Member Info for londoner7

We now know that In March 2024 the status, as recorded by a contracted independent consultant was, planning to blah, blah blah, the "re-entry and deepening of existing shallow wells (Hussar and Mt Winter), should engineering studies demonstrate this to be a time and cost-effective endeavour."

Did the drilling approvals on Hussar drag on through the year- largely awaiting company info- because Hussar well re-entry wasn't considered a cost-effective endeavour?

Remember this - RNS dated 14th July 2024 - "For the avoidance of doubt preparation of and access to the Hussar well site cannot be undertaken until final expanded environmental management plans are approved." This comment seems at odds with one from RNS dated 19th August 2024 which stated "The re-grading of the immediately adjacent airstrip along with site preparations is proceeding as planned". The same RNS refers to ongoing work on environmental approvals. Change in DEMIR rules or is Hussar well re-entry no longer a cost-effective endeavour?

It was posters here monitoring the DEMIR status reports who highlighted the change to 'drilling on Hussar approved' that prompted a delayed acknowledgement by GEX. GEX gave no indication of any works schedule in the RNS and closed with the comment, "The company will make a further statement in due course".

There would be an expectation that GEX were primed to commence works upon drilling approval. But I guess not if you don't consider a re-entry of Hussar a cost-effective endeavour.

All this talk of $billions of value in Hussar and Mt Winter. It doesn't look like the GEX board agrees.

I'd urge any prospective investors in GEX to read Central Petroleum's ASX announcement on their JV with GEX.

It contains considerably more detail on the JV and anticipated ongoing activities than GEX provided in their RNS. I suspect GEX will need to clarify their plans particularly with respect to the timing and funding of a Hussar re-entry.

Spot on panman.

Central Petroleum shareholders have been round this block a few times.

On the 9th Feb 2025 I posted here, "Another funding path is via the JV they are pursuing with an Australian company on additional well re-entry opportunities. Apparently, they’ve narrowed the field down from 100 to 2. I suspect they’ll go the well-trodden path of Mt Kitty and Magee."

'Narrowed the field down from 100' - Really? Speculative helium plays - He Nuclear, Peak Helium - were drawn to these particular wells because they carry a simple storyline to feed prospective investors. But their Helium potential doesn't stand up to scrutiny. (Do some research. I did and posted it to the MSMN board a few years back.)

I also posted this history of Central's JVs on the MSMN board.

"Central, with its Joint Venture Participant, He Nuclear Ltd, planned conditionally to drill at least one well during 2010 (The Magee 2 well) targeting gas, condensate and helium.

Magee-2 was subsequently deferred. The following text is from a CP drilling update:

“Central Petroleum has decided to change its planned 2010 drilling programme to enable the company to prioritise its pursuit of oil targets in the Amadeus Basin and maximise the opportunity of short term cash flows, rather than the longer term and more capital intensive Helium/gas targets.

The current inability of Oil and Gas Exploration Ltd (previously He Nuclear Ltd) (OGE) to pay 50% of the funding needed for the Magee 2 drilling programme has also contributed to the decision.

OGE owes approximately $1 million in unpaid cash calls for both the Magee and the Mt Kitty joint ventures”

Within the Amadeus Basin CP’s focus turned to the Dukas-1 well for conventional gas, working Santos as operator. (The pressure and rig issues during drilling are well known here). Santos lost a % of their interest when they passed on a deadline to commit to return to Dukas-1.

After a 3 year delay a private company, Peak Helium, revived interest in Magee, Mt Kitty and Dukas in Feb 2022, when they agreed a JV with Central Petroleum and Santos for 3 drills in 2023. Peak is carrying the full well costs (100%) to a max (gross) $20m per well on Magee and Mt Kitty, and WI costs on Dukas.

The farm out was subsequently terminated following Peak’s failure to comply with demands for payments under the agreement."

Santos clearly has no interest in moving forward as operator on these drill sites unless someone is carrying them and paying the drilling costs.

He Nuclear and Peak Helium were speculative plays which cost Central Petroleum and Santos money, so I'm not surprised that their JV with GEX now limits CTP's exposure.

But my read is that today's JV talk is smoke and mirrors and the crux is that GEX needs funding.

Oopps!

Parge,

yes if CFFO remained at similar levels to 2025 FY. but my interpretation of BOA's comment is that CFFO will be higher by 2030.

There was a lot in the BOA comment that I found confusing, not least the 60% dividend reference, but I appreciate the posting.

I liked the following section, because it reaffirmed my view that Ithaca will be the main beneficiary of any likely changes to the EPL in the upcoming budget, and the possibility that there's little change beyond perhaps bringing the end date of the EPL ahead by one year. My expectation is that any near term changes will be on capital allowances.

"The bank also wrote that they believe the company will be the main beneficiary of changes to the British tax regime relative to its competitors in the British North Sea and that improved fiscal certainty will help the process of selling part of the Cambo reservoir, and that the change will allow the company to achieve cash flow and dividends over the longer term."

However, given the odd grammar throughout, I suspect the last line should read, " allow the company to 'grow' cash flow and dividends over the longer term.

On the reference to "a dividend yield of approximately 60%", I suspect the writer was referring to the dividend payout from cash flows. The current dividend payout is 15%-30% of CFFO, with a 30% expectation for this FY. Given the pipeline of 2C resource available to Ithaca to develop over the next few years - largely ahead of the EPL ending - and the step up in cashflows with the end of the EPL, Ithaca would have scope to increase their dividend payout to 60% of CFFO.

Trickymatters, I haven't seen any coverage in The Times on Labour considering a reversal of their pledge on 'no new licences'.

Can you send me a link?

From Sept, I found this:

"Ministers are considering giving a green light to the expansion of existing North Sea oil and gas fields despite Labour’s manifesto pledge to ban new ones, as they seek to maintain jobs and tax revenues."

Is this the story you are referring to?

The expansion of existing fields is already within the remit of existing licences. Yes, the minister still needs to give approval of the environmental application - consent - but an outright refusal would be open to challenge in the courts.

"The government said it was considering allowing tie-backs to new oil and gas fields nearby to those with existing licences. "

This comment would be significant if it appeared in a publication of greater weight than "EnergyVoice". Also, the author's remit is on renewables, which makes me wonder if he appreciates the implication of his comment.

If a company has a current licence to explore and potentially develop new oil and gas fields there's no restriction on the infrastructure supporting the development provided it meets the environmental requirement, so the development could include a tie-back to a field with an existing licence.

Ithaca's development plan for Fotla is likely to be a tie back to the Ithaca operated Alba field. (I suspect we'll hear news on this soon.)

But the wording of the comment implies to me something new is under consideration. That is new oil and gas fields would be granted a licence if the development involves a tie back to an existing production facility. This would be at odds with Labour's manifesto commitment 'no new licences'.

Is that what the author is describing, or is it sloppy journalism?

The main point I'm making in this commentary, in relation to the EPL, is that the most effective benefit of EPL capital allowances accrue to companies which are already making substantial EPL payments. Secondly, if the EPL tax is removed after, or shortly after, the start up of production then there is a significant uplift in the return on investment.

Fast payback tie-ins seems to be the order of the day. As things stand a capital investment in 2029, with associated EPL allowances, followed by the removal of the EPL tax in 2030, would be a nicely timed investment. There would be a temporary high demand for rigs to cover that period. Of course, this scenario will have been raised in discussions on the EPL, so perhaps we''ll see a phased withdrawal of the EPL rather than a step change.

Ithaca just needs certainty on the timelines. Between the Cambo, Flotla, Tornado and K2 discoveries they have good optionality to make the best of the eventual EPL structure.

* My comments are based on my 'non-practicing knowledge' of the UK tax regime, so I welcome any comments or corrections from anyone with a working knowledge.

An interesting aspect of the Jeffries broker changes is an upgrade to companies operating in the North Sea and (predominantly) a downgrade to companies with no, or insignificant operations in the North Sea.

This suggests to me a broker view that there may be favorable changes to the EPL in the pipeline.

I suspect that any near term changes will be limited to those that are most likely to increase investment in the North Sea, rather than providing tax relief to companies like HBR which are largely (but not entirely) running down their North Sea operations.

This would mean an increase in the capital allowances, rather than removal or reduction in the EPL, but the price of oil remains an anomaly in the context of 'windfall' gains, so perhaps they will split oil from gas within the EPL structure. I can also envisage some tinkering with non-exceptions, which might include decom and finance costs.

Time will tell, but come what may, I think Ithaca has good optionality to make the best of managing through the EPL transition, assuming the EPL remains largely intact through to the current end date, March 2030.

Assuming Rosebank gets consent, Ithaca will have invested c.$750m of capital in a field which expected to ramp up to 14Kbopd (net oil) plus 2Kboepd (net gas) through early 2027 and maintain the plateau through to 2033, before declining. Though there is an option of a 2nd stage of development expected to start 5 years into production.

Allowing for tax allowances and including interest costs, I estimate that the net cost of Ithaca's share of the Rosebank development will be c.$180m up to first production 2026/7. (My numbers assume target production from start of 2027, which might be 1 or 2 quarters ahead of the outcome, but it's ballpark.)

Assuming a 78% tax rate I expect the cost of development to have been covered between the 2nd and 3rd year of production. With the ending of EPL in March 2030 the annual returns step up considerably, nearly tripling.

But I want to go back to the current EPL (+CT) regime and associated allowances.

In 2025 Ithaca expects to spend a total of $900m on CapEx (including $70m on decom). CT relief is c.$360m (less after finance costs) and EPL relief is c.$315m (after deducting decom). To be clear, Ithaca are paying out $900m for these investments - the government adds nothing - but the fact that Ithaca has producing assets, which are charged high levels of CT and EPL payments into the exchequer means the 2025 capital allowances can be offset against these payments. Ignoring the timing and phasing of payments, that's essentially a $315m reduction in the EPL charge and a $360m reduction in the CT charge over one year - though given existing CT tax losses, little CT is due anyway. (There's c$5bn of CT tax losses as of Dec 2024).

I didn't post at the time, but this morning's comments prompted me to look back at a note I made to myself at the interims. Here's an extract:

$2,700m - cash Jun 25

-$360m- H2 reversal of FCF

-$100m - Buyback, assuming YE completion

-$228m - Dividends

-$1,171m - repayment of Euro bond

------------------------

$841m - cash Dec 25.(Just above the $805m cash Dec 24)

The H2 reversal of FCF assumes the HBR year end FCF of $1bn is met. Although we have a good level of near term hedging, prices still matter - though we are now well into the year with no mishaps reported so far.

On future reductions in CapEx, I think consideration should be given to the post tax cost of CapEx - the reduction isn't as significant as the headline gross numbers.

"cannot see anything to break this current lethargy"

Gas prices may be a catalyst. 40% of Harbour production is subject to UK/EU gas pricing. Since the EU relaxed storage requirements last July the storage fill rates have fallen below recent years. The commentary is that LNG supplies provide cover to lower EU storage levels, but an early cold snap could lead to a sudden and significant increase in gas prices, which additionally provides hedging opportunities.

Hi Strictly, thanks for your numbers.

"Half time whistle 2025 £3,247.0m less £1,176.6m intangibles & goodwill = £2,071.2m dividend by shares in issue 326.109m = 635p BVPS"

I used a tangible net asset value in a table before the balance sheet, which included curious treatment of net debt, which I now see, so happy to use your £2,071.2m. I see you've taken the share count from a June 30th update. Though you don't exclude shares in treasury, I'm not going to quibble so I agree with your 635p BVPS.

"From here, 43.3p minimum EPS to sustain div = 6.8% on book value compares against 7.5% of book value paid in div for Taylor Wimps."

If I understand your calculation of 43.3p based on 10 years of 'capital appreciation' (my wording) then I believe the expenditure on those intangibles and goodwill over the period shouldn't be excluded. We could assume that the expenditure is adding to asset appreciation today.

Bottom line, if Taylor Wimpey's determination of dividend was applied to Vistry's 2025 interim results (IMO) the dividend yield would approximate to:

(7.5%*635p)/575p = 8.3%

Correction on share count

323m not £323m.

If VTY applied the same dividend policy as TW. they would pay a similar dividend yield.

VTY net tangible asset value £2,364m, or £2,364/£323m = £7.32 / share.

Yield = (7.5%*£7.32)/£5.75 = 9.5%.

If anyone sees it differently, please correct.

July numbers are out.

We're in the maintenance period and there's noise in the numbers, but overall still good so I anticipate more maintenance activity through Aug and Sept.

But two key features worth a mention are: J-Area back to good production levels with the completion of maintenance; and the best monthly production of the year from Captain c.29kbopd, ahead of maintenance which started 2nd week in August.

Tamovv, Ithaca's $23.5m investment in 'listed oil and gas shares' is an interesting development. It's fair to assume that the investment is in support of M&A activity. But a $23.5m holding in ENQ would be over ENQ's 3% holding threshold for reporting. How do you square that?

The investment would be below the threshold of another UK listed company that comes to mine, but it doesn't have to be a ULK listed company. That widens the net considerably.

Neversellshell22, you posed a question on the wide scope of valuations of HBR, and more recently you posted a link to an excellent article on Stockwatch.

I think the section in the Stockwatch article headed, "So, are decommissioning costs the elephant in the room?", largely answers the question you posed, to such an extent I'm loath to add much more.

The article identifies the reduction in the decom risk following the merger with Wintershall Dea, and also makes clear that the larger part of todays decom liability lies with the UK assets, c,$4bn, with UK production c.160Kboepd.

The risk within the UK portfolio is that these are old assets, albeit with good life expectancy, but some may be subject to 3rd party infrastructure reliability. This was brought home by the recent news that BP and Shell have, or are, restarting production from North Sea fields which were shut down a decade or more ago due to 3rd party infrastructure changes. (At some point I might be prompted to do a deep dive into Harbour's exposure to 3rd party activities.)

Current year decom spend is c.$400m. Let's see how that changes over, say the next two years. That would be a sign of direction. Also, let's see how generous Harbour are with their returns to shareholders over the same period. As the article states, decom valuations is a complex business, and who better to understand the detail than the company management, whose confidence will be relayed to us in future provisions and share buybacks.

This post doesn't answer the question of what is the right valuation, but expands on why there is uncertainty in the market.

I like the current dividend yield, and while I see good prospects for grown in the per share dividend returns I'm happy to hold.

Tornado10, I've just realised that the 2nd part of my reply relates to the earlier Seagull acquisition, which closed 7th July. The Cygnus acquisition isn't expected to close until the end Q3, so wasn't in my thoughts.

I repeat my believe, that the interval between the effective transaction date and the closing date is reflected in a lower cash payment at completion, with the production counted in the numbers after the closing date.

With that in mind I don't expect to see anything in the H1 numbers in relation to the Seagull acquisition other than the $20m deposit revealed in the Q1 numbers. Perhaps we'll see a deposit for the Cygnus acquisition in the H1 numbers.

I expect a total cash payment for both acquisitions of c.$250m. (I've plucked this number from memory)

The following text is from the RNS on Seagull, which reminded me of the additional tax benefits to come:

"The Transaction consideration is subject to customary purchase price adjustments, equating to an estimated payment at completion of approximately US$140 million, assuming an illustrative 30 June 2025 closing date. The Transaction includes JUK's material tax losses of approximately US$215 million in both Ring Fence Corporation Tax and Supplementary Charge Tax as well as approximately US$105 million Energy Profit Levy losses as at the effective date of 1 January 2024, reflecting JUK's material investment in the field."

Tornado10, you ask, "Have you updated Cygnus WI?"

No.

The transaction closed 7th July, so I don't expect ITH to include it in their Q2 numbers. Ithaca's interest since the effective date will be reflected in the completion payment of $139m.

Also, I was deliberate in using a delta change, Q2 down 8% on Q1, rather than an absolute number because I believe ITH include fuel gas in their production numbers. Nothing wrong with that, it is produced. But my interest is in getting to an EBITDA number, which is based on the volumes sold. (I like Ithaca's presentation of EBITDA, but don't how they accommodate fuel gas - I might take a closer look at the Q2 table.) You also need to convert the gas production number to boe. I use a conversion multiple of 0.187, which is my interpretation of Ithaca's guidance.

Bottom line, whatever gets me to a similar EBITDA number to the one Ithaca posts works for me.