WTI (Aug) $102.60 +$5.01, Brent (Sept) $106.27 +$5.11, Diff -$3.67 +10c, USNG $7.47 +45c, UKNG (Aug) 198.62p -1.67p, TTF (Aug) €159.60 -€8.10

Oil price

A couple of better days to remind punters that the fundamentals are tight and that there’s nothing coming from Opec until 3rd  August even possibly not then. The Fed went into purdah yesterday ahead of next week’s interest rate decision, the greenback actually weakened as expectations of a 100bp rise were trimmed.

Retail gasoline prices continue to drift short term, yesterday it was $4.49 per gallon which is down 15.6 cents w/w, a fall of 47.0c m/m and of course a rise of $1.337 y/y.

It seems like the Kremlin are playing hardball on gas again, Thursday is a key day with respect to Nordstream 1, expect nothing and you won’t be disappointed.

Challenger Energy Group

Challenger has provided the following update on its Trinidad and Tobago business unit’s operating results for Q2 2022:

• Total gross oil production for Q2 2022 was 34,159 barrels equating to approximately 375 barrels of oil per day (bopd), representing an approximately 6% increase over Q1 2022 (358 bopd).

The increase in average daily gross production is principally attributable to a focused effort on maintaining baseline production. It is noted that the Company’s 2022 work program, which is focused on near-term production enhancement activities (as announced in RNS dated 7 June 2022) is to be executed in phases over the coming months, and thus the expected impact of this work on production is not yet reflected in the production rates achieved during Q2 2022.

It is further noted that notwithstanding the increase in total oil production, the quarterly result was adversely impacted by especially severe torrential rains in the last two weeks of June 2022, which caused several days of downtime due to electrical failures and safety-related total field shut downs.

• Total oil sales in Q2 2022 amounted to 31,170 barrels, representing approximately a 5% increase over Q1 2022, with a gross realised average price per barrel sold of US$97.45, representing approximately a 17% increase over Q1 2022.

As noted above, especially severe weather conditions were experienced in the last two weeks of June 2022, and resulted in the Company being unable to deliver approximately 800 barrels of oil for sale prior to the close of the second quarter. However, this unsold inventory will be realised early during Q3 2022. 

• Revenue received by the Company from oil sales (being gross revenues less Government royalties and mandatory source deductions and adjustments applicable under the relevant licences)1, amounted to approximately US$1.4 million in Q2 2022. This represents average net revenue to the Company of US$45.15 per barrel sold, an approximately 15% increase over Q1 2022.
• In total, the Company’s operations in Trinidad and Tobago generated an (unaudited) pre-tax operating cash surplus in Q2 2022 of approximately US$0.4 million (Q1 2022: US$0.2 million). This surplus is stated after field operating costs, in-country G&A and other Trinidad expenses, but before corporation and other taxes (including supplemental petroleum tax, where applicable). It is noted however that, given the extent of carry-forward tax losses in Trinidad and Tobago, the Company is currently largely shielded from corporation taxes.

Eytan Uliel, Chief Executive Officer of Challenger Energy, said:
“Everyone in the Challenger Energy team continues to work on driving our production business in Trinidad and Tobago forward, and the results of the second quarter of 2022 represent steady improvements across the board – as compared to the first quarter production was up, oil sales were up, and cash flows being generated in-country have increased. It is also important to note that these results are due to a dedicated focus on managing the Trinidadian asset portfolio prudently and efficiently, and do not yet reflect any of the additional production we hope to realise from our planned 2022 work programme, which as advised in June will be rolled out across the second half of 2022. I therefore look forward to reporting further progress in the coming months, as we begin executing our planned work for the remainder of the year.”

CEG continues to get Trinidad operationally under control with ‘steady’ increases in production from the portfolio leading to better cash flows. As CEO Eytan Uliel says above this is just a precursor to the work programme being rolled out in 2H 2022 and should see better growth. 

Patience is a virtue and I know that the team at CEG are confident about the future in Trinidad but there is also the attraction of the position in Uruguay, applied for some two years ago but only recently awarded and now validated by the arrival of Shell and APA next door.

This well and truly puts CEG in with the big boys as they believe that the broader offshore Uruguay play system to be analogous to the recent prolific, conjugate margin discoveries made offshore Namibia by TotalEnergies and Shell, where reported multi-billion-barrel Cretaceous turbidite reservoirs have been encountered. The AREA OFF-1 licence exhibits the same Aptian play source rock and petroleum systems being present.

At present the Challenger share price reflects the past, with its baggage we all know about, I think that when it starts to look forward then investors will find that value in the company is potentially substantial. 

Angus Energy

Angus yesterday announced completion of almost all electrical connections and all instrument connections excepting storage and drain areas.  Moreover input/ output testing between the control computer or SCADA and each of the site’s  80+ instruments and actuated valves which that SCADA governs is complete.

Input/ output testing on the remaining electrically powered systems including re-boilers, switchgear, air compressors and lighting is expected to conclude on Wednesday (20th July) when system-wide testing of the SCADA begins.

We expect to introduce live gas as far as the test separator on Friday (22nd July) as part of the commissioning schedule and will advise further on a precise date for export and nominations thereafter.

They also made it clear that they ‘reiterated guidance from 12th July that anticipated production during Q3 comfortably exceeds hedge amount as advised’. There are always some small bumps in the road, it seems to me that all is going just fine with Saltfleetby.

Afentra

Afentra has announced that its wholly-owned subsidiary, Afentra (Angola) Ltd, has signed a Sale and Purchase Agreement with INA – Industrija Nafte, d.d. to acquire a 4% interest in Block 3/05 and a 5.33% interest(1) in Block 3/05A, offshore Angola. This transaction builds upon the acquisition of a 20% interest in Block 3/05 from Sonangol announced in April 2022. The INA Acquisition has an effective date of 30th September 2021.

Transaction Highlights:

·      Strategic Rationale – Incremental acquisition builds upon Afentra’s strategic entry into Block 3/05, a mature, shallow water, production asset with material upside

·      Block 3/05 – Acquisition results in a combined equity ownership of 24%(2) 

o  Initial consideration of $9 million

o  Additional consideration of $10 million, payable upon licence extension(3)

o  Contingent consideration of up to $6 million over 3 years, subject to certain oil price hurdles and an annual cap of $2 million

·      Block 3/05A – Acquisition of 5.33% interest in a license adjacent to Block 3/05, providing the opportunity to tie back existing discoveries to the Block 3/05 infrastructure

o  Initial consideration of $3 million

o  Contingent consideration of up to $5 million linked to the successful future development of certain discoveries and oil price hurdles

·      Combined Interests – the INA Transaction and the previously announced Sonangol Acquisition are expected to be financed through new debt facilities and existing cash, discussions with selected debt provider are well advanced

o  Combined 2P reserves of ~24 million barrels and production of ~4,680 bbl/day

o  Overall low-cost entry with implied acquisition cost of ~$4/ 2P bbl4

o  Attractive asset breakeven economics of $35/bbl

o  Average net FCF after capex of ~$35 million p.a. @ $75/bbl over next 5 years

o  Payback in less than 3 years at ~$75/bbl based on 2P production alone

Transaction Overview
Further to the RNS issued on 28 April 2022, in which Afentra announced that it had signed an SPA with Sonangol to purchase interests in Block 3/05 and Block 23, offshore Angola, the Company is pleased to announce an attractive acquisition from INA, of a further 4% non-operated interest in Block 3/05 and entry into adjacent Block 3/05A with the acquisition of a 5.33% non-operated interest.

The acquisition will take Afentra’s combined interest in Block 3/05 to 24%2 with a combined implied acquisition cost of ~$4/ 2P bbl4 and asset breakeven costs of $35/bbl. Block 3/05 production averaged 19,500 bopd in the first half of 2022 and has material production growth potential. Upon completion of both the Sonangol and INA transactions, Afentra will have initial 2P Reserves of c.24 million barrels (20 and 4 mmbo respectively) and daily production of c.4,680 bbl/d. (3900 and 780bopd respectively).

The asset interests being acquired under the INA Transaction generated an EBITDA of US$ 5.3 million for the year ended 31 December 2021, as extracted from unaudited management information for the year, with EBITDA being defined as “earnings before interest, tax, depreciation and amortisation”.

Block 3/05, in which Afentra is acquiring a further 4% non-operated interest, is located in the Lower Congo Basin and consists of eight mature producing fields. The discoveries were made by Elf Petroleum (now part of TotalEnergies) in the early 1980s. Development was by shallow-water (40-100m) platforms that included successful waterflood activities with first oil in 1985. Sonangol assumed operatorship from 2005 and has focused on sustaining production through workovers and maintaining asset integrity. No infill drilling campaigns have taken place in the last 15 years. The asset has a diverse portfolio of over 100 wells and currently produces from around 40 production wells and has nine active water injectors. The facilities include 17 well-head and support platforms and four processing platforms, with oil exported via the Palanca FSO.

The entry into Block 3/05A also provides Afentra with access to existing light oil and associated gas discoveries that could be tie-back developments to the existing Block 3/05 infrastructure. Block 3/05A contains an oil in place of ~300 mmbls, including one partially developed and two un-developed oil discoveries. There is potential for material incremental gross production of circa 10,000 bbl/d.

Both 3/05 and 3/05A provide scope for broad based ESG impact in the form of emissions reduction, gas utilisation opportunities and positive socio-economic impacts. Consistent with Afentra’s purpose and strategy, Afentra will be working alongside Sonangol to support its transition strategy which is closely aligned with Afentra’s ESG agenda. A key outcome of the due diligence work to date has been to identify the opportunity to work with the JV to enhance the environmental performance of Block 3/05 through emissions reductions.

The acquisition of the assets from INA is expected to be funded through the same debt and existing available funds as those being utilised for the Sonangol transaction and discussions with the selected debt finance provider are well advanced and will be finalised ahead of re-admission.

Transaction Timings and RTO Update
The INA Acquisition is subject to satisfaction of Conditions Precedent customary for a transaction of this nature which mainly relate to Governmental approvals and waiver of state pre-emption rights, these are expected in Q3/Q4 2022.The licence extension of Block 3/05 which will trigger the incremental payment of $10 million is also expected to be granted in Q3/Q4 2022.

The ongoing Sonangol transaction and associated RTO process, with publication of the AIM re-admission document and resumption of trading is expected to occur in the coming weeks.  The General Meeting to approve the Sonangol Acquisition will follow in line with regulatory timelines.

• Subject to final approval of the distribution of the CSI interest to the remaining joint venture partners
• Subject to completion of the Sonangol Acquisition and the INA Transaction
• License extension from 2025 to 2040 applicable to Block 3/05. Current license for Block 3/05a expires 2035
• Afentra Gross 2P estimate of 100 mmbo as at 1/1/2022 and $102mm combined firm payment
• EBITDA – earnings before interest, tax, depreciation, and amortisation

Transaction Presentation

A presentation providing further details of the INA transaction has been uploaded to Afentra’s website and can be viewed via the following link:

https://afentraplc.com/wp-content/uploads/2022/07/Afentra-Second-Acquisition-final.pdf

Commenting on the update, CEO Paul McDade said:
“This incremental acquisition is strategically attractive as it enhances the materiality of our entry into Angola and provides additional exposure to proven assets with significant upside. Block 3/05 is a high-quality asset with stable and robust cash flow and material production growth potential. The acquisition of an additional 4% demonstrates our commitment to both the asset and our plan to work with the operator, Sonangol, to maximise the production and recovery from this material asset for the benefit of all stakeholders.

Together, the Sonangol and INA transactions provide a solid foundation for Afentra’s growth in Angola, and elsewhere within Africa, our geographic focus. They also demonstrate the significant opportunities that exist in the region, for a responsible and ambitious independent like Afentra, that are resulting from the transition that is ongoing in the oil and gas industry in Africa.”

This is excellent news from Afentra, I had sort of expected a little more being added and this just makes the first deal even better. Production of c. 4680 b/d and net 2P of 24m barrels is priced at c.$4/2P barrel and with breakeven of $35/bbl pays back in under 3 years. Hopefully it won’t be long now before the deal completes, the shares return and investors will be highly rewarded. 

Hurricane Energy

Hurricane has provided an update on Lancaster field operations and net free cash balances as of 30 June 2022.

Lancaster Field Operations Update

The following table details production volumes, water cut and minimum flowing bottom hole pressure for the 205/21a-6 (“P6”) well during June 2022.

June 2022 Lancaster Field Data

1. The 205/21a-7z ("P7z") well was not on production during June 2022
2. Expressed as total water produced divided by total fluid (oil and water) production
3. Pressure reported is the monthly minimum from well downhole gauges.

As of 16 July 2022, Lancaster was producing c.8,650 bopd from the P6 well alone with an associated water cut of c.46%.

There was no lifting of Lancaster crude in June. The next cargo is anticipated to be lifted later in July 2022.

Financial Update
As of 30 June 2022, the Company had net free cash(4) of $127 million compared to the last reported balance of $139 million as of 31 May 2022. $78.5 million of Convertible Bonds remain outstanding and are due to be repaid by 24 July 2022. Following the repayment, assuming oil prices remain at over $90/bbl, at the end of July the Company is forecasting to be holding net free cash in excess of $75 million. If oil prices for the July cargo are above $110/bbl, the net free cash forecast increases to be above $85 million.

4.Unrestricted cash and cash equivalents, plus current financial trade and other receivables, current oil price derivatives, less current financial trade and other payables.

Following the repayment of the Convertible Bond, the Company intends to reduce the frequency of its production and financial updates to quarterly rather than monthly, being more in line with standard industry practice.

Antony Maris, CEO of Hurricane, commented:
“With another steady month of production, we now look beyond repayment of the bonds with a strong cash position and balance sheet. We believe that there are good investment opportunities ahead and the Company is well placed to deliver significant shareholder value.”

There is little that I can add to my usual monthly comments about Hurricane, the abundant free cash flow will pay off the convertible this week, the judge from the trial will be congratulating himself on his perspicacity as will the shareholders. But at the current level of 7.5p the shares are a snip and the upside from here is potentially huge. 

Predator Oil & Gas

Drilling and operations update

Highlights    

• MOU-1 step-out well MOU-2 to target 295 BCF net Contingent Resources
• Unrisked NPV US$592 million
• MOU-2 well pad construction will commence this month
• September – October drilling schedule
• Targeting 110 metre potential gross reservoir interval in Moulouya (“MOU-4”) Fan
• Planning for extended production test for early CNG sales and gas revenues
• Memorandum of Understanding for Gas Sales Agreement and leasing of CNG equipment being discussed

Predator Oil & Gas Holdings Plc (PRD), the Jersey-based Oil and Gas Company with operations in Morocco, Ireland and Trinidad is pleased to announce a drilling and operations update.

Guercif Drilling Programme

Current status
The Company is in the process of completing local permitting for the second of two alternative locations for the step-out well to the MOU-1 well which was completed for rigless testing in 2021. The final location will be agreed following the integration of reprocessed 2D seismic data that have recently been received. Civil engineering works will commence this month to construct the well pad for the step-out well now designated MOU-2.

Long lead equipment including well heads, casing, cement, chemicals, drill bits mud motors and downhole tools as well as mud and cementing services have been sourced out of the UK, France, USA, Canada, Egypt and the Netherlands.

The well is anticipated to be drilled and completed for rigless testing between September and October this year. The drilling window will be updated as well inventory arrives in Morocco from overseas. Star Valley Rig 101 is prepared to commence drilling operations on instructions from the Company.

The geological well programme and drilling programme are currently being updated.

Well objectives
The well will test the Moulouya Fan, previously designated the “MOU-4 Fan”. The extreme western feather edge of the Moulouya Fan was penetrated in MOU-1 located approximately 8 kms. to the southeast of the new step-out well. MOU-1 established the presence of gas in the target section and confirmed an over-pressured mudstone seal. Post-well seismic ties validated a seismic amplitude signature for the MOU-4 Fan covering an area of greater than 30 km²

MOU-2 will test the core of the Moulouya Fan in a shelf slope position where seismic signatures indicate the presence of major channel systems. The well will provisionally be drilled to 1,500 metres TVD KB and is expected to encounter the top of the Moulouya Fan between 1,130 and 1,200 metres TVD KB. At this location the well will be targeting a gross potential Moulouya Fan reservoir sequence of 110 metres. The potential for multiple gas-water contacts may exist as is the case in the Anchois discovery and appraisal wells. However at this well location there is little seismic evidence for compartmentalisation of the target reservoir section.

The well has been designed to test an independent structural closure within the Moulouya Fan covering up to 11 sq. km., twice the area of the original Anchois discovery well. Vertical relief on this closure is approximately 75 metres and is sufficient to test for lowest known gas in the 110 metre gross potential reservoir interval. Gas deeper than structural closure will help establish the validity of a single stratigraphic trap covering up to 30km² defined by the seismic amplitude signature tested in MOU-1.

MOU-2 is targeting net Best Estimate resources to the Company of 295 BCF (Table 1) based on the independent SLR Consulting Ireland Ltd. (“SLR”) Competent Persons Report (“CPR”), (February 2020 and January 2022 “MOU-4” updated). Gas deeper than the mapped structural closure tested by MOU-2 would support the SLR High Estimate of gas resources net to the Company of 708 BCF.

Supportive desktop studies
Recently completed post-well geochemical, sedimentological and biostrat studies on well cuttings have confirmed that the distal part of the Moulouya Fan was deposited in a deep marine setting. The presence of very fine grained sandstones was established as indicated as interpreted from the high resolution NuTech post-well log analysis. These are moderately well sorted and have undergone very little compaction. At deposition the independent studies indicated that these sediments were likely to have 35 – 40% porosity and permeabilities between 2000 and 5000 Md. Lack of compaction and consolidation suggests that poroperm conditions would not have been significantly impacted through burial and therefore good reservoir quality would potentially be retained, as supported by the post-well NuTech log analysis.

The new desktop studies will be used to update and refine the MOU-1 testing programme.

Geochemical source rock studies unexpectedly showed that the section between 800 and 1500 metres frequently had Total Organic Carbon content of between 0.85 and 1% raising the possibility of not only a thermogenic dry gas source but also a biogenic gas source.

Potential for early monetisation
Plans are being advanced to place MOU-2 in a success case on an extended production test for an initial CNG development. This does not require the issue of an Exploitation Concession licence, which can be applied for in due course following the extended production test.

Initial gas sales are likely to be constrained to a plateau of 10 mm cfgpd (using MOU-2 and MOU-1). Reservoir characteristics are encouraging and well deliverability may potentially be significantly higher than this plateau. For early monetisation and the generation of near-term gas sales revenues a cautious approach is being adopted to ensure that any exposure to shortfall in gas deliveries due to operational reasons is manageable through a flexible Gas Sales Agreement to end users with an alternative LPG back-up.

CNG sales can be upscaled with additional development wells to reach the next threshold production target of 50 mm cfgpd.

First CNG gas sales are being targeted for within 6 months of the completion of rigless testing for MOU-1 and MOU-2. Timing will depend on maintaining a momentum in the logistical supply chain.

To further its commercial objectives the Company is in discussion with the Moroccan industrial market to secure a Memorandum of Understanding for a Gas Sales Agreement that will be implemented upon the completion and announcement of the MOU-2 and MOU-1 rigless test results.

To assist the financing of the CNG development the Company is seeking to have in place before MOU-2 is drilled a Memorandum of Understanding with an international CNG utility company to finance through a leasing agreement the initial CNG development. The lack of fixed pipeline development costs; accelerated timescale to first gas; and higher gas prices achieved in the Moroccan industrial market versus the power sector generates the scale of revenues necessary to make commercially attractive such leasing agreements. A Memorandum of Understanding for a Leasing Agreement would  be implemented upon the completion and announcement of the MOU-2 and MOU-1 rigless test results.

Potential scoping revenues and indicative valuation
The SLR CPR (January 2022) gives an unrisked NPV per BCF of discovered gas of US$1.99 million. This is based on a large-scale gas-to-power development using a gas price of US$9/mcf and results in a low net-back of just US$1.99/mcf.

Conservatively therefore a 10 mm cfgpd CNG project would generate a NPV of US$7.26 million annually rising to US$36.3 million through scaling up to 50 mm cfgpd.

SLR recognise that a 10 mm cfgpd CNG development could potentially generate significantly higher revenues based on a CNG operating cost of US$2.3/mcf and a net CAPEX cost of US$12.21 million and an average gas sales price of US$11/mcf, before allowing for recent cost and gas price inflation as a result of the European energy crisis.

The SLR CPR gave an unrisked NPV of US$592 million for the net Best Estimate resources of 295 BCF being targeted by the upcoming MOU-2 well subject to proving commerciality. The CNG development case provides the optimum scenario for proving and accelerating commerciality whilst the gas market remains influenced by the European energy crisis.

At an exchange rate of US$1.19/GBP1.00 this represents an unrisked 146.5 pence per share based on the Company’s fully diluted share capital of 339,582,281 shares to support the risk-reward drilling proposition.

Mag Mell FSRU LNG and Ram Head gas storage

The Company is commissioning a report through SLR Consulting Ireland Ltd. to:

• develop an outline pipeline site survey plan for the existing Kinsale Head gas export pipeline to shore and to include the foreshore;
• prepare a draft investigative Foreshore Licence Application Form with accompanying map;
• apply to the Foreshore Unit of the Department of Housing, Local Government and Heritage to request a pre-application consultation meeting.

This forms part of the Company’s ongoing process to maintain heightened public and regulatory awareness of the importance of protecting strategic gas infrastructure from premature decommissioning  as the energy crisis in Europe evolves. This is vital to diversify Ireland’s gas imports and to assist with the development of gas storage. Currently Ireland has no gas storage facilities.

CO2 EOR Trinidad
The Company is focussed on leveraging it’s CO2 EOR expertise in Trinidad whilst preserving its cash resources in the near-term to advance drilling activity in Morocco.

Working in cooperation with Lease Operators in the PS-1 Block the Company has selected four additional sites for CO2 EOR operations. This will be the key area of focus for the remainder of 2022.

Green Hydrogen
The Company is seeking to acquire an attractive green hydrogen opportunity to develop once the Moroccan drilling and testing programme for 2022 has been completed.

Cash resources are committed at present to the MOU-2 drilling programme but options to secure exclusivity over early stage projects in private companies will be considered if the Company believes that it can add value through  its listed status to strengthen marketing of green hydrogen to potential end users.

Paul Griffiths, Executive Chairman of Predator Oil & Gas Holdings Plc commented:
“Despite logistical challenges caused by the situation between Russia and Ukraine, we are pleased that we remain on track to drill the follow-up well to MOU-1 during September and October. The Guercif licence area has always represented a unique risk-reward proposition for the Company and its shareholders. This has been reinforced in the last few months as the European energy crisis has taken a firm stranglehold.

We have the means to drill a sizeable onshore gas target but most importantly a clear plan for early monetisation though a CNG development that does not require any new gas pipeline infrastructure or any long delays in accessing existing infrastructure.

The Moulouya Fan Project is a project made for the current shortage of gas scenario in Morocco and Europe. Sometimes global events align to favour those that were prepared to take risks in an area that was for so long neglected and overlooked. Recognising missed opportunities is a key driver for our Company’s management as it creates our competitive edge.”

Fans of Predator will be happy that Morocco is back on and with what may be described as using an optimal solution, a CNG development without a pipeline, its infrastructure and of course the costs. They will also be happy to see Ireland remains on the agenda and CO2 EOR is scheduled for later on in the year.

SDX Energy/Tenaz
Tenaz Energy Corp would like to provide an update regarding our previously announced acquisition of SDX Energy Plc. Through public disclosures and communication with SDX, we have been informed that a shareholder representing that it owns 25.7% of SDX’s issued and outstanding shares intends to vote against the proposed Scheme of Arrangement to amalgamate Tenaz and SDX.

The Scheme requires, among other things, that 75% of the shares voted by SDX shareholders support the combination for it to become effective. In determining the shareholder approval, any shares voted must be eligible to vote and be validly voted in respect of the Scheme approval.

Tenaz has reserved the right to elect to implement the transaction by way of a takeover offer in compliance with the UK Takeover Code, subject to the UK Takeover Panel’s consent and NI 62-104 and the terms of the co-operation agreement with SDX. We are evaluating all available options with respect to the transaction and will provide a further update when appropriate.

Full details of approval requirements can be found in the Scheme Document distributed to SDX shareholders, which is available on our website at www.tenazenergy.com.

There has been no change or postponement of the shareholder meetings of either Tenaz or SDX to consider the transaction. Both meetings are scheduled for July 29, 2022.

It seems that Tenaz still have plenty of options available to them and having got this far are not going to be put off lightly. Expectations for a wildly higher bid should be managed down, this stock has been touted round the market by its major shareholder for long enough…

KeyFacts Energy Industry Directory: Malcy's Blog