets and the ensuing Western sanctions on Russia and vice versa which have negatively impacted on the recoveries of many economies, particularly Egypt. This activity has included the formation of a dedicated cross-functional working group, regular risk management reporting and the adoption of a new Group sanctions policy. At an operational level, the Group has closely worked with JOCs to develop contingency planning in a number of hypothetical scenarios. The key principal and emerging risks are:

§  Prolonged War in Ukraine / ensuing sanctions*

§  Risks of rising inflation and stagflation*

§  Inability to repatriate cash earned from Egypt*

§  Further devaluation of the Egyptian pound*

§  Legal risks - Sanctions related*

§  Vietnam Licence Extension*

§  Farm in for 125/126*

§  Climate Change

§  Commodity Price volatility

§  Volatility in Production level

§  HSES

§  Partners' alignment

§  Sub-optimal capital allocation

§  Political and Regional

 

*New/emerging risks identified at HY 2022.

 

Financial Review

Finance strategy

Our finance strategy continues to underpin the Group's business model and goes hand in hand with our commitment to building shareholder value through capital growth and sustainable dividends. Following recommencement of investment in Vietnam during 2021 and the additional liquidity provided by our farm-in partner in Egypt after successful completion of the transaction with IPR in March 2022, supported by the improved oil prices, we are on track to deliver strong positive cash flow generation and growth in value in 2022.

 

 

Highlights

	1H 2022	1H 2021
Production Volumes (boepd)	7,962	9,147
Production Volumes - Vietnam (boepd)	5,861	5,429
Production Volumes  - Egypt (boepd)3	2,101	3,718
Oil Price Realised ($/bbl)	109.47	64.76
Oil & Gas Price Realised ($/boe)	99.49	57.47
Oil & Gas Sales ($m)	129.6	72.9
Total Revenue ($m)1	112.3	59.2
Gross Profit ($m)	52.4	7.7
Operating profit ($m)	110.2	30.0
Operating profit excluding impairment (reversal)/charge ($m)²	47.4	2.2
Cash operating cost per ($/boe)2	15.82	14.74
Net debt ($/m)2	37.9	32.9
EBITDAX ($/m)2	75.0	26.1
Gearing2	0.24	0.20

¹ Stated after realised hedging loss of $17.3m (1H 2021: loss of $13.7m) 

² See Non-IFRS measures at page 32

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

 

Cash operating cost per barrel*	1H 2022 $m	1H 2021 $m
Cost of sales	59.9	51.5
Less
Depreciation, depletion and amortisation	(27.6)	(23.6)
Production based taxes	(8.8)	(4.4)
Export duty	(3.2)	-
Inventories	5.1	1.7
Other cost of sales	(1.1)	(0.8)
Trade Receivable risk factor provision	(1.5)	-
Cash operating costs	22.8	24.4
Production (BOEPD)	7,962	9,147
Cash operating cost per BOE ($)	15.82	14.74

 

 

Cash operating cost per barrel by Segment	Vietnam     $m	Egypt Up to 20/03/22 1   $m	Egypt From 21/03/22 to 30/06/22 1 $m	Egypt Total   $m	Total     $m
Cost of sales	50.0	4.9	5.0	9.9	59.9
Less
Depreciation, depletion and amortisation	(25.9)	(0.6)	(1.1)	(1.7)	(27.6)
Production based taxes	(8.7)	(0.0)	(0.1)	(0.1)	(8.8)
Export duty	(3.2)	-	-	-	(3.2)
Inventories	5.1	-	-	-	5.1
Other cost of sales	(0.8)	(0.2)	(0.1)	(0.3)	(1.1)
Trade Receivable risk factor provision	-	(0.5)	(1.0)	(1.5)	(1.5)
Cash operating costs	16.5	3.6	2.7	6.3	22.8
Production (BOEPD)	5,861	2,857	1,513	2,101	7,962
Cash operating cost per BOE ($)	15.55	15.94	17.31	16.57	15.82

 

¹ movements from 1 January 2022 up to 20/03/22 are 100% share and from 21/03/22 includes 45% Pharos share. 100% cash operating costs for period from 21/03/22 to 30/06/22 amounts to $6.0m and 100% Cash operating cost per BOE is $17.49.

Cash flows and accounting for Egypt

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

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

Pharos owned and managed the business up to completion.  On completion an adjustment to compensate IPR for 55% of net cash flows, revenue offset by costs since the effective date has been adjusted for in the level of carry to be provided by IPR to Pharos.

In the financial statements, for the period post completion, Pharos' 45% share of field costs - capex, opex and G&A - are accounted for as incurred by Pharos, although all such costs are paid by IPR and set off against the carry. Please see Note 15 on page 30 for more details on the disposal of asset held for sale. 

All revenues earned are paid direct to Pharos. 

 

Operating Performance

Revenue

Oil & gas sales for the period were up 78% to $129.6m (1H 2021: $72.9m). The Group revenues in the period were reduced by hedging losses of $17.3m (1H 2021: $13.7m losses).

Revenue for Vietnam increased 84% to $103.8m (1H 2021: $56.3m). The average realised crude oil price was $111.50/bbl (1H 2021: $66.47/bbl), a 68% increase. The premium to Brent increased marginally, representing just over $3/bbl (1H 2021: $2/bbl). Production increased from 5,429 boepd to 5,861 boepd.

The increased revenue for Egypt of $25.8m (1H 2021: $16.6m) in part was as a result of invoicing for an additional $7m following approval of the third amendment to the El Fayum Concession agreement which increased the cost recovery from 30% to 40% from November 2020. The higher average realised crude oil price, up 67% to $99.57/bbl (1H 2021: $59.70/bbl), was offset by lower average production levels, from 3,718 bopd to 2,101 bopd (from 21 March 2022 includes 45% Pharos share of production; 1H 2022 100% production 3,142). There are two discounts applied to the El Fayum crude production - a general Western Desert Discount and one related specifically to El Fayum. Both are set by EGPC (the in-country regulator) and combined increased marginally to nearly $6/bbl (1H 2021: $5/bbl).

 

Group operating costs, DD&A and expenses

Cash operating costs at Group level, defined in the Non-IFRS measures section on page 32, amounted to $22.8m (1H 2021: $24.4m) a 7% decrease over the same period last year. On a barrel of oil equivalent basis, this was $15.82/boe (1H 2021: $14.74/boe).

Cash operating costs in Vietnam increased to $16.5m (1H 2021: $15.3m) in the period which equates to $15.55/bbl (1H 2021: $15.57/bbl). The increase is due to higher costs relating to the FPSO as a result of lower TLJOC production (TLJOC has 11.5% cost share in 1H 2022 compared to 27.5% in 1H 2021) throughput which increased Pharos' share of the costs.

Cash operating costs in Egypt were $6.3m (1H 2021: $9.1m) in the period, which equate to $16.57/bbl (1H 2021: $13.52/bbl). Cash operating costs from 1 January 2022 up to 20/03/22 are 100% share and from 21/03/22 includes 45% Pharos share. The increase in cash operating costs relates largely to higher variable cost as a result of an upsurge in the fuel price offset by the devaluation of EGP against the US dollar in comparison to 1H 2021.

DD&A charges on production and development assets increased to $27.6m (1H 2021: $23.6m), driven by higher production from Vietnam combined with a higher depreciating cost base following 2021 impairment reversals taken on both Vietnam and Egypt. DD&A per bbl is currently $19.15/boe (1H 2021: $14.25/boe).

Administrative expenses of $5.0m (1H 2021: $5.5m) are lower than the comparative period due to the restructuring that took place in 2021. After adjusting for the non-cash items such as depreciation and IFRS 2 Share Based Payments of $0.9m (1H 2021: $1.5m), the administrative expense is $4.1m (2021: $4.0m). Following completion of the farm down to IPR in March and the AGM in May the Board was reduced from 9 to 6. The remaining non-executives' fees were restated to the levels prior to the reductions taken during 2020 and 2021. As previously noted in the 2021 Annual Report & Accounts, the incoming CEO took a 21% reduction in base salary on assuming the role. 

 

Impairment Reversals

 

As a result of ongoing oil price volatility and movements in 2P reserves, we have tested each of our oil and gas producing properties for impairment.  The results of these impairment tests are summarised below. For each producing property, the recoverable amount has been determined using the value in use method which constitutes a level 3 valuation within the fair value hierarchy. The recoverable amount is supported by the fair value derived from a discounted cash flow valuation of the 2P production profile.

Summary of Impairments  - Oil and Gas properties	TGT $m	CNV $m	Egypt $m	Total $m
1H 2022
Pre-tax impairment reversal	24.8	13.6	24.5	62.9
Deferred tax charge	(8.6)	(5.1)	-	(13.7)
Post-tax impairment reversal	16.2	8.5	24.5	49.2
Reconciliation of carrying amount: 1
As at 1 Jan 2022	266.0	84.2	49.2	399.4
Additions	0.5	0.2	6.7	7.4
Changes in decommissioning asset 2	(8.7)	(1.7)	-	(10.4)
DD&A	(20.6)	(5.3)	(1.7)	(27.6)
Impairment reversal	24.8	13.6	24.5	62.9
As at 30 Jun 2022	262.0	91.0	78.7	431.7
1H 2021
Pre-tax impairment reversal	21.9	2.2	3.7	27.8
Deferred tax charge	(7.6)	(0.8)	-	(8.4)
Post-tax impairment reversal	14.3	1.4	3.7	19.4
Reconciliation of carrying amount: 1
As at 1 Jan 2021	239.3	91.2	104.1	434.6
Additions	0.7	0.2	3.3	4.2
Changes in decommissioning asset 2	(2.7)	(0.9)	-	(3.6)
DD&A	(14.4)	(5.0)	(4.2)	(23.6)
Impairment reversal	21.9	2.2	3.7	27.8
As at 30 Jun 2021	244.8	87.7	106.9	439.4

 

¹ Egypt carrying value reflects 45% share (1H 2021: 100%).

² Changes in decommissioning asset for TGT is due to changes in discount rate and the field abandonment plan, whereas CNV reflects the change in discount rate only (1H 2021: change in discount rate only for both TGT and CNV)

It should be noted that the TGT impairment reversal at 1H 2022 has been restricted to reflect the remaining balance of historic impairment charges previously recorded against the field. The impairment reversal test calculated NPV13 of $218.9m which would have been a pre-tax reversal of $67.2m, but this was restricted to $24.8m. Further details of these impairment charges, including key assumptions in relation to oil price and discount rate are provided in Note 10 of the interim financial statements.

 

Hedging

Our hedging positions for the period resulted in a realised loss of $17.3m (1H 2021: loss of $13.7m) as the Brent price improved from $73 to $123 during 1H 2022. Additionally, the fair value as at 30 June 2022 was an unrealised loss of $11.3m for the remaining hedges in place (1H 2021: unrealised loss of $12.4m). The Group is required to hedge 35% of the RBL Vietnam production as part of the agreement. Approximately 30% of the Group's forecast production representing 36% of Vietnam's production until June 2023, is hedged at an average price of $67.0/bbl (1H 2021: cover was 27% of the Group's forecast production and 37% of Vietnam's production from July 2021 to June 2022 securing a minimum price for this hedged volume of $55.6/bbl).

Please see below a summary of hedges outstanding as at 30 June 2022.

 

		3Q22	4Q22	1Q23	2Q23	3Q23	4Q23
Production hedge per quarter - 000/bbls	150		150	180	180	30	30
Min. Average value of hedge - $/bbl	69.09		69.09	65.33	65.33	65.00	65.00
Max. Average value of hedge - $/bbl	78.17		78.17	102.88	102.88	115.20	115.20

 

Financing costs

Finance costs for the period were $5.6m (1H 2021: $2.9m) mainly related to amortisation of capitalised borrowing costs of $2.0m, inclusive of a one-off charge of $0.7m following a change in estimated future cash flows (1H 2021: $1.0m), interest expense payable and similar fees of $2.4m (1H 2021: $1.8m) and unwinding of discount of provisions $0.5m (1H 2021: $0.3m).

 

Taxation

The overall net tax charge of $43.9m (1H 2021: $20.3m) relates to tax charges in Vietnam of $30.2m plus the deferred tax charge on impairment reversal of $13.7m (1H 2021: Vietnam tax charges of $11.9m plus the deferred tax charge of $8.4m).

The Egypt concessions are subject to corporate income tax at the standard rate of 40.55%, however responsibility for payment of corporate income taxes falls upon EGPC on behalf of our local subsidiary Pharos El Fayum (PEF). The Group records a tax charge, with a corresponding increase in revenue, for the tax paid by EGPC on its behalf. Due to accumulated tax-deductible balances, there is no tax due on PEF this period.

 

Net profit

A net profit was recorded for the period from continuing operations of $54.3m, which is after $49.2m post-tax impairment reversal on PPE and $(0.1)m impairment of intangibles in Israel (1H 2021: profit $6.4m includes $19.4m post-tax impairment reversal on PPE).

Balance Sheet

Net cash/debt

As at the balance sheet date, $85.4m (RBL $77.8m and NBE $7.6m) was drawn under the Group's borrowing facilities and there was cash of $47.5m, giving a net debt figure of $37.9m (1H 2021: RBL $61.3m and NBE $nil; cash $28.4m and net debt of $32.9m).  Gearing has been calculated as total debt to equity of 0.24x (1H 2021: 0.20x).

We have had a solid record in receiving cash in Egyptian Pound (EGP) and US Dollars (USD) as well as offsets of creditors against our receivable position with EGPC since our acquisition of the Egyptian asset in 2019. As at 30 June 2022, the trade receivables with EGPC stood at $14.9m (31 Dec 21: $7.4m). However, with the recent global macroeconomic volatility, which has seen both a devaluation of the EGP and restrictions on outgoing USD transfers by the Central Bank of Egypt, we have experienced a slowdown in recovery and little scope for offset against creditors. Whilst we are able to recover the receivable in EGP, we have no real requirement other than the local office and staff costs. We are therefore holding the receivable balance in USD to avoid being caught by the current devaluation of the EGP. We continue to request USD from EGPC which is the currency in which they should settle the invoices, in accordance with the Concession Agreement, and have received small payments in USD in the last few weeks. In the event of any delay in our El Fayum invoices being paid, we have access to our facility with the National Bank of Egypt (NBE), which allows us to draw down 60% of the value of each invoice in USD. The amount drawn under the NBE facility as at 30 June 2022 was $7.5m, which is included in our net debt calculation. We will continue to closely monitor our working capital position across the Group with a view to expediting cash conversion and will keep the market updated on progress.

 

Borrowings 

Reserve Based Lending (RBL)

The RBL is secured over the Vietnam producing assets only and, after the refinancing in July 2021, as at 30 June 2022 had a four-year term maturing in July 2025. The borrowing base as at 30 June 2022 was $77.8m (1H 2021: $56.3m).

See Non-IFRS measures at page 32.

 

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

The amount repayable under the agreement at 30 June 2022 was $7.6m (30 June 2021: $5.0m) and it is presented as borrowings under current liabilities.

In May 2022, Pharos renegotiated the uncommitted revolving credit facility for discounting (with recourse) of up to $18m, limited to 60% of outstanding receivables (1H 2021: $20m).

This facility has been put in place to mitigate the risk of late payment of our debtors. Under this arrangement, Pharos is able to access cash from the facility using the El Fayum oil sales invoices as evidence to support its ability to repay the facility. The oil sales invoices remain due to Pharos and it retains the credit risk.  The Group therefore continue to recognise the receivables in their entirety in its balance sheet. 

Cash flow

Cash generated from operations was $57.0m (1H 2021: $18.2m) and prior to working capital movements was $75.8m (1H 2021: $27.1m). Stripping out the impact of the hedging positions to the underlying operations numbers gives a total of $93.1m (1H 2021: $40.8m), which is in line with the significant improvement that we see in commodity prices, partially offset by the Group production decrease period on period.

The increase in receivables was $10.4m for the period (1H 2021: increase of $5.4m). The movement is mainly driven by $7m additional invoice following the third amendment to the El Fayum Concession agreement. The remaining increase is commodity price driven, from YE21 the average oil price realised has increased from $70.95/bbl to $109.47/bbl therefore increasing the receivables balance held at half-year. (1H 2021: the average oil price realised from YE20 increased from $44.70/bbl to $64.76/bbl therefore increasing the receivables balance held at half-year).

Capital allocation

Following a period of improved commodity prices and a strengthening of the Group's liquidity position, we are able to turn our thoughts to shareholder returns in the form of both share buybacks and dividends. We announced a small share buyback programme in July 2022 of $3m, of which $1.6m has been committed. Based on progress to date, we expect to complete the programme in the fourth quarter this year. We are also announcing our intention to return to paying dividends based on the Company's 2022 full year results and set out our framework below.

 

The forecast Group cash capital expenditure for the year remains at $29m net after $15m carry in the Egypt drilling campaign and a return to drilling in Vietnam with two wells on TGT and one on CNV.

 

 

 

Dividend Framework

We aim to recommence dividend payments starting in 2023.  Our policy is now set at returning no less than 10% of Operating Cash Flow (OCF).

 

OCF has been selected as the most appropriate measure as it automatically takes account of:

 

•       swings in Brent price;

•       tax, which is the main form of government take in Vietnam; and

•       working capital movements.

 

The first dividend will be a final dividend for the 2022 financial year and will be paid in full following approval of the shareholders at the Company's AGM in 2023. Going forward, we expect the payment pattern will move to a conventional pattern of an interim and a final dividend.

 

Liquidity risk management and going concern

The Group closely monitors its liquidity risk. Cash forecasts are regularly produced, and stress tested for a number of scenarios including a downturn in the oil price, changes in production rates, operating costs and capital expenditure.  In the current environment of volatile, although strengthen oil prices and continued economic uncertainties created by the Ukraine war and rising inflation, scenario planning continues to be extensive. Accordingly, stress tests have been run for oil prices down to $63/bbl in October 2022, rising gradually over a year until in line with our base oil price curve, concurrent with reductions in Vietnam and Egypt production compared to our base case of 5%.  As at 30 June 2022, the Group had a cash balance of $47.5m and the forecasts show that the Group will have sufficient financial headroom for the period of 12 months from the date of approval of these half-year results. The Directors therefore have a reasonable expectation that the Company has adequate resources to continue in operational existence for the foreseeable future. Thus, they continue to adopt the going concern basis of accounting in preparing these half year results.

 

 

Sue Rivett

Chief Financial Officer

 

Corporate Review

Purpose

The oil and gas industry is in a period of transition as the drive to reduce emissions globally combines with each nation's efforts to secure the energy needed for the prosperity of its own citizens. It is likely that global demand for energy from hydrocarbons will remain strong for some years to come and it is therefore vital that oil and gas assets are managed in a responsible and transparent manner, for the benefit of the local economies, businesses, communities and families. The use of oil and gas in developing economies, particularly where it replaces coal, can provide the energy needed to drive GDP growth as a foundation for long-term economic and social benefits. In this way, our goal is to contribute to create sustainable prosperity and value for all of our stakeholders: investors, host countries, business and communities.

 

ESG

1.   Our commitment to Net Zero Emissions on all assets

 

Today, we are formalising a commitment to achieve Net Zero GHG emissions from all our assets by no later than 2050. This Net Zero target underscores the principle that sustainability is a key value in our purpose and business strategy.

Our Net Zero target includes Scope 1 (direct) and Scope 2 (indirect) emissions from all our assets. In addition, our Net Zero target applies to our existing as well as our future assets. As we evaluate any potential development of our business, such as licence extensions and acquisitions, we will take this commitment into account in our decision-making and it will fall under our Net Zero target.

We will look to advance our Net Zero target date which will depend on achieving operational efficiencies, reducing flaring and venting, replacing the power consumption of our facilities with less impactful energy sources and eventually procuring nature-based carbon offset projects for hard-to-abate, residual emissions. This will require investment by Pharos and its operational partners, which is why we are today establishing an Emissions Management Fund. For every barrel sold at an oil price above $75, we will set aside $0.25 into this Fund. The intended purpose of the fund is to provide support for emissions management projects for Pharos and our operational partners in line with our climate goals.

Today we also pledge to publish a detailed Net Zero roadmap in 2023. This will include the following:

-       A baseline emissions inventory for all our assets

-       Asset-level emission reduction frameworks

-       Interim targets over the short and medium term

-       Capital expenditure and resourcing to achieve targets

 

We recognise that the journey to Net Zero will not be straightforward, for Pharos and for the wider industry, with a stream of new ideas and solutions emerging to be tested. As new technologies become established, they will be reviewed and brought into use where relevant. We are committed to transparency in our reporting and to keeping stakeholders updated on our progress.

We also recognise that the support of host governments, state oil companies and regulators is key to push this agenda forward. We will work with our host governments where they seek to use oil revenues to promote sustainable and inclusive economic development, and we stand ready to support actions that they take to manage climate change and achieve their COP commitments.

We intend to keep our Net Zero commitment under review to align with emerging best practice methodologies informed by climate science and to accelerate our Net Zero timeline if possible.

2.   Climate strategy

 

Our climate strategy includes providing responsible stewardship, focusing on improving equipment efficiency to reduce power consumption and emissions, as well as extending life of existing fields though reservoir management, licence extensions and appropriate investments. For hard to abate emissions, we will target offset projects that can be developed and produced cost effectively, responsibly and in support of multiple UN Sustainable Development Goals.

 

Outlook

Our business remains focussed on creating value and near term cash flow from our asset base. We look to maximise value from these assets through ongoing efficiency drives, a close eye on the cost base and capital allocation which targets returns well in excess of the cost of capital.

Our capital allocation policy has always been founded on the inclusion of cash returns to shareholders and we have recommenced these in July 2022 with a share buyback programme. 

Our current priorities, in terms of balance sheet management, are to ensure that there is sufficient cover for upcoming work programme commitments plus a level of liquidity immediately available to the Group, to reinforce our resilience and ability to withstand future oil price downturns.

In the current oil price environment, the levels of cash generation are sufficient for us to resume regular dividend payments in 2023, following approval at the next AGM. Alongside our ongoing programme of responsible investment, we will continue to review the value accretion offered by share buybacks and are delighted to be in a position to recommence dividends no later than mid-2023.

 

 

 

Jann Brown

Chief Executive Officer

 

Responsibility Statement

The Directors confirm that to the best of their knowledge:

 

1.     The interim condensed consolidated set of financial statements immediately following this report has been prepared in accordance with United Kingdom adopted International Accounting Standard IAS 34 'Interim Financial Reporting' and gives a true and fair view of the assets, liabilities, financial position and profit or loss of the Company; and

 

2.     The interim report includes a fair review of the information required by:

 

·      DTR 4.2.7R of the Disclosure Guidance and Transparency Rules, being an indication of important events that have occurred during the first six months of the financial year and their impact on the condensed consolidated set of financial statements; and a description of the principal risks and uncertainties for the remaining six months of the year; and

 

·      DTR 4.2.8R of the Disclosure Guidance and Transparency Rules, being related party transactions that have taken place in the first six months of the current financial year and that have materially affected the financial position or performance of the entity during that period; and any changes in the related party transactions described in the last annual report that could do so.

 

 

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 2022 which comprises the condensed consolidated income statement, the condensed consolidated statements of comprehensive income, the condensed consolidated balance sheets, the condensed consolidated statements of changes in equity, the condensed consolidated cash flow statements and related notes 1 to 16.

 

Based on our review, nothing has come to our attention that causes us to believe that the condensed consolidated set of financial statements in the half-yearly financial report for the six months ended 30 June 2022 is not prepared, in all material respects, in accordance with United Kingdom adopted International Accounting Standard 34 and the Disclosure Guidance and Transparency Rules of the United Kingdom's Financial Conduct Authority.

 

Basis for Conclusion

 

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

 

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

 

Conclusion Relating to Going Concern

 

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

 

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

 

Responsibilities of the directors

 

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

 

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

 

Auditor's Responsibilities for the review of the financial information

 

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

 

Use of our report

 

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

 

 

 

Deloitte LLP

Statutory Auditor

London, United Kingdom

14 September 2022

 

 

 

 

Condensed consolidated income statement
										(unaudited) Six months ended	(unaudited) Six months ended		Year ended
										30 Jun 2022	30 Jun 2021		31 Dec 2021
									Notes	$ million	$ million		$ million
Continuing operations
Revenue									3, 13	112.3	59.2		134.1
Cost of sales									4	(59.9)	(51.5)		(114.6)
Gross profit										52.4	7.7		19.5
Administrative expenses										(5.0)	(5.5)		(13.2)
Impairment charge - Intangibles									3, 9	(0.1)	-		(2.2)
Impairment reversal - PP&E									3, 10	62.9	27.8		54.6
Impairment charge - Assets classified as held for sale										-	-		(10.4)
Operating profit										110.2	30.0		48.3
Other/restructuring expense									5	(0.6)	(0.4)		(3.3)
Loss on disposal									15	(5.8)	-		-
Finance costs									6	(5.6)	(2.9)		(6.4)
Profit for the period before tax									3	98.2	26.7		38.6
Tax									7	(43.9)	(20.3)		(43.3)
Profit/(Loss) for the period										54.3	6.4		(4.7)
Earnings/(Loss) per share from continuing operations (cents)									8
Basic										12.3	1.5		(1.1)
Diluted										12.3	1.4		(1.1)
Condensed consolidated statements of comprehensive income
										(unaudited) Six months ended	(unaudited) Six months ended		Year ended
										30 Jun 2022	30 Jun 2021		31 Dec 2021
								Notes		$ million	$ million		$ million
Profit/(Loss) for the period										54.3	6.4		(4.7)
Items that may be subsequently reclassified to profit or loss:
Fair value (loss) arising on hedging instruments during the period										(24.2)	(19.8)		(27.7)
Less: Loss arising on hedging instruments reclassified to profit or loss							13			17.3	13.7		29.7
Unrealised currency translation differences										-	0.1		-
Total comprehensive income/(loss) for the period										47.4	0.4		(2.7)

 

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

CONDENSED CONSOLIDATED Balance sheets
						(unaudited)	(unaudited)
						30 Jun 22	30 Jun 21	31 Dec 21
					Notes	$ million	$ million	$ million
Non-current assets
Intangible assets					9	14.3	4.6	12.4
Property, plant and equipment					10	432.0	440.3	399.8
Other assets						58.2	47.1	48.1
						504.5	492.0	460.3
Current assets
Inventories						10.7	19.2	10.7
Trade and other receivables					15	72.1	29.5	28.1
Tax receivables						1.1	0.4	1.5
Cash and cash equivalents						47.5	28.4	27.1
Assets classified as held for sale						-	-	62.0
						131.4	77.5	129.4
Total assets						635.9	569.5	589.7
Current liabilities
Trade and other payables						(15.2)	(25.6)	(24.1)
Derivative financial instruments					13	(14.9)	(14.9)	(6.5)
Borrowings					14	(35.3)	(13.7)	(33.3)
Tax payables						(4.8)	(4.2)	(5.4)
Liabilities associated with assets classified as held for sale						-	-	(8.5)
						(70.2)	(58.4)	(77.8)
Net current assets						61.2	19.1	51.6
Non-current liabilities
Trade and other payables					15	(0.9)	-	-
Deferred tax liabilities						(106.4)	(89.9)	(91.2)
Borrowings					14	(48.0)	(45.0)	(47.2)
Long term provisions						(57.4)	(70.1)	(69.1)
						(212.7)	(205.0)	(207.5)
Total liabilities						(282.9)	(263.4)	(285.3)
Net assets						353.0	306.1	304.4
Equity
Share capital						34.9	34.9	34.9
Share premium						58.0	58.0	58.0
Other reserves						242.5	241.2	250.5
Retained earnings / (deficit)						17.6	(28.0)	(39.0)
Total equity						353.0	306.1	304.4

 

 

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

 

 

 

 

CONDENSED consolidated STATEMENTs OF CHANGES IN EQUITY

 

 

 

 

							Called up share capital		Share Premium		Other reserves	Retained (deficit)/ earnings		Total
							$ million		$ million		$ million	$ million		$ million
As at 1 January 2021							31.9		55.4		243.0	(36.6)		293.7
Profit for the period							-		-		-	6.4		6.4
Other comprehensive loss							-		-		(6.0)	-		(6.0)
Shares issued							3.0		2.6		5.3	-		10.9
Share-based payments							-		-		1.1	-		1.1
Transfer relating to share-based payments							-		-		(2.2)	2.2		-
As at 30 June 2021 (unaudited)							34.9		58.0		241.2	(28.0)		306.1
Loss for the period							-		-		-	(11.1)		(11.1)
Other comprehensive income							-		-		8.0	-		8.0
Share-based payments							-		-		1.4	-		1.4
Transfer relating to share-based payments							-		-		(0.1)	0.1		-
As at 1 January 2022							34.9		58.0		250.5	(39.0)		304.4
Profit for the period							-		-		-	54.3		54.3
Other comprehensive loss							-		-		(6.9)	-		(6.9)
Share-based payments							-		-		1.2	-		1.2
Transfer relating to share-based payments							-		-		(2.3)	2.3		-
As at 30 June 2022 (unaudited)							34.9		58.0		242.51	17.6		353.0

 

 

condensed consolidated cash flow statements

 

						(unaudited) Six months ended	(unaudited) Six months ended	Year ended
						30 Jun 2022	30 Jun 2021	31 Dec 2021
					Notes	$ million	$ million	$ million
Net cash from operating activities					12	27.6	0.1	10.8
Investing activities
Purchase of intangible assets						(2.3)	(4.2)	(15.2)
Purchase of property, plant and equipment						(11.5)	(4.1)	(24.4)
Consideration received on farm out of Egyptian assets					15	10.1	-	2.0
Assignment fee in relation to farm out of Egyptian assets					15	(0.5)	-	-
Payment to abandonment fund						(1.1)	(1.2)	(2.2)
Net cash used in investing activities						(5.3)	(9.5)	(39.8)
Financing activities
Proceeds from borrowings					14	7.5	8.3	39.9
Interest paid on borrowings					14	(2.4)	(1.8)	(6.8)
Repayment of borrowings					14	(6.7)	(4.2)	(12.5)
Lease payments						-	(0.1)	(0.4)
Share-based payments						0.1	-	-
Net proceeds from issue of share capital						-	10.9	10.9
Net cash (used in)/from financing activities						(1.5)	13.1	31.1
Net increase in cash and cash equivalents						20.8	3.7	2.1
Cash and cash equivalents at beginning of period						27.1	24.6	24.6
Effect of foreign exchange rate changes						(0.4)	0.1	0.4
Cash and cash equivalents at end of period						47.5	28.4	27.1

 

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

Notes to the condensed consolidated financial statements

1.   General information

The information for the year ended 31 December 2021 does not constitute statutory accounts as defined in section 434 of the Companies Act 2006.  A copy of the statutory accounts for that year has been delivered to the Registrar of Companies.  The auditor's report on those accounts was not qualified, did not include a reference to any matters to which the auditors drew attention by way of emphasis without qualifying the report and did not contain statements under section 498(2) or (3) of the Companies Act 2006.

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

The half year financial report for the six months ended 30 June 2022 was approved by the Directors on 13 September 2022.

2.   Significant accounting policies

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

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

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

The interim report does not include all the notes of the type normally included in an annual financial report. Accordingly, this report is to be read in conjunction with the annual report for the year ended 31 December 2021 and any public announcements made by Pharos during the interim reporting period.

New and amended standards adopted by the Group

A number of new or amended standards became applicable for the current reporting period. The Group did not have to change its accounting policies or make retrospective adjustments as a result of adopting these standards.

Reference to the Conceptual Framework - Amendments to IFRS 3

Property, Plant and Equipment: Proceeds before Intended Use - Amendments to IAS 16

Onerous Contracts - Costs of Fulfilling a Contract - Amendments to IAS 37

These amendments had no impact on the interim condensed consolidated financial statements of the Group.

Critical judgements and accounting estimates

The preparation of condensed consolidated financial statements requires management to make judgements, estimates and assumptions which affect the application of accounting policies and the reported amounts of assets, liabilities, income and expense. Actual results may differ from these estimates.

 

 

 

(a)   Critical judgement in applying the Group's accounting policies

In the process of applying the Group's accounting policies, management has made judgements that may have a significant effect on the amounts recognised in the financial statements. These are: (i) oil and gas assets and (ii) going concern. The critical judgements disclosed in the annual report for the year ended 31 December 2021, Asset held for sale and Treatment of the Third Amendment to the El Fayum Concession Agreement, are not relevant as at 30 June 2022.

(b)   Key sources of estimation uncertainty

The key assumptions concerning the future, and other key sources of estimation uncertainty, other than those mentioned above, that may have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year continue to be: (i) oil & gas reserves and DD&A; (ii) impairment of producing oil & gas assets; and (iii) climate change and the energy transition.

Consideration was also given to the potential ongoing impact of the COVID-19 pandemic. During the first six months of 2022, the pandemic did not cause any interruptions to the Group's producing assets in Vietnam and Egypt.

3.   Segment information

The Group has one principal business activity being oil and gas exploration and production. The Group's continuing operations are located in South East Asia and Egypt and these areas form the basis on which the Group reports its segment information (the Group's operating segments). There are no inter-segment sales.

Six months ended 30 June 2022 (unaudited)							SE Asia	Egypt	Unallocated1		Group
							$ million	$ million	$ million		$ million
Oil and gas revenue							103.8	25.83	-		129.6
Commodity Hedge (see Note 13)							-	-	(17.3)		(17.3)
Total Revenue							103.8	25.8	(17.3)		112.3
Depreciation, depletion and amortisation - oil and gas							(25.9)	(1.7)	-		(27.6)
Impairment charge - Intangibles							-	-	(0.1)		(0.1)
Impairment reversal - PP&E							38.4	24.5	-		62.9
Profit/(Loss) before tax from continuing operations1							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

 

Six months ended 30 June 2021 (unaudited)							SE Asia	Egypt	Unallocated1		Group
							$ million	$ million	$ million		$ million
Oil and gas revenue							56.3	16.6	-		72.9
Commodity Hedge (see Note 13)							-	-	(13.7)		(13.7)
Total Revenue							56.3	16.6	(13.7)		59.2
Depreciation, depletion and amortisation - oil and gas							(19.4)	(4.2)	-		(23.6)
Depreciation, depletion and amortisation - other							-	(0.3)	-		(0.3)
Impairment reversal - PP&E							24.1	3.7	-		27.8
Profit/(Loss) before tax from continuing operations1							42.4	6.0	(21.7)		26.7
Tax charge on operations (see Note 7)							(11.9)	-	-		(11.9)
Tax charge on impairment reversal (see Note 7)							(8.4)	-	-		(8.4)
Non-current assets2							333.3	109.7	1.9		444.9
Year end 31 December 2021							SE Asia	Egypt	Unallocated1		Group
							$ million	$ million	$ million		$ million
Oil and gas revenue							131.0	32.8	-		163.8
Commodity Hedge							-	-	(29.7)		(29.7)
Total Revenue							131.0	32.8	(29.7)		134.1
Depreciation, depletion and amortisation - oil and gas							(43.0)	(8.0)	-		(51.0)
Depreciation, depletion and amortisation - other							-	(0.4)	-		(0.4)
Impairment charge - Intangibles							-	-	(2.2)		(2.2)
Impairment reversal - PP&E							52.9	1.7	-		54.6
Impairment charge - Assets classified as held for sale							-	(10.4)	-		(10.4)
Profit/(Loss) before tax from continuing operations1							98.8	(10.1)	(50.1)		38.6
Tax charge on operations (see Note 7)							(24.8)	-	-		(24.8)
Tax charge on impairment reversal (see Note 7)							(18.5)	-	-		(18.5)
Non-current assets2							360.8	51.4	-		412.2

 

¹Unallocated 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.

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

Under the terms, the cost recovery percentage was increased from 30% to 40% allowing Pharos a significantly faster recovery of all its past and future investments. In return, Pharos agreed to waive its rights to recover a portion of the past costs pool ($115m) and reduce its share of Excess Cost Recovery Petroleum from 15% to 7.5%. While in full cost recovery mode, Contractor's share of revenue increases from 42.6% to 50.8% as from November 2020 (corresponding to additional net revenues to Contractor of $7.0m to 31 December 2021).

 

4.   Cost of sales

										(unaudited) six months ended 30 Jun 2022	(unaudited) six months ended 30 Jun 2021	Year ended 31 Dec 2021
										$ million	$ million	$ million
Depreciation, depletion and amortisation										27.6	23.6	51.0
Production based taxes										8.8	4.4	10.1
Export duty										3.2	-	-
Production operating costs										25.4	25.2	53.6
Inventories										(5.1)	(1.7)	(0.1)
										59.9	51.5	114.6

 

 

5.   Other/restructuring expense

(unaudited) six months ended 30 Jun 2022 (unaudited) six months ended 30 Jun 2021 Year ended 31 Dec 2021       $ million $ million $ million   Redundancy loss       0.1 0.4 3.0   Premium - lease transfer       0.5 - 0.3           0.6 0.4 3.3

 

6.   Finance Costs

(unaudited) six months ended 30 Jun 2022 (unaudited) six months ended 30 Jun 2021 Year ended 31 Dec 2021       $ million $ million $ million   Unwinding of discount on provisions                                                        0.5 0.3 0.8   Interest expense payable and similar fees (see Note 14)                                      2.4 1.8 3.8   Amortisation of capitalised borrowing costs (see Note 14) 2.0 1.0 2.4   Net foreign exchange losses/(gains)   0.7 (0.2) (0.6)           5.6 2.9 6.4

 

As at 30 June 2022, $0.5m relates to the unwinding of discount on the provisions for decommissioning (1H 2021: $0.3m). The provisions are based on the net present value of the Group's share of the expenditure which may be incurred at the end of the life of TGT and CNV (currently estimated to be 8-9 years) in the removal and decommissioning of the facilities currently in place.

Following the June 2022 redetermination and the $0.2m repayment of principal in relation to the Group's reserve based lending facility, there was a change in estimated future cash flows. As a result, in June 2022, a one off charge of $0.7m (1H 2021: $nil; Dec 2021: $0.5m gain) and amortised cost of $1.3m (1H 2021: $1.0m; Dec 2021: $2.9m) was recognised in the income statement.

7.   Tax

(unaudited) six months ended 30 Jun 2022 (unaudited) six months ended 30 Jun 2021 Year ended 31 Dec 2021       $ million $ million $ million   Current tax 28.7 16.0 37.6   Deferred tax charge/(credit) on operations 1.5 (4.1) (12.8)   Deferred tax charge on impairment reversal   13.7 8.4 18.5   Total tax charge       43.9 20.3 43.3

The Group's corporation tax is calculated at 50% (1H 2021: 50%) of the estimated assessable profit for the year in Vietnam. In Egypt, under the terms of the concession any local taxes arising are settled by EGPC. During each period, both current and deferred taxation have arisen in overseas jurisdictions only.

For CNV, a pre-tax impairment reversal in the amount of $13.6m has been reflected in the income statement with an associated deferred tax charge of $5.1m (1H 2021: pre-tax impairment reversal $2.2m, deferred tax charge of $0.8m). For TGT, a pre-tax impairment reversal in the amount of $24.8m has been reflected in the income statement with an associated deferred tax charge of $8.6m (1H 2021: pre-tax impairment reversal $21.9m, deferred tax charge of $7.6m).

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

(unaudited) six months ended 30 Jun 2022 $ million (unaudited) six months ended 30 Jun 2021 $ million Year ended 31 Dec 2021                     $ million Profit before tax 98.2 26.7 38.6 Profit before tax at 50% (2021: 50%) 49.1 13.3 19.3 Effects of:   Non-taxable income (5.6) (3.7) (8.0) Non-deductible expenses 4.7 3.5 4.5 Tax losses not recognised 13.1 10.2 28.7 Utilisation of losses (17.7) (3.0) - Adjustments to tax charge in respect of previous periods 0.3 - (1.2) Tax charge for the year       43.9 20.3 43.3

 

The prevailing tax rate in Vietnam, where the Group produces oil and gas, is 50% (1H 2021: 50%). The tax charge in future periods may also be affected by the factors in the reconciliation above.

Non-taxable income principally relates to Vietnam impairment reversal of $(5.5)m (1H 2021: $(3.7)m). Non-deductible expenses primarily relate to Vietnam DD&A charges for costs previously capitalised, which are non-deductible for Vietnamese tax purposes of $3.3m (1H 2021: $1.9m). A further $1.4m (1H 2021: $1.6m) relates to non-deductible corporate costs including share scheme incentives. Tax losses not recognised of $13.1m (1H 2021: $10.2m) are predominantly due to the tax impact of realised hedging losses during the period.

Utilisation of losses of $(17.7)m (1H 2021: $(3.0)m) relate to Egypt. The Egypt concessions are subject to corporate income tax at the standard rate of 40.55%, however responsibility for payment of corporate income taxes falls upon EGPC on behalf of our local subsidiary Pharos El Fayum (PEF). The Group records a tax charge, with a corresponding increase in revenue, for the tax paid by EGPC on its behalf. However, this is only valid if PEF is in an historic profit making position and no such tax has been recorded this period.

 

8.   Earnings/(loss) per share

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

(unaudited) six months ended 30 Jun 2022 (unaudited) six months ended 30 Jun 2021 Year ended 31 Dec 2021       $ million $ million $ million   Profit/(Loss) from continuing operations for the purposes of basic profit/(loss) per share 54.3 6.4 (4.7)   Effect of dilutive potential ordinary shares - Cash settled share awards and options - (0.3) -   Profit/(Loss) from continuing operations for the purposes of diluted profit/(loss) per share 54.3 6.1 (4.7)

(unaudited) six months ended 30 Jun 2022   (unaudited) six months ended 30 Jun 2021   Year ended 31 Dec 2021       $ million $ million $ million   Weighted average number of ordinary shares 441.7 434.6 437.8   Effect of dilutive potential ordinary shares - Share awards and options 0.5 0.7 -   Weighted average number of ordinary shares for the purpose of diluted profit/(loss) per share 442.2 435.3 437.8

 

 

In accordance with IAS 33 "Earnings per Share", the effects of $14.2m antidilutive potential shares have not been included when calculating diluted earnings per share for the year ended 31 December 2021, as the Group was loss making.

9.   Intangible assets

Intangible assets comprise the Group's exploration and evaluation projects which are pending determination.

In June 2022, having reviewed the triggers for impairment, Management are of the view that none of the impairment indicators under IFRS 6 have been triggered and therefore no impairment testing is required for Vietnam or Egypt.

During H1 2022, $0.1m was spent in Israel on geoscience and geophysical studies. Pharos continues to hold $2.7m (Dec 2021: $2.7m) cash in relation to bank guarantees for the Israeli offshore exploration licenses. At 30 June 2022, the Group has decided to write off the $0.1m in Israel as no substantive expenditure has been identified as indicated in IFRS 6 (Dec 2021: Israel impairment charge $2.2m).

10.  Property, plant and equipment

As a result of the oil price volatility and movements in 2P reserves, we have tested each of our oil and gas producing properties for impairment. The results of these impairment tests are summarised below. For each producing property, the recoverable amount has been determined using the value in use method which constitutes a level 3 valuation within the fair value hierarchy. The recoverable amount is supported by the fair value derived from a discounted cash flow valuation of the 2P production profile.

 

 

 

Vietnam

The key assumptions to which the fair value measurement is most sensitive are oil price, discount rate and 2P reserves (2021: oil price, discount rate and 2P reserves). As at 30 June 2022, the fair value of the assets are estimated based on a post-tax nominal discount rate of 13% (1H 2021: 11%) and a Brent oil price of $107.6/bbl in 2H 2022 down to $77.0/bbl in 2025 plus inflation of 2% thereafter (1H 2021: an oil price of $64.7/bbl in 2H 2021 up to $65.0/bbl in 2025, plus inflation of 2% thereafter).

For CNV, a pre-tax impairment reversal in the amount of $13.6m has been reflected in the income statement with an associated deferred tax charge of $5.1m. As at 30 June 2022, the carrying amount of the CNV oil and gas producing property, after additions of $0.2m, changes in decommissioning asset ($1.7m), DD&A ($5.3m) and impairment reversal of $13.6m, is $91.0m.

For TGT, a pre-tax impairment reversal in the amount of $24.8m has been reflected in the income statement with an associated deferred tax charge of $8.6m. As at 30 June 2022, the carrying amount of the TGT oil and gas producing property, after additions of $0.5m, changes in decommissioning asset ($8.7m), DD&A ($20.6m) and after impairment reversal of $24.8m, is $262.0m. It should be noted that the TGT impairment reversal at 30 June 2022 has been restricted to reflect the remaining balance of historic impairment charges previously recorded against the field. The impairment reversal test calculated NPV13 $218.9m which would have implied a pre-tax reversal of $67.2m, but this was restricted to $24.8m.

Testing of sensitivity cases indicated that a $5/bbl reduction in long-term oil price used when determining the value in use method would result in post-tax impairment charges (compared to new Net Book Value, "NBV") of $3.8m on CNV. A 1% increase in discount rate would result in post-tax impairments of $1.3m on CNV. We have also run sensitivities utilising the IEA (International Energy Agency) scenarios described as being consistent with achieving the COP26 agreement goal to reach net zero by 2050 (the "Net Zero price scenario"). The nominal Brent prices used in this scenario were as follows; 2022:$105.6/bbl, 2023:$93.8/bbl,2024:$84.4/bbl, 2025:$77.0/bbl, 2026: $71.0/bbl, 2027:$65.0/bbl, 2028:$58.0/bbl, 2029:$51.0/bbl. 2030:$44.0/bbl. Using these prices and a 13% discount rate would result in additional post-tax impairments of $5.8m on CNV.

For TGT, even if these downside scenarios are applied ($5/bbl reduction in long-term oil price, 1% increase in discount rate and Net Zero price scenario), the impairment reversal would still have been $24.8m.

Egypt

The key assumptions to which the fair value measurement is most sensitive are oil price, discount rate and 2P reserves (2021: oil price, discount rate and 2P reserves). As at 30 June 2022, the fair value of the asset is estimated based on a post-tax nominal discount rate of 15.1% (1H 2021: 14%) and a Brent oil price of $107.6/bbl in 2H 2022 down to $77.0/bbl in 2025 plus inflation of 2% thereafter (1H 2021: an oil price of $64.7/bbl in 2H 2021 up to $65.0/bbl in 2025, plus inflation of 2% thereafter).

For Egypt, an impairment reversal (pre and post tax) in the amount of $24.5m has been reflected in the income statement. As at 30 June 2022, the carrying amount of the Egypt oil and gas producing property, after additions of $6.7m, DD&A ($1.7m) and after the impairment reversal of $24.5m, is $78.7m.

Testing of sensitivity cases indicated that a $5/bbl reduction in long term oil price used would result in an impairment of $7.2m (compared to new NBV). A 1% increase in discount rate would result in an impairment charge of $3.0m. We have also run a sensitivity using a 15.1% discount rate and the Net Zero price scenario which would result in an additional impairment of $15.0m.

Other considerations

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

Other fixed assets comprise office fixtures and fittings and computer equipment.

Capital commitments

At 30 June 2022, the Group had exploration licence commitments not accrued of approximately $27.3m (31 Dec 2021: $36.2m).

 

11.  Distribution to Shareholders

The Company remains focused on preserving balance sheet strength and has not yet returned to declaring dividend payments (2021 : $Nil).

12.  Reconciliation of operating profit to operating cash flows

									(unaudited) six months ended 30 Jun 2022	(unaudited) six months ended 30 Jun 2021	Year ended 31 Dec 2021
									$ million	$ million	$ million
Operating profit									110.2	30.0	48.3
Share-based payments									0.8	1.0	2.4
Depreciation, depletion and amortisation									27.6	23.9	51.4
Impairment charge - Intangibles									0.1	-	2.2
Impairment reversal - PP&E									(62.9)	(27.8)	(54.6)
Impairment charge - Assets classified as held for sale									-	-	10.4
Operating cash flows before movements in working capital									75.8	27.1	60.1
(Increase)/Decrease in inventories									(4.4)	(1.5)	0.8
Increase  in receivables1									(10.4)	(5.4)	(7.2)
Decrease in payables1									(4.0)	(2.0)	(2.2)
Cash generated by operations									57.0	18.2	51.5
Interest paid									(0.1)	(0.1)	(0.1)
Other/redundancy expense outflow									(2.3)	(0.1)	(0.7)
Income taxes paid									(27.0)	(17.9)	(39.9)
Net cash from operating activities									27.6	0.1	10.8

 

¹ During the six months ended 30 June 2022 a total of $4.3m (1H 2021: $2.6m) of trade receivables due from EGPC in Egypt were settled by way of non-cash offset, out of which $1.0m relates to 3rd Amendment signature bonus (1HY 2021: Nil), $0.8m was set against trade payables (1HY 2021 $2.6m), $2.0m Assignment bonus settled on behalf of the Farm out partner, IPR and $0.5m Group's share of NBS Concession assignment bonus (see Note 15).

13.  Hedge transactions

During 1H 2022, Pharos entered into different commodity (swap and zero collar) hedges to protect the Brent component of forecast oil sales and to ensure future compliance with its obligations under the RBL over the producing assets in Vietnam. The commodity hedges run until June 2023 and are settled monthly. The hedging positions in place at the balance sheet date cover 30% of the Group's forecast production until June 2023, securing an average price for this hedged volume of $67.0/bbl (1H 2021: cover was 27% of the Group's forecast production until June 2022, securing a minimum price for this hedged volume of $55.6/bbl).

Pharos has designated the swaps and zero collar as cash flow hedges. This means that the effective portion of unrealised gains or losses on open positions will be reflected in other comprehensive income. Every month, the realised gain or loss will be reflected in the revenue line of the income statement. For the period ended 30 June 2022 a loss of $17.3m was realised (1H 2021: loss of $13.7m). The outstanding unrealised loss on open position as at 30 June 2022 amounts to $11.2m (1H 2021: loss of $12.4m).

The carrying amounts of the swaps and zero collar are based on the fair value determined by a financial advisor. As all material inputs are observable, they are categorised within Level 2 in the fair value hierarchy. It is presented in "Derivative financial instruments" in the consolidated statement of financial position. The liability position as at June 2022 was $14.9m of which $3.6m has been realised and due for payment early July (1H 2021: liability position $14.9m of which $2.5m was realised).

14.  Borrowings

Changes in liabilities arising from financing activities:

	(unaudited)  six months ended 30 Jun 2022 $ million			(unaudited) six months ended 30 Jun 2021 $ million
	Credit      facility	RBL	Total Borrowings	Total Borrowings
Carrying value as of 1 January	6.5	74.0	80.5	53.7
Proceeds from Uncommitted Revolving credit facility	7.5	-	7.5	8.3
Repayments of borrowings	(6.5)	(0.2)	(6.7)	(4.2)
Amortisation of capitalised borrowing costs (see Note 6)	-	2.0	2.0	1.0
Interest payable and similar fees (see Note 6)	0.2	2.2	2.4	1.8
Interest paid during the year	(0.1)	(2.3)	(2.4)	(1.9)
Carrying value as of 30 June	7.6	75.7	83.3	58.7
Current	7.6	27.7	35.3	13.7
Non-current	-	48.0	48.0	45.0

 

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

In May 2022, the Group renegotiated the uncommitted revolving credit facility with National Bank of Egypt for discounting (with recourse) of up to $18m (1H 2021: $20m).

The carrying amount of the trade receivables include receivables in Egypt which are subject to an Uncommitted Revolving Credit Facility for Discounting (with Recourse) arrangement.  This facility was put in place to mitigate the risk of late payment. Under this arrangement, Pharos is able to access cash from the facility using the El Fayum oil sales invoices as evidence to support its ability to repay the facility. The oil sales invoices remain due to Pharos and it retains the credit risk. The Group therefore continues to recognise the receivables in their entirety in its balance sheet. 

15.  Disposal of asset held for sale

In December 2021, the company classified 55% of the Group's operated interest in each of our Egyptian Concessions, El Fayum and North Beni Suef, as Assets classified as held for sale (Net assets classified as held for sale as 31 December 2021: $53.5m).

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

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

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

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

All revenues earned are paid direct to Pharos. 

 

 

 

Disposal of asset held for sale:

									$ million
Intangible									(2.3)
Property, plant and equipment									(54.4)
Inventories									(5.9)
Trade and other receivables									(2.3)
Trade and other payables									8.3
Disposal of 55% of El Fayum and NBS									(56.6)
Firm consideration received - IPR Cash Receipts									5.0
Other receivable - Carry									37.0
Other receivable - contingent consideration									13.6
Other receivable with IPR									0.5
Consideration received and to be received									56.1
Assignment fees payable to EGPC									(3.6)
Success fees paid on completion									(1.7)
Loss on disposal									(5.8)

 

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

The carry of $37.0m is disproportionate funding contribution from IPR adjusted for working capital and interim period adjustments from the effective economic date of 1 July 2020 and completion date. The interim period adjustments amount is the best estimate as at 30 June 2022.

The carry will decrease every month against the cash calls received from IPR. The total amount utilised as at 30 June 2022 amounts to $7.1m, which has been disclosed in "Consideration received on farm out of Egyptian assets" in the cash flow as part of investing activities (combined with $3.0m firm consideration received on 30 March 2022). No cash outflow is required until we utilise the whole amount.

The Group is entitled to contingent consideration depending on the average Brent Price each year from 2022 to the end of 2025 (with floor and cap at $62/bbl and c.$90/bbl respectively). The contingent consideration is calculated yearly and is capped at a maximum total payment of $20.0m. As at 30 June 2022, the contingent consideration amounts to $13.6m ($4.6m current and $9.0m non-current). Testing of sensitivity for a $5/bbl reduction in long term oil price used would result in $1.7m decrease in contingent consideration to $11.9m.

As at 30 June 2022, $3.6m relates to the assignment fee for the sale of 55% of the Group's operated interest in each of our Egyptian Concessions, El Fayum and North Beni Suef, to IPR. $0.5m Group's share of NBS Concession assignment bonus was settled against Trade Receivable. Out of the remaining $3.1m, $2.2m is booked as current other payable and $0.9m as non-current other payable.

16.  Subsequent events

Share buy-back

On 20 July 2022, Pharos initiated a share buy-back programme to purchase up to approximately $3m (excluding stamp duty and expenses) of the Company's ordinary shares in the market. As at close of business on 12 September 2022, $1.6m had been committed under the programme. Based on progress to date, we expect to complete the programme in the fourth quarter this year.

 

 

 

Non-IFRS measures

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

Cash operating costs per barrel

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

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

									(unaudited) six months ended 30 Jun 22	(unaudited) six months ended 30 Jun 21	Year ended 31 Dec 21
									$ million	$ million	$ million
Cost of sales									59.9	51.5	114.6
Less:
Depreciation, depletion and amortisation									(27.6)	(23.6)	(51.0)
Production based taxes									(8.8)	(4.4)	(10.1)
Export duty									(3.2)	-	-
Inventories									5.1	1.7	0.1
Trade Receivable risk factor provision									(1.5)	-	-
Other cost of sales									(1.1)	(0.8)	(1.6)
Cash operating costs									22.8	24.4	52.0
Production (BOEPD)									7,962	9,147	8,878
Cash operating cost per BOE ($)									15.82	14.74	16.05

 

Cash operating costs per barrel by segment (1H 2022)

											Vietnam			Egypt			Total
											$ million			$ million			$ million
Cost of sales											50.0			9.9			59.9
Less:
Depreciation, depletion and amortisation											(25.9)		(1.7)				(27.6)
Production based taxes											(8.7)		(0.1)				(8.8)
Export duty											(3.2)		-				(3.2)
Inventories											5.1		-				5.1
Trade Receivable risk factor provision											-		(1.5)				(1.5)
Other cost of sales											(0.8)		(0.3)				(1.1)
Cash operating cost											16.5			6.3			22.8
Production (BOEPD)											5,861			2,1011			7,962
Cash operating cost per BOE ($)											15.55			16.57			15.82

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

 

Vietnam									(unaudited) six months ended 30 Jun 22	(unaudited) six months ended 30 Jun 21
									$ million	$ million
Cost of sales									50.0	37.7
Less:
Depreciation, depletion and amortisation									(25.9)	(19.4)
Production based taxes									(8.7)	(4.3)
Export duty									(3.2)	-
Inventories									5.1	1.7
Other cost of sales									(0.8)	(0.4)
Cash operating costs									16.5	15.3
Production (BOEPD)									5,861	5,429
Cash operating cost per BOE ($)									15.55	15.57

 

Egypt									(unaudited) six months ended 30 Jun 22	(unaudited) six months ended 30 Jun 21
									$ million	$ million
Cost of sales									9.9	13.8
Less:
Depreciation, depletion and amortisation									(1.7)	(4.2)
Production based taxes									(0.1)	(0.1)
Inventories									-	-
Trade Receivable risk factor provision									(1.5)	-
Other cost of sales									(0.3)	(0.4)
Cash operating costs									6.3	9.1
Production (BOEPD)									2,1011	3,718
Cash operating cost per BOE ($)									16.57	13.52

 

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

 

 

DD&A per barrel

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

									(unaudited) six months ended 30 Jun 22	(unaudited) six months ended 30 Jun 21	Year ended 31 Dec 21
									$ million	$ million	$ million
Depreciation, depletion and amortisation									(27.6)	(23.6)	(51.0)
Production (BOEPD)									7,962	9,147	8,878
DD&A per BOE ($)									19.15	14.25	15.74

 

DD&A per barrel by segment (1H 2022)

									Vietnam		Egypt		Total
									$ million		$ million		$ million
Depreciation, depletion and amortisation									(25.9)		(1.7)		(27.6)
Production (BOEPD)									5,861		2,101		7,962
DD&A per BOE ($)									24.41		4.47		19.15

 

Vietnam									(unaudited) six months ended 30 Jun 22	(unaudited) six months ended 30 Jun 21
									$ million	$ million
Depreciation, depletion and amortisation									(25.9)	(19.4)
Production (BOEPD)									5,861	5,429
DD&A per BOE ($)									24.41	19.74

 

Egypt									(unaudited) six months ended 30 Jun 22	(unaudited) six months ended 30 Jun 21
									$ million	$ million
Depreciation, depletion and amortisation									(1.7)	(4.2)
Production (BOEPD)									2,101	3,718
DD&A per BOE ($)									4.47	6.24

 

 

 

 

 

Net Debt

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

									(unaudited) six months ended 30 Jun 22	(unaudited) six months ended 30 Jun 21	Year ended 31 Dec 21
									$ million	$ million	$ million
Cash and cash equivalents									47.5	28.4	27.1
Borrowings*									(85.4)	(61.3)	(84.6)
Net Debt									(37.9)	(32.9)	(57.5)

 

*Exclude unamortised capitalised set up costs

 

EBITDAX

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

									(unaudited) six months ended 30 Jun 22	(unaudited) six months ended 30 Jun 21	Year ended 31 Dec 21
									$ million	$ million	$ million
Operating profit									110.2	30.0	48.3
Depreciation, depletion and amortisation									27.6	23.9	51.4
Impairment reversal									(62.8)	(27.8)	(42.0)
EBITDAX									75.0	26.1	57.7

 

Net Debt/EBITDAX

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

									(unaudited) six months ended 30 Jun 22	(unaudited) six months ended 30 Jun 21	Year ended 31 Dec 21
									$ million	$ million	$ million
Net Debt									(37.9)	(32.9)	(57.5)
EBITDAX									75.0	26.1	57.7
Net Debt/EBITDAX									0.51	1.26	1.00

 

 

Gearing

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

									(unaudited) six months ended 30 Jun 22	(unaudited) six months ended 30 Jun 21	Year ended 31 Dec 21
									$ million	$ million	$ million
Total Debt									85.4	61.3	84.6
Total Equity									353.0	306.1	304.4
Debt to Equity									0.24	0.20	0.28

 

 

Operating cash per share

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

									(unaudited) six months ended 30 Jun 22	(unaudited) six months ended 30 Jun 21	Year ended 31 Dec 21
									$ million	$ million	$ million
Net cash from continuing operating activities									27.6	0.1	10.8
Weighted number of shares in the year									441,743,462	436,995,454	437,512,648
Operating cash per share									0.06	-	0.02

Operating profit excluding impairment (reversal)/charge

Operating profit excluding impairment (reversal)/charge is calculated by adding back the impairment (reversal)/charge to the operating profit.

 

									(unaudited) six months ended 30 Jun 22	(unaudited) six months ended 30 Jun 21	Year ended 31 Dec 21
									$ million	$ million	$ million
Operating profit									110.2	30.0	48.3
Impairment charge									0.1	-	12.6
Impairment reversal									(62.9)	(27.8)	(54.6)
Operating profit excluding impairment (reversal)/charge									47.4	2.2	6.3