WTI (Aug) $74.83 +$1.84, Brent (Sep) $79.40 +$1.71, Diff -$4.57 -13c. 

USNG (Aug) $2.74 +7c, UKNG (Aug) 70.4p -1.45p, TTF (Aug) €28.15 -€1.6.

Oil price 

Oil rallied sharply yesterday and today Brent is over $80/b. This is on the back of the EIA’s STEO published yesterday in which they suggested that the oil supply and demand balance was about to tighten, in one case quite strongly later this year. We shall see what the other two organisations say about the situation imminently.

The big deal of the week apart from those reports was the US CPI data today, after a lower figure than the whisper the markets went sharply higher but have since settled down as the Fed will surely still have two raises up its sleeve.

IOG

IOG has provided an operational update in advance of the Company’s half-year 2023 results. The information contained herein has not been audited and may be subject to further review. An accompanying presentation is available on the IOG website and can be accessed via this link: https://bit.ly/3LuKbPW

Rupert Newall, CEO, commented:

“Following the successful intervention and production ramp up, the Blythe H2 gas rate has stabilised at 32 mmscf/d, within the 30-40 mmscf/d pre-well guidance range, with no indication of formation water. As expected, initial H2 production data indicates better reservoir quality than at H1 and supports our existing Blythe gas in place and reserves estimates. We expect 2H23 production to average in the 20-30 mmscf/d range.

The team has significantly improved operating performance over 1H23, delivering 93% operating efficiency and a cost reduction programme tackling both opex and overheads. In parallel we continue the constructive dialogue with bondholders to address balance sheet challenges caused by the Southwark A2 result and the sharp fall in the gas market.

As a new management team, we have been reassessing the most efficient strategy to create value for our stakeholders based on operating data since First Gas in 2022 and updated technical evaluation of the risks and rewards across the portfolio. In addition to the established Saturn Banks production infrastructure position, the portfolio comprises high permeability conventional reservoirs as well as tighter gas reservoirs which require stimulation. Whilst the latter have clear potential, the conventional fields can deliver more compelling returns on capital with lower development risk. Strategically, therefore, we plan to prioritise these opportunities, from the Western Cluster (Blythe and Elgood) to the Southern Cluster (Kelham, Abbeydale, Orrell) and the Central Cluster, where our latest technical work indicates conventional discovered gas development potential at Grafton and Tenby.

Our “Conventional Core” incremental investment case illustrates this potential for efficient capital deployment. This has a management estimated unrisked pre-tax IRR of over 90% at an average gas price of 75 p/therm (well below today’s forward curve), which would be substantially derisked by a successful Kelham appraisal well. The broader portfolio has also extensive value to unlock beyond this, which could be further enhanced if we are successful in our nine 33rd Round block applications.”

It has been a busy and somewhat trying half for IOG as demonstrated by todays statement. The Southwark overhang, along with the weaker gas price  has led to a strategic refocus not to mention conversations with bondholders. Operationally, it was good to see the Blythe H2 well successfully drilled and production efficiency was improved considerably.

This strategic adjustment has led to IOG prioritising its conventional assets, which should be lower cost and risk in the short and medium term compared to the unconventional dearer assets. Some of these fields lie in their Central Cluster where they have been technically de-risking the P2589 licence as well as the Western and Southern Clusters, and potentially new licence awards if the 33rd Round comes to fruition. 

This is a re-pivoting of the IOG portfolio or maybe a strategic realignment, the volatile market having been addressed in order to deliver profitability in the future. Despite ongoing ‘choppyness’, gas prices are still considerably higher than before now that Europe is more reliant on LNG, so if bondholder discussions go well then they may be able to overcome a tricky few months.

1H23 Operating Highlights

 

1H23

FY22

Gross average gas rate

mmscf/d

13.8

21.0

Operating efficiency

%

93.3%

N/A

Production efficiency

%

81.4%

58.6%

Net gas sales

mmscf

511

3,444

Average realised gas price

p/therm

124.0

201.4

Net condensate sales

MT

1,764

5,339

Average condensate price

$/MT

599

805

TRIR¹

per 200,000 hours

3.5

3.6

Emissions intensity²

kgCOe/boe

1.1

0.8

Blythe Production

·    The H2 well gross gas rate tested at 42 mmscf/d directly after the faulty downhole valve had been fully opened. The subsequent gas rate ramp-up has stabilised at 32 mmscf/d, within the pre-well 30-40 mmscf/d guidance range.

·      Initial H2 production data is in line with pre-well expectations:

 Better reservoir quality at H2 than at H1 area

 Indications that communication exists between H2 and H1 area

 No indication of formation water production from H2

 Consistent with remaining reserves estimates (FY2022: 1P / 2P / 3P 24.6 / 42.3 / 46.8 billion cubic feet equivalent (BCFE) 

·     Gross 2H23 production is expected to average in the 20-30 mmscf/d range, based on initial decline rate expectations

 Perenco Bacton terminal annual maintenance shutdown expected in Q3

·      Reduction in water production is expected to reduce unit opex

·   Shelf Drilling Perseverance rig has demobilised from Blythe with the associated mandatory shut-in completed within three days

 Rig and associated vessel contracts in process of being terminated

Initial 1H23 Financial Information 

·    Revenue before sales deductions in the period of £9.5m, impacted by lower production rates, lower gas prices and higher partner royalty payments

 In periods of declining production and gas prices, the joint venture royalty formula increases the reduction in effective net economic interest beyond 20.2% of IOG’s net 50% working interest, however in periods of higher production and gas prices this effect can reverse

 The royalty is applicable to revenues from Blythe, Elgood and Southwark and is capped at £91m; total aggregate royalty paid to date is £16.1m

·      Cash balance at 30 June 2023 of £20.3m, of which £7.3m restricted

·      Maximising near-term cash flow remains a key priority; capital expenditure being minimised  

·    Ongoing constructive engagement with bondholders on near-term liquidity and longer-term capital structure solutions

Saturn Banks Portfolio: strategic focus on conventional gas

Conventional discovered gas opportunities   

·      Blythe: Potential for limited periodic H1 gas flow later in 2023, in addition to H2

·      Elgood: Further production targeted from existing well by 2024 from limited remaining reserves

·    Kelham: subject to funding, successful appraisal would open up the Southern Cluster that includes the conventional gas discoveries Abbeydale and Orrell

 Dual-lateral appraisal well would test both Kelham North and Kelham Central structures

·   P2589 licence (part of Central Cluster): ongoing subsurface re-evaluation indicates two conventional discovered gas opportunities with development potential as subsea tiebacks to the Southwark platform c.17km to the southwest:

 Grafton (formerly Sinope South)

 Tenby (previously Callisto North, initially developed in 2000)

 Both to be further defined technically and economically

 Additional conventional exploration prospects on block: Forest Row and Brockley

·      Positive 33rd Licensing Round interviews held in May 2023 for nine SNS block applications which could add further conventional and tight gas resources to the Saturn Banks portfolio

Ongoing re-evaluation of tight gas assets

·     Southwark re-evaluation continues; further technical and economic justification required for any return to A1 or A2 wells

·     Nailsworth and Elland subsurface and deliverability to undergo further technical review over 2H2023 in light of Southwark A2 learnings

·     Goddard due to be appraised by 31 March 2024 pursuant to licence terms and up to 50% has been offered for farm-out by the IOG-CalEnergy Resources (UK) Ltd joint venture

Incremental investment cases

Based on the latest subsurface and engineering work, two incremental investment scenarios have been worked up that demonstrate the significant value in the Saturn Banks portfolio. The economics benefit from extensive synergies given the established production infrastructure already in place.

Both scenarios also benefit from IOG’s material tax loss and investment allowance position, which as at 31 December 2022 included ring fence³ tax losses of £239.3m and Energy Profits Levy losses of £21.0m and non-ring fence losses of £24.2m.

Conventional Core incremental development scenario

·     Southern and Central Cluster conventional fields only (includes Kelham North/Central which is subject to appraisal)

·      Base case gross unrisked recoverable resources of 239 BCF

·      Entirely focused on higher permeability reservoirs that do not require stimulation

·      6 conventional subsea wells (3 per cluster): IOG classification: Tie back developments   

·      Tied back to Southwark platform and delivered into Bacton via Saturn Banks Pipeline System (SBPS)

·      Base case monthly peak gross gas rate of 142 mmscf/d

·      First gas 26 months from initial Final Investment Decision

·     Estimated pre-production gross capex of £284m; total capex including compression, decommissioning and contingencies of £368m (15.4 p/therm)  

·      Gross project pre-tax Internal Rate of Return (IRR):

 92% at average gas price of 75 p/therm

 124% at average gas price of 100 p/therm

Full Portfolio incremental development scenario

·  Southern, Central and Northern cluster conventional and tight gas assets (includes both Kelham North/Central and Goddard, both subject to appraisal) plus certain 33rd Round assets (subject to successful award)

·      Base case gross unrisked recoverable resources of 591 BCF

·      7 conventional and 11 tight gas wells

·     Two additional unmanned platforms, with tiebacks via the Blythe and Southwark platforms into the SBPS and on to Bacton

·      Base case monthly peak gross gas rate of 239 mmscf/d

·      First gas 23 months from initial Final Investment Decision

·     Estimated pre-production gross capex of £743m; total capex including compression, decommissioning and contingencies of £1,091m (18.5 p/therm)  

·      Gross project pre-tax Internal Rate of Return (IRR):

 63% at average gas price of 75 p/therm

 89% at average gas price of 100 p/therm

Scirocco Energy

Scirocco has noted the update issued today by Aminex PLC  regarding the Ruvuma asset, in which Scirocco awaits completion of the divestment of its 25% interest to ARA Petroleum Tanzania. The update states that operations on the Ruvuma PSC have continued to progress under the direction of the operator, APT.

Commenting on the update, Tom Reynolds, CEO of Scirocco, said:

“The significant progress made by the JV in the development of the Ruvuma license has provided us with improved clarity regarding the timing of contingent payments under the sale arrangements between ARA Petroleum Tanzania and Scirocco. Scirocco Energy is continuing to make progress towards the completion of the transaction and looks forward to providing an update on its status.”

For Scirocco the completion of the ARA deal is important because once finalised it will enable the company to go full speed ahead on pursuing its expansion plans away from Tanzania. As I have said many times this deal was always going to take some time but now appears to be in the final furlong. 

Highlights:

·      Following analysis of the results of the initial 3D seismic processing and interpretation, the JV partners have chosen a new optimal target location of the Chikumbi-1 well (“CH-1”).  The Tanzanian authorities have given provisional approval of the new CH-1 well pad location and final written approval is expected imminently.

·      The full processing of the 3D seismic data is now complete. Given the vast volume of data acquired, interpretation is now due to be completed in Q4 2023, which may result in a full revision of gas reserve and resource potential for the field.

·      A well-workover of the Ntorya-1 well (“NT-1”), to enable rapid tie-in to the gas production facilities and bring the well into early production requires the use of a drilling rig and remains scheduled to run after the drilling of CH-1.

·      The Gas Sales Agreement (“GSA”) in respect of the Ntorya Gas Field has now been agreed among the JV partners and the Tanzania Petroleum Development Corporation (“TPDC”). Signing of the GSA will take place upon approval by the Attorney General’s Office.

·      The Field Development Plan (“FDP”) for the development of the Ntorya Area has now been approved by all parties.

·      The Development Licence for the Ntorya Area has been approved by all relevant Tanzanian authorities and has been submitted to the Cabinet of Ministers for final authorisation.

·      The Tanzanian authorities have continued with the necessary workstreams to progress the construction of the export pipeline from Ntorya to the Madimba Gas Plant to accommodate gas, according to recent public reports, by December 2023.

·      APT recently received the first shipment of long lead items, including tubulars, required for the spudding of the CH-1 well.

·      The two-week well-testing programme on the Ntorya-2 well (“NT-2”), designed to provide additional information required for the design of in-field processing facilities, and originally scheduled for late March 2023, is now expected to run in the coming months.

As previously announced, the conclusion to the above workstreams decouples the spudding of CH-1 from first gas production and receipt of gas revenues. The re-defining and de-risking of the project materially advances first gas production, which is now expected at the end of 2023. A further announcement on drilling rig arrangements and timings will be made in due course.

Aminex, with a 25% non-operated interest, is carried throughout the ongoing work programme to a maximum gross capital expenditure of $140 million ($35 million net to Aminex). The carry is expected to see the Company through to the commencement of commercial gas production from the Ntorya gas-field at zero cost to the Company.

Charles Santos, Executive Chairman of Aminex commented:

“Ruvuma is an important project for Tanzania requiring a broad technical engagement and multiple negotiations.  We are very pleased that the Tanzanian authorities continue to prioritise our project, including supporting the accelerated production of gas and the building of a pipeline. We are also pleased to report that APT is making great progress, including finalisation of the GSA, FDP and the Development Licence, and the identification of a much-improved well location. We expect additional progress in the coming months on the well-testing of NT-2, the spudding of CH-1 and the workover of NT-1.  We also look forward to the completion of the 3D seismic interpretation by the fourth quarter of 2023”

Deltic Energy

Deltic has announced a significant increase in its estimate of oil and gas resources for the Pensacola discovery on Licence P2252 (Deltic WI: 30%). This increase, based on Deltic’s post well analysis, is nearly double initial expectations.

Highlights

·    Following post well analysis, Deltic now estimates the Pensacola structure to contain gross P50 initially in place volumes of gas and oil of 342 million barrels of oil equivalent.

·    This analysis indicates Pensacola may contain almost double the volume of recoverable gas and oil than originally thought, with Deltic now estimating total gross P50 Estimated Ultimate Recovery (‘EUR’) of c.99mmboe, up from 50mmboe immediately after well completion.

·    Significantly, Deltic now estimates Pensacola contains material volumes of oil, representing c. 30% of the combined recoverable hydrocarbons.

·    Work is progressing with partners to develop the appraisal and development programme for Pensacola with an appraisal well continued to be targeted for late 2024.

·    Deltic is pursuing monetisation options for the discovery in line with its strategy.

Graham Swindells, Chief Executive of Deltic Energy, commented:    

“The Pensacola oil and gas discovery is transformational for Deltic. Well data indicates that Pensacola contains close to double our original estimate, representing one of the most significant discoveries in the North Sea in many years.”

“This is an outstanding result for Deltic. Our success to date reinforces the quality of our technical team and the Deltic model of taking licences from award through to successful drilling.”

“We look forward to working with our JV partners to continue moving this exciting asset through the appraisal phase and onward towards development. With the significant additions to our resource base, we will also continue to pursue monetisation options in line with our stated strategy.”

This is indeed a massive upgrade particularly given it wasn’t that long that the discovery was made. At the time a good gas discovery was announced but now is also has the key element of light oil into the bargain. Going into the planning process for the appraisal well, having completed a good deal of analysis, now expected next summer this can be described as a development with all the good news that goes with that. 

All options are now on for Deltic, with Shell alongside they can be guaranteed a luxury if ambient ride to a full development and on the way they can part with as much or as little of the prospect if they get a good offer. Shell do not have pre-emption rights here, just the right of first refusal which in my view makes the process pretty copper-bottomed.

Also don’t forget the 50% of Selene at which an exploration well is to be drilled next autumn/winter, this will be the icing on the cake but could add a great deal to an already very high valuation. I will do the sums in a little while but at 30p depending on the value of Pensacola, which at 30% of 100m boe could make Deltic a 10 bagger from here with a formidable development value plus exploration upside.

Volumetric Update – Oil and Gas Initially in Place   

Deltic has updated its volumetric assessment of the Pensacola discovery based on data collected from the 41/05a-2 well and the results of lab testing.  This represents a significant increase in estimated initially in-place gas and oil volumes, as set out below:

PENSACOLA DISCOVERY – Oil and Gas Initially in Place (gross, Deltic WI: 30%)

Hydrocarbon Type

Units

P90

P50

P10

Gas

BCF

312

459

652

Oil

MMBO

87

243

485

Associated Gas*

BCF

40

136

340

COMBINED

TOTAL

MMBOE**

148

342

650

*Associated gas is gas dissolved within the oil deposit

** Gas is converted at 5.98 BCF to 1 MMBOE

Licence P2252 which contains the Pensacola discovery is operated by Shell 

While the expected presence of oil in the south of the prospect represents highly material upside, the discovered gas volumes in the northern part of the Pensacola prospect are better constrained and therefore the gas is still likely to be the initial focus of near-term appraisal and development activity.

Preliminary Development Plan and Recoverable Oil and Gas Volumes

Based on preliminary reservoir engineering work completed by Deltic, a range of potential development scenarios have been assessed to allow an estimation of recoverable volumes which could be produced from the Pensacola discovery. In all of these scenarios it has been assumed that hydrocarbons will be exported via a new offshore installation and pipeline to Teesside.  Based on these scenarios Deltic estimates the range of potentially recoverable oil and gas associated with the Pensacola discovery as follows:

PENSACOLA DISCOVERY – EUR (gross, Deltic WI:  30%)

Hydrocarbon Type

Units

P90

P50

P10

Gas

BCF

198

320

499

Oil

MMBO

11

30

67

Associated gas

BCF

24

95

272

COMBINED TOTAL

MMBOE*

48

99

196

* Gas is converted at 5.98 BCF to 1 MMBOE

Licence P2252 which contains the Pensacola discovery is operated by Shell 

Post Well Analysis

Interpretation work by the JV team following the post-well analytical programme has reinforced the conclusion that thicker and better quality Hauptdolomite reservoir is present across the crest of the Pensacola Reef, which will be targeted in future appraisal and development drilling.

The Hauptdolomite cores collected at the well location have an average porosity of 18.8% with a maximum permeability of 40mD (average of 6mD), better than the reservoir quality initially estimated from wireline logs.  Dynamic reservoir modelling by Deltic indicates that the reservoir quality encountered at the well location would support commercial flow rates from horizontal wells, without requiring any improvement in reservoir quality up-dip.

Next Steps

Deltic continues to work closely with the Licence Operator and our JV partners to develop the appraisal programme for the Pensacola discovery.  Subject to JV and other regulatory approvals, the drilling of an appraisal well on Pensacola is continued to be targeted for late 2024. In parallel, the JV will undertake various studies to define optimal development plans for the Pensacola discovery. 

In line with the Company’s stated strategy, Deltic has also commenced a formal process to pursue the value crystallisation options that exist for the Pensacola discovery which may involve monetisation and/or farm down of its equity interest in the Pensacola discovery.

Reabold Resources

Reabold Resources plc, the oil & gas investing company with a diversified portfolio of exploration, appraisal and development projects, is pleased to provide details of the high-grading exercise of its North Sea licences, in the context of the Company’s ongoing disciplined approach to capital allocation, which has led to the prioritisation of the highest potential return assets in the Board’s view.  As a reminder, the Northern North Sea basket of Licences was acquired for £0.25 million, effective May 2022, and the Southern North Sea basket of licences was acquired for c.£1 million in January 2023, as part of the Company’s acquisition of Simwell Resources Limited.

Reabold Northern North Sea

The Company is pleased to announce that it has successfully been granted an extension until July 2025 for licence P2478 (Dunrobin and Golspie, 36% working interest), which has aggregate gross unrisked[1] Pmean prospective resources of 201 mmboe (197 Mbbls + 24bcfg)[2].

In addition, licences P2605 (Laxford and Scourie) P2504 (Oulton and Oulton West) (both 100% working interest) have been retained as we continue the farm-out process, prior to a drill or drop decision by November 2024. These licences have aggregate gross unrisked Pmean prospective oil resources of 38 Mbbls3 and aggregate gross unrisked Pmean prospective gas resources of 148 Bscf3, in addition to 11Mbbls of oil and 15 bcfg 2C contingent resources (11.1 Mbbls + 3.6 bcfg in Oulton and 11bcfg on block in Laxford).

Licences P2396 (Curlew-A), P2464 (Quoys and Unst), P2493 (Sandvoe) (all 100% working interest) have been or are due to be relinquished shortly.

Reabold Southern North Sea

In Reabold’s Southern North Sea portfolio, licence P2486 has been retained as the operator continues the farm-out process, prior to a drill or drop decision by July 2024.

Shell, the operator of licence P2332, which is adjacent to the licence containing the Pensacola well, made a decision to relinquish the licence. Licences P2329 and P2427 have been or are due to be relinquished shortly.

The work undertaken on all our Southern North Sea licences has provided the Company with valuable data and added to our understanding of the Zechstein play, which is fundamental to our West Newton and Crawberry Hill assets onshore.

Sachin Oza, Co-CEO of Reabold, commented:

“With an abundance of value opportunities within Reabold, the high-grading of our recently acquired North Sea licence portfolio is driven by the Board’s disciplined financial framework, where the highest return opportunities have been prioritised.  We will look to farm down these high-graded assets to help fund the de-risking and value creation process.”

I have put in a request to see Reabold, like the old days it’s not, and hope to catch up next week, i’m still waiting fora reply. But all this is seemingly small beer yet a company with modest cash resources should, i would have thought be pressing on with West newton not these bits and pieces and acreage in Italy…