WTI (Feb) $77.41 +$2.29, Brent (Mar) $82.67 +$2.57, Diff -$5.26 -21c.
USNG (Feb) $3.67 +4c, UKNG (Feb) 167.49p -3.78p, TTF (Feb) €66.795 -€1.21.
Oil was up sharply, as I said yesterday despite amazing inventory reports. Further Russian sanctions are being considered by the US and allies which should stifle their oil sales.
Wentworth and Etablissements Maurel & Prom S.A. announced on 5 December 2022 that they had reached agreement on the terms of a recommended acquisition of the entire issued and to be issued share capital of Wentworth by M&P at 32.5 pence per share, in accordance with the UK Takeover Code. The Acquisition values the entire issued and to be issued ordinary share capital
of Wentworth at approximately £61.7 million (approximately $75.0 million).
On 14 February 2022 Wentworth published a competent person’s report which included an
asset valuation by RPS Energy Canada Limited. In connection with the Acquisition,
Wentworth is required by Rule 29 of the Code to publish an updated, independent asset
valuation. As RPS is also reserves auditor to M&P, Wentworth has commissioned ERC Equipoise Ltd to provide the Valuation. ERCE is independent of both Wentworth and M&P.ERCE values Wentworth’s oil & gas assets at a range, based on the scenarios set out below, of: $59 million to $75 million
Wentworth estimates the value of the Company as an ongoing business, based on the
Valuation, adjusting for existing cash, taxes and costs, on a fully diluted basis, to be between:
24.8 pence per share and 27.9 pence per share
The illustrative figures below set out the indicative pence per share valuation of Wentworth as
a business, taking into account the Valuation.
The Valuation represents the Net Present Value1
of the cash flows from Wentworth’s
assets in each of three stated scenarios, selected by ERCE, as at 1 October 2022 (the
Withholding tax of 10 per cent. is applied on those cash flows when repatriated from
Costs comprise the Net Present Value1
of the expenditure required to maintain the
business, both in Tanzania and as a quoted company. The illustrative figures below
extrapolate the Company’s reported 2021 General & Administrative expenses for the
length of the licence in each scenario, risked where appropriate.
In all cases, the discount rate used by ERCE is 15%, which the Board believes to be
appropriate, taking into account Wentworth’s cost of capital.
Scenario 12 Scenario 23 Scenario 34
$ million GBp/share8,9 $ million GBp/share8,9 $ million GBp/share8,9
Valuation1,10 59.0 25.6 71.0 30.8 75.0 32.5
(5.9) (2.6) (7.1) (3.1) (7.5) (3.3)
Costs1,5 (30.7) (13.3) (38.0) (16.5) (38.0) (16.5)
Cash5,6 28.0 12.2 28.0 12.2 28.0 12.2
Working Capital5,7 6.7 2.9 6.7 2.9 6.7 2.9
Total 57.2 24.8 60.7 26.3 64.3 27.9
1. Net Present Value is the value of all future cashflows (positive and negative) over the length of the licence, discounted
to the present
2. Scenario 1 assumes that the current licence expires at the end of the current term in October 2031 and is not extended.
In addition it assumes that $45 million (gross) of costs which the Operator believes to be cost recoverable are not
ultimately recovered at all.
3. Scenario 2 assumes that the current licence is extended at the end of the current term, being 2031, until October 2041.
In addition it assumes that $16.9 million (gross) of the $45 million (gross) of costs which the Operator believes to be cost recoverable are not ultimately recovered at all. The licence extension (and the taxes and costs thereafter) are risked at 80%.
4. Scenario 3 assumes that the current licence is extended at the end of the current term, being 2031, until October 2041.
In addition it assumes that $45 million (gross) of costs which the Operator believes to be cost recoverable are fully
recovered. The licence extension (and the taxes and costs thereafter) are risked at 80%.
5. Corporate adjustments, including withholding tax, costs, cash and working capital have been made by Wentworth to the ERCE valuation to provide an illustrative corporate valuation.
6. Cash figure represents the unaudited 30 September 2022 balance, in order to align with the Effective Date.
7. Working capital is defined as receivables minus payables. Figure represents the unaudited 30 September 2022
balance, in order to align with the Effective Date.
8. Assumes a GBP: USD exchange rate of 1:1.2163, sourced from Factset as at 10 January 2023.
9. Assumes a fully diluted share count of 189,717,616.
10. ERCE has only provided asset valuations for Scenarios 1, 2 and 3 in USD. In the table above, Wentworth has converted
these to GBp/share.
Rule 29.6 of the Code requires that this announcement contain an estimate by the Wentworth
directors of the amount of any potential tax liability which would arise if the assets were to be
sold at the amount of the Valuation and a comment as to the likelihood of any such liability
crystallizing. The Wentworth Directors, having taken appropriate taxation advice, are aware
that in comparable transactions in Tanzania, taxation, in varying amounts, has been levied by
the Government of Tanzania. The Wentworth Directors are unable to calculate the amount of
tax that may be levied by the Tanzanian Government for any such sale for the purposes of
Rule 29.6 of the Code.
The Valuation is available on Wentworth’s website: https://www.wentplc.com/investors/offerfor-wentworth/
The publication of the Valuation permits the Board of Wentworth to set out the above views
on value as well the observations below:
Wentworth has historically been able to deliver strong shareholder returns since its
maiden dividend in 2019, however:
o Wentworth has benefitted from the Mnazi Bay production sharing contract’s
cost recovery mechanism and historic cost pool, having recovered
approximately $300 million of historic costs to date;
o on 23 December 2022, the Mnazi Bay JV Partners (“JV Partners”) received
formal notice from TPDC that it proposes to discuss re-examining the historic
cost pool audit for the years 2013 – 2015 relating to seismic, field infrastructure
and drilling of MB-4 well expenditure. Joint Venture costs of $45 million
(approximately $15 million net to Wentworth) are subject to the reexamination. The Company anticipates, given the absence of recent investment in the Mnazi Bay field, that 2023 production will include significant periods where costs have been fully recovered, leading to substantially lower
revenues. Any reduction in the current expected cost pool balance as a result of the audit re-examination is likely to further impact revenue next year;
o Mnazi Bay is at, or close to, peak production and material capex is required to
maintain, let alone increase, production. As such, historic revenue, profit and
dividend growth cannot be used as proxy for future expectations; and
o M&P is the operator of the asset. All future capital expenditure is dependent on
M&P choosing to allocate capital to this asset, in the context of its wider
The directors consider that inorganic growth in Tanzania is clearly going to be
challenging. Wentworth has pursued various acquisition opportunities, the most
advanced of which did not proceed after the vendor’s partner exercised its pre-emption
The value of Wentworth is substantially impacted by the present value of its G&A costs.
Historic G&A costs do include the costs of acquisitions which did not complete.
However the significant majority of the costs relate to maintaining a substantial
presence in Tanzania, which, in the opinion of the Board, is required to maintain
Wentworth’s good standing in Tanzania, as well as the costs of maintaining Wentworth
as a well governed quoted entity. The Board has regularly considered stripping back
the costs of the business, either to the bare minimum to function as a quoted company
or as a private company. However, when considered in depth, the Board has not been
able to satisfy itself that the outcome would result in greater cash returns than that
offered by the Acquisition and could lead to reduced investor appeal resulting in an
erosion of value for shareholders. The Board believes that the most appropriate way
to realise the value of the asset is for the asset to form part of a larger business. The
Acquisition is expected to deliver substantial synergies for M&P, but those potential
synergies exist only because M&P is Wentworth’s partner in the Mnazi Bay asset.
Wentworth cannot access those synergies itself, nor can Wentworth offer all of those
synergies to a third party acquirer, particularly when M&P has extensive direct and
indirect pre-emption rights over the asset.
Wentworth now expects to publish the scheme document in connection with the Acquisition
on 25 January 2023 which will contain the full terms and conditions of the Acquisition together
with notices of the Court Meeting and the General Meeting (expected to be held on 23
February 2023), the expected timetable of the Scheme, and will specify the action to be taken
by Wentworth Shareholders.
Wentworth management intends to hold investor meetings in the UK and Norway with
shareholders ahead of the Court Meeting and the General Meeting. Wentworth invites
shareholders to submit questions to email@example.com to permit these to be addressed. If you
would like to participate in physical meetings please also submit your name, shareholding and
preferred location and the Company will attempt to facilitate meetings, where practicable.
Further detail will be provided in due course.
Tim Bushell, Chairman of Wentworth, said:
“The Board believes that the Valuation underlines its view that the terms of the Acquisition are
fair and reasonable, not least given the substantially lower revenues expected in 2023 due to
the depletion of the historic cost pool. Furthermore, material capex is required to maintain, let
alone increase, production at the Company’s only non-cash asset.
“The Acquisition represents a substantial 62% premium to the share price at the time of the
offer when adjusted for cash and is a material increase to M&P’s initial indicative offer prices.
This is reflected by the support from longstanding shareholders representing over 22% of the
“Wentworth recommends that Shareholders vote in favour of the Acquisition to enable them
to realise the future value potential in the near-term for cash without further capital
expenditure, operational risk and time.”
Wentworth yesterday made this detailed announcement in the takeover process which makes for interesting if not surprising reading when the totality of the process is taken into account. The bid at 32.5p in cash from Operator Maurel & Prom is recommended by the WEN board who value the business at between 24.8-27.9p per share and is therefore at a 62% premium as noted by the Chairman above.
As I see it, whilst I have been a huge fan of both WEN and the Mnazi Bay asset, the Board are not able to recommend anything except the cash on offer from M&P. This is for a number of reasons, firstly the fact that M&P operate the asset and accordingly decide upon the level of investment which in itself will inevitably feed through to WEN ‘s ability to generate cash and distribute to shareholders.
The key word above is Operator as M&P are in charge of the Mnazi Bay numbers, more importantly the Cost Recovery Programme which we know will be re-examined in 2023. JV costs of some $45m, of which $15m is net to Wentworth mean that for pretty much certain revenues this year will be lower, possibly substantially lower as warned by the Chairman above.
Remember that this has hitherto been a benefit to WEN, some $300m of historic costs have already been recovered from the pool which has in itself contributed to the company’s financial strength and with it the ability to distribute to shareholders.
There is also the overall M&A situation to bear in mind in which WEN are in a somewhat difficult situation especially given pre-emption rights held by M&P at Mnazi Bay. WEN have been increasing distributions to shareholders in the last couple of years as complementary acquisitions proved to be difficult to find and even when trying to buy out Scirocco that proved pointless as they were pre-empted there too.
So, with the opportunity to buy M&P out of Mnazi Bay a definite non-runner and any deal to sell almost certainly to be taken in-house by M&P I think that the market have not borne in mind how the basic economics could be adversely affected from this year forwards.
The dividend and of course share buy-backs are great with previous numbers but not with reduced revenue entitlement as a result of eating through the cost pools. Remember it was an unsolicited approach and the Board have extracted as much value from M&P as possible by increasing the offer materially above the original unsolicited offers which is why I have come to the conclusion that maybe reluctantly, the board have advised that it is an offer they must advise shareholders to accept
Afentra has provided the following update regarding the previously announced Angolan acquisitions.
Approval of INA Acquisition
Afentra is pleased to announce that it has received approval from the Ministry of Mineral Resources, Oil and Gas for the acquisition from INA-Industrija d.d. (“INA”) of a 4% interest in Block 3/05 and 4% interest1 in Block 3/05A offshore Angola pursuant to a sale and purchase agreement between INA and Afentra’s wholly-owned subsidiary, Afentra (Angola) Ltd, dated 19 July 2022.
The Company is now working with INA to finalise the formal completion of this acquisition.
Sonangol SPA extension
Afentra can now confirm that it has agreed with Sonangol to extend the long-stop date from 31 December 2022 to 31 March 2023.
We look forward to providing shareholders with further updates in due course.
Commenting on the update, CEO Paul McDade said:
“The receipt of approval from the Ministry of Mineral Resources, Oil and Gas for the INA Acquisition is a key step in this process and we now look forward to completing the acquisition in the coming weeks. It will mark our entry into Angola and the first of two highly complementary acquisitions that will provide Afentra with a strong growth platform, underpinned by robust cash flow and significant potential to deliver upside value. It will also mark the inception of our partnership with Sonangol in Blocks 3/05 and 3/05A where we intend to work closely with Sonangol to optimise production and to extend the life of this quality, long-life asset.”
Very good news today from Afentra, not just the Ministry approval in itself but also ANPG, the regulator, who also wished to make a public statement which I know that the company take as an indication that they consider Afentra an important, new investor in Angola.
I have decided that Afentra should make its debut in the new Bucket list which will be published very soon. Not only as they stand on the crest of entry into Angola but also as its high quality management, whom I rate very highly indeed, will I think bring a whole host of opportunities for shareholders.
Pharos has issued the following trading and operations update to summarise recent operational activities and to provide trading guidance in respect of the financial year to 31 December 2022. This is in advance of the Company’s Preliminary Results on 22 March 2023. The information contained herein has not been audited and may be subject to further review and amendment.
· Group working interest 2022 production 7,166 boepd net 1 (2021: 8,878 boepd net, 7,533 boepd net on a comparative basis1), in line with production guidance;:
– Vietnam production 5,418 boepd net (2021: 5,560 boepd net)
– Egypt production 1,748 bopd 1 net (2021: 3,318 bopd; 1,973 bopd on a comparative basis 1)
· In Vietnam, work on submitting Revised Field Development Plans (RFDPs) for two wells on TGT and one on CNV for the 2023 work programme is progressing, with all wells remaining in contingent budget until approval
· Interpretation work on the 3D Seismic in Block 125 is continuing and showing promising results. Application for extension to Block 125/126 licence submitted as no suitable rigs available for drilling in 2023
· In Egypt, seven wells were put on production in 2022, plus one additional well drilled in Q4 2022 and awaiting completion
· Multi-well development drilling programme continues in 2023, two drilling rigs commenced drilling new wells in El Fayum
· Request for a short extension on North Beni Suef (NBS) granted, with work on a further extension request underway
· Net Zero commitment on all assets by 2050, detailed roadmap coming in 2023
· Group revenue for 2022 was c.$222m before hedging loss of c.$23m (2021: $163.8m before hedging loss of $29.7m)
o Vietnam revenues for the year c.$185m
o Egyptian revenues for the year circa $37m 2
· Cash balances as at 31 December 2022 were approx. $45m; net debt c.$29m (2021: cash balances $27.1m; net debt $57.5m)
· Completion of the initial $3m share buyback programme, with a further $3m committed for 2023
· Recommending recommencement of regular dividend payments starting in 2023, subject to shareholder approval at AGM 2023, as announced at Interim Results announcement in September 2022
· Group working interest 2023 production guidance 6,050 – 7,500 boepd net:
– Vietnam 2023 production guidance 4,700 – 5,700 boepd net
– Egypt 2023 production guidance 1,350 – 1,800 bopd net (equivalent to gross production of 3,000 – 4,000 bopd)
· Forecast cash capex for 2023 is expected to be c.$38m (c.$23m after Egyptian carry by IPR)
1 The farm-down transaction and transfer of operatorship of Pharos’ Egyptian assets to IPR completed on 21 March 2022. Working interest production for Egypt in 2022 is therefore reported as 100% through to completion and 45% thereafter. The comparative basis for 2021 also assumes 100% working interest until 21 March 2021 and then 45% for the remainder of the year.
2 Egyptian revenues are given post government take including corporate taxes.
Production in 2022 from the TGT and CNV fields net to the Group’s working interest averaged 5,418 boepd (2021: 5,560 boepd). This is in line with the 2022 production guidance.
TGT production averaged 13,784 boepd gross and 4,089 boepd net to Pharos (2021: 13,887 boepd gross and 4,120 boepd net). CNV production averaged 5,317 boepd gross and 1,329 boepd net to Pharos (2021: 5,762 boepd gross and 1,440 boepd net).
Vietnam production guidance for 2023 is 4,700 to 5,700 boepd net.
Vietnam Development and Operations
On Block 16-1 – TGT Field, the drilling programme for two development wells completed in H2 2022, on time and under budget. The first well, H1-35P, commenced production on 21 October 2022, and the second well, 11XPST, commenced production on 10 November 2022.
Additionally, the JOC continues to execute an active well intervention and data-gathering programme on TGT to further optimise production.
On Block 9-2 – CNV Field, one development well, CNV-2PST1, started drilling in H2 2022 and is anticipated to be completed by the end of January 2023.
For the 2023 work programme, the JOCs are working towards submitting Revised Field Development Plans (RFDPs) for two wells on TGT and one on CNV, with all wells remaining in contingent budget until approval by partners and the Ministry of Industry and Trade (MOIT). Production guidance has assumed no contribution from these wells in 2023.
Discussions with our partners PTTEP and PVEP are ongoing to finalise the official licence extension request, which will be submitted to PVN for their approval prior to being put to the Prime Minister for final assent.
On Block 125, the 3D seismic processing is complete and the ongoing interpretation of this data has resulted in the mapping of a variety of world class Prospects in this relatively unexplored basin, with further work needed to refine them into “drill-ready” status.
The analysis of the 2D seismic shot in 2019 indicated prospectivity in both the shallow and deeper water, and the ongoing interpretation of the 3D has highlighted greater prospectivity in the deeper water section given the scale of the Prospects identified.
We had planned to drill a well on this block in 2023 but the current focus on the deeper water means that a drillship is needed to drill this well and we have been unable to source one for 2023 on acceptable terms. We have therefore submitted an application for an extension of the PSC and plan to drill a well in Q2/Q3 2024.
We will use the time to optimise drilling locations and well planning for this deeper water well, to source a drillship and other long-lead items and to find a partner to support the funding of this well. A number of parties have expressed interest and have been invited to review data. Discussions are ongoing.
El Fayum Production,
The transaction with IPR and transfer of operatorship completed on 21 March 2022. Working interest production in 2022 is therefore reported as 100% through to completion of the farm-down and 45% thereafter.
Production for 2022 from the El Fayum Concession averaged 3,128 bopd gross and 1,748 bopd net to Pharos. This is in line with the 2022 production guidance.
Egypt production guidance for 2023 is 1,350 – 1,800 bopd net (equivalent to gross production of 3,000 – 4,000 bopd).
El Fayum Development and Operations
Multi-well development drilling in El Fayum continues in 2023, with nine wells planned for the year. Seven wells were put on production in 2022 (including one well drilled in 2021), and one additional well drilled in Q4 2022 is and awaiting completion in Q1 2023.
Two drilling rigs have commenced drilling new wells in El Fayum. The second rig, which was secured on a long-term contract in July 2022, started drilling in December 2022, allowing a short period of overlap between two rigs.
Additionally, two workover rigs are on field to contribute to production through low-cost well repairs, recompletions, and deployment of water injection.
El Fayum Exploration
As part of the planned work programme in 2023, two commitment exploration wells are expected to be drilled in the El Fayum Concession. These two Satellite exploration wells are planned to target two separate structures near existing producing fields with primary reservoir targets in the Abu Roash G and Upper Bahariya formations. We are working closely with IPR to progress well planning and optimise drilling schedules.
North Beni Suef (NBS)
Drilling of a commitment well in NBS was deferred to 2023 with the granting of a short extension, thus allowing additional time to fulfil our commitment to drill this well by March 2023. The Company also plans to drill an additional commitment exploration well in NBS, the timing of which is dependent on rig availability schedule and negotiations for an additional extension of the exploration period until September 2023.
Several prospects have been identified from the existing 3D seismic and c.110 km2 of additional 3D seismic is planned to be acquired in H1 2023.
The Company entered 2022 with cash of $27.1m and net debt of $57.5m. Cash balances as at 31 December 2022 were approx. $45m and net debt was c. $29m.
The recent global macroeconomic volatility has seen both a significant devaluation of the Egyptian Pound and continued restrictions on outgoing US Dollar (USD) transfers by the Central Bank of Egypt. As noted in previous updates to the market, Pharos have opted not to accept the payment of our receivables balance in Egyptian Pounds (EGP) unless required for operations. The progressive devaluation of EGP against USD means that it is preferable to continue to hold USD denominated receivables. As a result, Pharos’ receivables have increased to $24.2m (which includes the c.$7m catch-up invoice for improved fiscal terms) at 31 December 2022 (2021: $7.4m).
The International Monetary Fund (IMF) recently announced that its Executive Board had approved the provision of a $3 billion, 46-month extended fund facility to Egypt, which the IMF expects to catalyse additional financing of approximately $14 billion from Egypt’s international and regional partners. In addition, Egypt is seeking access to up to a further $1 billion from the IMF’s newly created resilience and sustainability facility to support climate-related policy goals. Taken together, these developments are widely anticipated to improve Egypt’s FX reserves and overall liquidity in H1 2023. We therefore remain optimistic that outstanding receivables with EGPC will start to be recovered during 2023.
In the event of continued delays in our El Fayum invoices being paid, we have access to our revolving credit 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 31 December 2022 was $9.2m, which is included in our net debt calculation. We recently agreed with NBE to extend the current $18m facility on the same terms to 31 March 2024. We 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. We will keep under review the receivables position in Egypt which may impact the capital available for development.
Group revenues for full year 2022 were c.$222m prior to a hedging loss of c.$23m. The revenue includes $7m from Egypt due to the Third Amendment to the El Fayum Concession Agreement, as announced in our Preliminary Results on 16 March 2022. The average realised oil price per barrel achieved for Vietnam was c.$106/bbl representing a premium of just over $4/bbl to Brent and for Egypt was approx. $96/bbl, representing a discount of approx. $5/bbl to Brent.
The H1 2023 premium for TGT crude in Vietnam has been agreed at $8.00/bbl, a significant increase over the H2 2022 premium of $5.65/bbl (H1 2022: $3.13/bbl). The H1 2023 premium for CNV crude has been agreed at $7.88/bbl, significantly higher than the H2 2022 premium of $5.09/bbl. This highlights the increased competition and demand for the high quality crude being produced from both Vietnam fields.
Overhead reduction remains an ongoing focus for the Group. We restructured the Egyptian business with a reduction in the underlying cost base in March 2022, following the farm-down and transfer of operatorship to IPR. In addition, we reshaped the Board structure with a reduction in the number of Board members from nine to six and continue to evaluate further cost efficiencies.
For full year 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 December 2023 and are settled monthly. The majority of hedged production volumes (61%) were in H1 2022, leading to realised losses of $17m out of total realised losses of $23m for the year, in order to meet requirements under the RBL and also going concern and working capital tests in relation to the Egypt farm-down deal.
For 2022, 30% of the Group’s total production was hedged, securing an average realised price for the hedged volumes of $73.1/bbl. The Group’s reserve based lending facility (RBL) requires the Company to hedge at least 35% of Vietnam RBL production volumes and the current hedging programme meets this requirement through to December 2023, leaving 71% of Group production unhedged.
Please see below a summary of hedges outstanding as at 31 December 2022.
Production hedge per quarter – 000/bbls
Min. Average value of hedge – $/bbl
Max. Average value of hedge – $/bbl
The December redetermination process under the RBL has now completed with a principal repayment of $12.9m made in December 2022 and the amount drawn currently stands at $64.9m.
The RBL loan, which is only over Vietnam producing assets, matures in July 2025. The facility amount is amortised by $14.2m, every re-determination, from 1 July 2022, with a facility amount as at 31 December 2022 of $85.75m, which decreased to c. $71.5m from 1 January 2023 and will decrease further to $57.3m from 1 July 2023. The Group is able to dividend up from the Vietnam RBL zone to the Plc twice a year in January and July following approval of the redetermination.
The Debt Service Reserve Account (DSRA) was put in funds of $18.5m on first business day of 2023 to service the principal repayment for half year 2023 plus interest.
Portfolio management & capital allocation
The Board remains focused on optimising its asset portfolio and is driven by its duty to deliver value to shareholders, which is achieved through share price accretion and returns of capital by ways of dividends and share buybacks. The Board maintains an active approach to timely asset portfolio management, taking into account the return on capital, cash generation potential, costs, growth and strategic fit of each asset in the current portfolio in light of the overriding focus on generating value for shareholders.
Capital discipline and regular shareholder returns are core elements of our overall shareholder offering, and we note their importance for investors. The Board is pleased to recommend the recommencement of regular dividend payments starting in 2023, returning no less than 10% of Operating Cash Flow (OCF). The first dividend will be a final dividend for the 2022 financial year and will be paid in full in July following approval of the shareholders at the Company’s AGM in 2023 as announced in September 2022.
Share buyback programme
Following the initiation of a share buyback programme to purchase $3m (excluding stamp duty and expenses) of the Company’s ordinary shares in July 2022, we are pleased to announce the completion of this programme. A total of 10.3 million shares were bought, at a daily average price of 24.4p.
The Board believes that the Company’s shares are still trading at a material discount to their underlying net asset value, despite the performance across the Group’s asset base, and the Board remains of the view that a continuation of share buybacks is an appropriate means of returning value to shareholders at this time. Therefore, the Company will be looking to continue with the share buyback programme in 2023, with a further $3m (excluding stamp duty and expenses) committed as of today. This extension of the programme (the Programme Extension), is expected to commence immediately.
Purchases of ordinary shares under the Programme Extension will initially be made under the existing authority of the Company to purchase its own shares approved by shareholders at the Company’s 2022 annual general meeting (AGM). This authority will expire at the conclusion of the Company’s 2023 AGM, expected to be held in May. The Company intends to seek a renewal of the authority at the 2023 AGM in customary terms. Accordingly, if the Programme Extension has not been completed by the date of the 2023 AGM, its continuation will be subject to the passing of the resolution to renew the authority.
As with the initial share buyback programme announced in July 2022:
· the Programme Extension will be conducted in compliance with European Union (EU) Regulation No 596/2014 (MAR) and the MAR buyback technical standards (Commission Delegated Regulation (EU) 2016/1052) (the Technical Standards), both of which form part of Retained EU Law as deﬁned in the European Union (Withdrawal) Act 2018;
· the Company will not seek to rely on the safe harbour conditions for trading set out in Article 3(2) and Article 3(3) of the Technical Standards, given the limited liquidity in its ordinary shares and the limitations that the conditions would impose on the number of shares that can be purchased;
· ordinary shares purchased under the Programme Extension will be cancelled; and
· Peel Hunt LLP, the joint broker to Pharos, will manage the Programme and carry out on-market purchases as principal, with the authority to enact purchases and make trading decisions concerning the timing of the purchases independently of the Company.
Details of any and all purchases made under the Programme Extension will be provided via RNS announcements and published in the regulatory news section of the Company’s website.
Our producing assets continue to deliver strong cash generation. In Vietnam, we are looking to enter a new phase with discussions on licence extension requests ongoing and in Egypt, where we continue to benefit from a full carry for the first half of the year, IPR has committed to a programme which will add new wells to the production base. This has allowed us to commit to regular ongoing returns to shareholders, as part of our annual capital allocation plans.
Debt levels continue to reduce, and we have limited commitments over the asset base, giving us a strong foundation to work from. Finally, the opportunity which we have in our Exploration Block in Vietnam is unique and significant effort will be spent this year in concluding the analysis, planning the well and bringing in the right partner.
Jann Brown, Chief Executive Officer, commented:
“2022 saw strong cash generation, allowing us to make returns to shareholders through a share buyback programme which will now be extended with a further $3m allocated. We are also fully aware of the importance of regular dividends to much of our investor base, and look forward to making the first payment under the dividend policy announced in September as a key part of our overall commitment to returning value.
Our asset investments are made where we can generate a combination of near-term cash flow and longer-term value from our portfolio. In Egypt, we continue to engage with IPR as the Operator to optimise the work programme of both the El Fayum and the North Beni Suef Concessions and we remain fully carried for the first part of the year. In Vietnam, we are focused on sustaining cash generation through development drilling, and further work to enhance value is ongoing. On the TGT and CNV production licences, we are working with partners to refresh our field development plans and extend licence periods. Finally, the scale of the opportunity on Block 125 is becoming clearer as more work is done on it and we are pushing forward with the plans for drilling here, now expected to be in 2024.”
This is an extensive statement from Pharos who have much on their plate in both Egypt and Vietnam, the latter being the way forward to growth in the long term. With a detailed analysts presentation next week I will add more after that but all is going well, albeit a bit slowly.
United Oil & Gas
United Oil & Gas has announced the results of an independent contingent resources audit conducted by Gaffney, Cline & Associates Limited on the Maria Discovery, in Licence P2519, located in the UK Central North Sea. United holds a 100% working interest in the licence.
– Mid-case 2C gross contingent resources for the Forties and Dornoch reservoirs of the Maria discovery are estimated at 6.3 mmbbls and 23.3Bcf (10.2 mmboe)
– The range of resources estimated at Maria ranges from 3.3 mmbbls and 13.2 Bcf (5.5 mmboe) in the 1C case to 11.1 mmbbls and 39.3 Bcf (17.7 mmboe) in the 3C case
Gross Field Contingent Resources Summary Table (as at 31st December 2022)
UOG calculated Boe (mmboe) (1)
Source: Gaffney, Cline & Associates Limited. (1) conversion factor 6 Bcf = 1mmboe.
United Chief Executive Officer, Brian Larkin commented:
“The independent audit further validates the work produced by our inhouse technical team, providing an independent mid-case estimate of 10.2 mmboe contingent resources at the Maria discovery. The report highlights the value of our 100% interest in this late stage appraisal and development asset that has the potential to deliver significant near term value to our shareholders. We are making good progress on potential options to maximise shareholder value from this licence and will provide further updates in due course.”
UOG are due a bit of good news and this data from Maria shows that the company is more than just a one-trick pony. Maria has looked like an interesting play to me for a while and I look forward to seeing its progress.
Last night in the Haribo Cup Forest beat Wolves on pens and the Saints pulled off a splendid win over the Noisy Neighbours. In the semis they will play the Magpies and Forest get the Red Devils.
Tonight in the Prem the Cottagers welcome Chelsea, they probably think that it is their best chance of a victory in the Fulham Road derby for some time.