Member Info for londoner7

In July, I said, "No guidance provided yesterday in spite of the claim that "productivity is close to normal". At the Sept finals report I'm expecting a kitchen sinking by management ahead of their own LTIP awards. I've decided to stay on the sidelines until another look after the Sept update."

Well there was no need for a kitchen sinking. The market did it for them.

LTIP Awards are part of the game management in all companies play. I watch them closely and step away if they look too generous. These awards represent 3% of today's market cap. That is rich so I don't need to look any deeper - I won't be getting involved here.

As usual the detail of the awards is kept under wraps until they vest, but I'd guess they have modest targets considering the current position of GFRD share price and the sector. Another 3% next year and the year after? That's equivalent to a dividend.

The sector operates on tight margins and lately few in the sector has achieved them. I don't pick out the team here as being any worse than average, but the best margin achieved (Bill has been here a few years) is 0.9% in the last 4 years and that was before exceptionals, so a 3% dilution in market cap for one years LTIP Awards looks at high for the sector.

In a normal market the weaker players in the sector would fold and margins would improve for the survivors. But that doesn't seem to be the way markets perform in this low interest environment. This sector seems to suffer worse that most.

Maybe there's something here for nimble traders, but not for this investor.

Bareboat charter - I was going on memory. It’s actually nearer 4.5 years before the rate changes, but my memory of the hire rates is correct. Enquest share is 70.5%.

Here’s the detail from the RI Prospectus (page 271):

The original charter period begins on the “first production date” (which is 4 September 2018 being the date of issuance of the Acceptance Certificate) and expires, unless terminated earlier in accordance with its terms (including the charterers’ ability to terminate for convenience on 180 days’ notice) on 1 April 2025. Upon expiry of the original charter period, the charter period is automatically extended on an annual basis for a period of 12 months up to a maximum of 17 years in addition to the original charter period, unless terminated earlier in accordance with its terms (including the charters’ ability to terminate for convenience on 180 days’ notice) or if the charterers notify Armada of its election to terminate the bareboat charter 12 months prior to the expiry of the original charter period.

(small print)

The daily rate became payable from 6 July 2017). Hire rates per day are $447,352 during the original charter period and $139,860 during the extension hire period, payable by EnQuest Heather (subject to adjustments in the event of force majeure and availability)

[Failure by Armada to meet certain minimum requirements could result in compensation payments to the charterers. (my wording)]

The maximum compensation payable by Armada is $50,600 USD per day.

Bottom line: this is a significant drop in FPSO costs, assuming there is nothing in the lease agreement small print preventing it's extension to the Bressay field.

25m shares @ 0.18p traded yesterday at 10:45.

Was that a buy or sell? Related to warrants?

Perhaps a transient trade. We've seen these delayed trades subsequently cancelled. I've a few trades I wish I could cancel.

It's very hard to keep up.

L3Trader, you threw me with this comment, "Kraken: I think ENQ should try to sell 15% of Enq to CNE if it can get a good price."

I wasn't sure if you meant this in relation to collecting some cash towards a potential Exxon deal, or meeting any shortfall in the RCF next year. (On the latter, I'm relaxed about Enquest's position with the RCF because of comments made by JS in the recent call. He talked of the possibility of extending the RCF repayment and having good relations with the lenders. I don't think he would have made such a comment if extension wasn't a realist possibility.)

But then I viewed the idea of a partial sale to CNE in the context of a development of Bressay. In the recent call AB highlighted 'partnership structures' as being a factor in taking Bressay forward. EnQuest will make a contingent payment of $15 million following OGA approval of a Bressay field development plan. The contingent payment increases to $30 million in the event that EnQuest sole risks Equinor in the submission of the field development plan. This would take Enquest's share in Bressay from c41% to c82%. At that point Chrysaor might take a similar deal for their 18% share.

That would be a tidy position for Enquest if CNE with a 29.5% share in Kraken wanted to join Enquest in developing Bressay. At that point I think it should be easy to agree a suitable valuation for Kraken to adjust the partnership if required, say 55%:45% in the combined a Kraken / Bressay development.

I don't know if Bressay or other Kraken license tie ins offer the best next stage in development, but a supporting factor in any development is that in 3-4 years the day rate for the Kraken FPSO drops significantly, from a c$116m (ENQ share) today, down to c$35m. On say, 25K bopd net production, that's c$8 per barrel off OpEx.

Thanks, romaron. I don’t know much about the detail of Enquest’s tax position, but I do recall a news item that highlighted an element of ‘tax transference’ within the BP Magnus deal - I wasn’t an investor in Enquest at the time but for some reason the news registered.

The BP deal demonstrates there is flexibility in utilising tax losses across assets, which I believe is standard in any business, but I’m not sure about specific tax credits. Here I’m thinking of the two Heavy Oil Field credits awarded to Enquest for Kraken. Their use may be restricted to Kraken revenues. I don’t know.

Exxon – cash versus vendor loan/ profit share structure.

An attraction to BP in accepting the vendor loan and profit share structure for Magnus is that it permits Enquest to utilise their tax position and offer a pricing to BP which includes a share of that tax position. Of course, we don’t know how attractive that pricing was over any competing cash offers.

But I suspect there are other factors to consider, key being decommissioning costs and a share of any upside potential in production.

A cash buyer will be playing down the returns from production and playing up the costs of decommissioning, particularly in terms of timing – the closer to decommission the higher the present- day costs assessment of decommissioning.

Enquest, could present a vastly different package, which may be more attractive to Exxon. Importantly, Enquest has the experience of the Magnus transaction to support their offer, and Exxon will have some insight into how advantageous it is proving to BP.

It could be that Exxon are hard set against anything but a cash offer. But if Enquest are the only bidder putting forward a ‘special structure’ offer against the other bidders putting in cash offers, perhaps there is something to play for.

Sweatysock, I continue to follow the Mosman story, for reasons I’ve described previously and will continue to post as I see fit. You are not the arbitrator of this board.

Throughout, whether invested or not, I have attempted to be fair and realistic in my contributions and contrary to your point consider myself to one of the least mischievous posters here.

Perhaps the accuracy of contributions here doesn’t matter to you, providing it supports your opinion, but others here might care about accuracy.

Da_Gee posted a comment which is mischievous if the facts stated are false – perhaps you consider that ramping and acceptable. I asked for clarification. Perhaps he will supply it. It is telling that my request upsets you.

Da_Gee, you say, “Please note we also get a premium on the oil grade we have. Think it was $6 more.”

Can you point to a reference that supports $6 premium?

L3Trader, you had other questions for me, “but a few questions for you. Do you agree the FPSO leasing cost was $56M in H1?”

No. Lease payments in H1 were $56m but these include office and other leases, which last year represented approx. 8% of lease obligations. The FPSO lease is still probably >$50m in H1, but I’m guessing you see this as light. If so, I agree but I’m waiting for the full year numbers.

“Only $5M repaid of the vendor loan for 75% of Magnus (it was supposed to be about $12M per HY; this tells me the cash waterfall takes precedence over repayment of the loan; interest on this loan is 7.5%!) .”

I agree this is odd. The guidance is that the Vendor loan (I had c$30m for the year in mind) had first call on Magnus cashflows ahead of profit share. Perhaps it will all be resolved in the year end numbers.

But another point occurred to me. A few days ago you said, “On the positive side the balance of payables has come down significantly.” I assume you are referring to the contingencies relating to Magnus (75%). If so, you may be reading this wrong, as I recall you did when the reverse occurred last year.

All of the Magnus contingencies are consolidated into a single number. Those are outstanding vendor loan, associated interest, and the big one, profit share payments due to BP. But these contingencies are discounted to a present-day value. If expected Magnus cash flows over the near term fall, as they have done due to the oil price, then the provisions number will also fall. That’s what we see in the H1 accounts. Further, if the expected payments of the Magnus profit share attributed to BP (up to $1B) extend beyond the COP of the Magnus field then those are not counted (how can they after COP?)– I recall a comment to that effect relating to the current oil price. Also, I wonder if the vendor loan payment is simply lost in this nonsense accounting.

In a way I’d like to see the contingencies payable INCREASE. That would mean that expected Magnus cash flows are increasing. Remember they are shared between BP and ENQ. Better to have 50% of more cash, in the bank (don't forget Pelle's wishes). Even if it means a bit more on a non cash balance sheet item.

Sleep on that one! ;-)

I’ve been trying to get my head around whether the update is as good as it appears to be. The market always likes to hear ‘ahead of market expectations’, but I’m more focused on my expectations.

Generally, I’ve written off 2020 for the companies I follow in the Covid impacted universe. In addition, typically I see a good result as a repeat of 2019 numbers in 2021. But in Breedon I am looking for something better, because of the operating momentum entering 2020 (pre-Covid) and the Cemex acquisition. I’d guess the market did too, as reflected in the share price performance at the turn of the year. Although, an element of that performance would have been due to the Brexit ‘resolution’, which to some degree is now being disrupted.

Alongside the half year results this update provides a good guide towards the 2nd half, although I’d have preferred a revenue update without the ‘noise’ of a one-month contribution from the Cemex acquisition. Taking out the Cemex contribution, using latest figures from 2018, points to a 2.5% like for like improvement in July and August over 2019. But it is a noisy adjustment.

It’s too early to get a firm handle on 2021, but I’m sensing Breedon might start 2021 at a similar operating level to how they started 2020, with the additional positive impact that the Cemex acquisition will have been in-house for 5 months rather than 7 months into the future, and effectively £70m of the £155m cash cost paid down.

To support that position, which I feel is top end, would need year-end metrics of pre-IFSR 16 net debt £320m and an adjusted EPS of ((66.5-15.5)*0.8)/1,696 = 2.4p.

The November update will provide a good marker along the way (I’m looking for c£60m-£65m below the 2019 revenue number).

The big unknows are how the UK and Ireland come through Covid, and the impact of a possible ‘hard border’ on operations and market sentiment. Breedon should guide on any operational impact at the results next March.

AB typically buys on a Friday.

Perhaps as a child that was the day he got his pocket money, and old savings habits are hard to break!

Thanks NortherLad.

It was interesting to note ENQ referred to WI efficiency on Magnus in their latest update. I haven't seen detail reported before.

"This increase was driven by high production efficiency of 86% and also high water injection efficiency of 91%."

I not sure how to interpret this but I'd guess the metric was added to address a question or query from some quarter.

NortherLad, thanks for that information.

In answer to my Q&A question on the DA tower, Bob only referred to a benefit to produced water. But I understand that may have been his key focus or limitation. I also understand your point about the tower being an essential part of the water injection system. As I said that was my original take, but Bob's reply threw me.

In conclusion, am I correct to say that an additional water injection pump installed now, would support a higher level of water injection ahead of a 2nd DA tower coming on stream in Q4?

L3Trader, you ask, “Magnus now fully sorted, or are the compressor/injection problems still ongoing?”

The quick-fire response is, have you asked IR? But you asked me, so I’ll try and help.

Within ENQ, Magnus has been my focus, because of the volatility of production in H1, between 13K bopd – 19K bopd, with 14.6K bopd reported for June. There was some ‘noise’ around the gas compressor problem, the transfer away from gas injection, and the additional production from the new wells.

The OGA data includes a lot of detail and as an engineer I can’t resist examining it. But I’m not an oil engineer or geologist so the risk is that I misinterpret the data. At a base level I believe my interpretation is correct – the data points to periodic reductions in water injection and this shows up as an impact on production volume. As an investor, I want to know if these water injection problems are being resolved. That lead to my question (twice) in the recent Q&A. Bob’s reply surprised and confused me. I then reviewed other communications and concluded I have misunderstood the relevance of the DA towers to water injection. I thought the two were one and the same, but now believe they are separate. The DA towers support produced water volumes. Water injection facilities are something else. Somewhere, I think it was in the interim commentary, I thought I heard that the gas compressor problem has now been resolved.

In summary, this is how I see it. I was encouraged to see >19K bopd in April – it points to what is possible. In June there was a c35% reduction in water injection, which may have been a factor in the reduced oil production in June. However, additional water injection facilities may now be onstream – that was the plan. The 2nd DA tower is due to come onstream in Q4 – this may be linked to the shutdown which is expected to be for one week in Q4. I’m optimistic we’ll see good production numbers before the end of the year. Magnus has not performed to the CPR expectations, but the oil is still in place.

An alternate view: The Magnus infrastructure is old. The ENQ engineers have been acquainting themselves with their new acquisition. Not only are the ENQ engineers tasked with maintaining the kit but also aligning the facility with revised demands, such as a move from gas injection more towards water injection, a rising rather than falling rate of production as new wells are brought on stream, and the associated increase in produced water. I imagine a classic car fanatic contemplating the restoration of an E-Type he’s rescued from 40 years at the back of a leaky cow shed and giving it a bit of modern-day oomph. Although having had the ‘pleasure’ of a ride in a restored E-Type, I’d focus on the suspension!

romaron, taking the floor for a moment on your question.

I am struggling to understand your question. Is the question: An oil company has say, $3B in tax losses. If impairments are taken against relevant assets, do these impairments reduce the original tax loss? Secondary question: if these tax losses are maintained can they be acquired, and used, by another company?

Hi L3Trader, I’ll respond to each point.

“trading on similar amounts per bbl of 2P reserves.” I was surprised how close they were, but this was just a moment in time, repeating the exercise in a month or two might show a larger spread. Based on my assessment of the position when ENQ was 15.5p, not much larger, $0.6 different from memory, but this shows the gearing ENQ carries in translating this adjustment to equity value, i.e. share price. Something CNE has little of, but this adjustment impacts in both directions. In a way, this valuation on 2P is a no brainer. Companies are valued on future cash flows relative to the investment, equity and debt. The 2P reserve is the best indicator of what those cash flows will be. Plug that into your spreadsheet against oil price predictions and you have your cash flows. The bigger surprise to me was how low 2C was valued, and sanctioned 2P was not valued much higher until the investment had been made. Look at the prospective tie-ins ENQ identified in their CMD, typically $15. Malaysia at $7-10 looks an outlier but when you consider the PSC it too nudges $15. On Bressay, AB hinted at $15, like Worcester. I struggle a little with this but perhaps the extra Bressay volumes compensate for the extra challenges.

“aggressive trades between the oil companies I invest in” I use “aggressive” in relative terms. I’m not an all-out trader. I hold long established and I hope researched positions in companies. I maintain rules which limits my stake, and I’ve adjusted to this restriction by selling down stakes I think are toppy, with a view to adding later. I typically do this exercise only once or twice a year in each company and the adjustment is typically only 25%. I have formed different strategies for different companies or sectors, although I tend to spread my investment in the oil sector across more companies. For years I ran a strategy on Shell focused on the fact that they never reduced their dividend. This year they announced a reduction and I sold my entire stake within the hour. That released funds for other companies in the sector. Today, my oil plays are largely CNE and ENQ. By “aggressive trades” I mean that I will probably move to 50% rotations between the two companies. As an example, when ENQ was priced at 15.5p last June I would have been rotating out of ENQ into CNE while maintaining my position in the sector. I didn’t because at the time I was rebuilding my position in ENQ, so I paused. I now have my full stake in ENQ.

My response on Magus could be a long one so I’ll follow up in a 2nd post.

L3Trader, our posts crossed, but on a quick read of yours I think my comments on reserves hold. I might come back on the other stuff.

But on my post, I felt I left out a response to the point hitman1a made about the relative valuation of ENQ and CNE – he saw ENQ as cheap in comparison. I’m not going to argue that point, but I do want to expand on the 2P valuation and gearing which have a bearing.

I was struck by how frequently c$15 came up as a cost or valuation for 2P reserves, in the absence of, let me call, noise.

2P will have differing quality, depending on OPEx (as you say in your last post) and the speed with which it can be extracted – longer dated extraction having a lower present value. But all of the current production for ENQ and CNE is in the c$20 Opex range after adding FPSO lease.

The market values the 2P in accordance with oil price expectations, and that is where the gearing can play a significant part. I felt the oil price recovery during May and June was too strong and the ENQ SP benefitted because the recovery was ahead of where the market had priced oil. I was looking to rebuild my position at the time and felt ENQ was overpriced at 15.5p. My patience paid off. If oil is now at or below the curve then I support hitman1a’s view that ENQ is cheap. In terms of my trading strategy I intend to play that position if I feel the oil price and as a result the ENQ share price, has moved too far ahead.

I’m writing this on the fly and while it makes sense in my head, I appreciate that might not be the case on paper. I’m happy to expand if anyone asks.

Cheers

ps I understand that there is also a gearing benefit through debt, although that adds significantly to the risk if the business is unlucky with timing - PMO! A consequence for PMO is that following the restructuring it has lost a significant part of that debt gearing. I think ENQ is looking well placed. L3 - as I've said before, I don't see Oct 2021 as a make or break event for ENQ provided they are in the ball park.

Hi L3Trader, your post on 2P reserves wasn’t targeted at me, but I want to comment as a lead into a 2P reserves valuation exercise I did at the weekend, which was prompted by a comment by hitma1a on CNE reserves and relative value to ENQ. As a holder in both companies it made me realise I didn’t have as good handle on relative valuations as I should. Particularly, as my core strategy on the oil sector is to make aggressive trades between the oil companies I invest in, while maintaining a position in each.

First, your interpretation of AB’s 30MM bbls oil left in the ground comment. The slide showing 11MM of Thistle 2P reserves also showed 11MM of Thistle 2C. AC was referring to the Thistle and Heather fields and when he made his 30MM comment I doubt he was distinguishing between 2P and 2C. I believe 202MM is net of both Thistle and Heather, and the other stuff is small in comparison (IMO).

Back to my 2P reserves valuation exercise. I start out with 202MM, deduct expected 2020 production AND deduct 17MM for BP 37.5% share in the profits at Magnus and further 9MM for the PM8 PSC contract (I’ll admit to a wet finger in the air on that one). My interest in this exercise was driven by the recent sale of CNE Senegal interests, leaving essentially a cash shell (2020 YE) with just 35MM of 2P in Kraken and Catcher. CNE has 2C in these fields, and some exploration in Mexico, but I’m discounting all 2C in both CNE and ENQ.

I spent some time looking at 2C and exploration and decided that it is only really 2P that matters, particularly where the capital has been invested and the 2P is in production which is the case for ENQ and CNE 2P reserves. Examples of 2C valuations: CNE sale of 208MM of 2p and 2C for $300m, approx. $1.5 per bbl (here 2P can be lumped in with the 2C because while it is sanctioned it doesn’t include any capital expenditure); ENQ recent acquisition of 115MM Bressay 2C for $0.2 per bbl, which assumes the project goes to OGA; Parkmead, a NS minnow, picked up 34MM 2C as part of the recent licence award – free? 2C is peanuts because the world has loads of oil in ground. The gating element in moving 2C to 2P is economy of scale or infrastructure in place. If an explorer can’t hit a lot of 2C for <$3 per bbl it’s a miss.

Just room left for the resulting 2P valuations (I made numerous adjustments):
ENQ 2P $14
CNE 2P $15.9
PMO 2P $14.8 (I assigned $300m to Zuma, which I think is generous. With the current turmoil in PMO I expected this to come way lower, but it’s worse than it appears. Only 41% of 2P is oil. If I apply a discount for the gas, again I think I’m being generous, I get PMO 2P $18).

correction:
I'm expecting a 5K decline in Kraken through 2021, compared to 2020.

2P reserves YE 2019 - Slide 9 of the presentation shows 202MM with Thistle 11MM highlighted separately. Perhaps the AR shows something else but this is clear.

Worcester. At the Capital Markets day ENQ indicated c6MM bbls gross attributed to Worcester. In 2019 CNE added 1.5MM bbls to their 2P for their 29.5% share which grosses up to 5.1MM bbls. We know that ENQ and CNE attribute reserves to Kraken differently. I guess until the field is in production the margin on reserves estimate will be wide. Note CNE attributed 2P Worcester in their 2019 number. I'd expect ENQ to have done the same so the 202MM includes Worcester. It is normal to move 2C reserves to 2P when the development is sanctioned.

I don't recall an estimate for Worcester daily production, but if you fiddle around with their payback guidance you can get around 4,500 boepd on 6MM, and 3.7K on a 5MM number. Either way, if AB say's it's producing 3,000boepd, I'm okay with that. I wonder if the Worcester production will be reported as a separate field in the OGA data, like North Kraken. However, I'd guess the oil that comes out of the Worcester producer well is in proportion to the water injected into the 2nd well. ENQ will be optimising their finite levels of water injection to maximise overall production and recovery across the full development - getting that optimisation right is down to the brains in the organisation.

L3Trader, I think your hope for 40K from Kraken through to the end of 2022H1 is very optimistic. Refer to the production profile in the 2015 CMD presentation. I'm expecting a 5K decline in Kraken through 2020. If AB guides again for 30K-35K I see that as a good outcome. IN Q&A an analyst was pushing for Kraken guidance in 2021 and I took it that he'd be happy will 30K as the low end.