Member Info for londoner7

Pelle, chilting, I hope you don't mind me jumping in on this (Kraken maintenance question).

It isn't rocket science to understand the relevance of the timing of maintenance schedules with associated loss of revenue and increase in maintenance capex, to the timing of a 'reduction' of $100 to the RCF. Based on other dates associated with the credit facility I believe the $100m reduction occurs 15th Oct - DYOR. The final 2019 bond interest payment of approx. $30m is also due in Oct, so I see 15th Oct as the next liquidity hurdle.

On 21st Mar, on Kraken, ENQ said, "A three-week maintenance shutdown is scheduled for the third quarter."
At the latest update 23rd May ENQ said, "The planned maintenance shutdown at Magnus was completed in May, with the remaining programmes at the Group's other fields expected to be executed by around the end of the third quarter."

Those words are carefully chosen. I'd guess that ENQ have specialist staff (or contractors) for maintenance activities and will want to phase the activities across the various fields, so I'd be surprised if these activities are not started soon on the smaller fields. Posters here have indicated that there could be significant works scheduled for Kraken. If so, I anticipate two consequences, first, as Pelle says, the schedule is (date) fixed with key people involved, and second there is an increased risk of delay in completion. For these reasons I suspect Kraken will be last in line - provided the 12 day offload cycle holds.

That all said, I see 5th Sept as the key date. Alongside the H1 numbers I'd expect a clear statement on the schedule for maintenance and Capex. News of an early repayent/reduction in the credit facility would be nice.

Like many here I'll be watching those tanker offloads from Kraken. Each one is worth $20m net cash.

chiltering, thanks for the Moody's reference - I hadn't seen it before.

An interesting read, a bit like a school report card, pointing out the room for improvement, As you say, achievable.

The reference to 2P reserves is interesting. It highlights the market sensitivity to any impacts such as that CNE write down on their Kraken reserves earlier in the year. Maintaining current Kraken production and progressing to development of the western flank in 2020 will be key, as will Magnus development with the ongoing 2 wells p.a. programme. I note that the 2019 PRP (3 year) target for reserves is +5% for the threshold payment and +10% for maximum payment so I guess that puts the reserves target in sight.

I still think that 70K production this year is a challenge - needs maintenance of the June Kraken production number through H2 and I think the impact of maintenance on minor fields may be greater than anticipated. That said, there's upside potential from any further improvement at Kraken, new pipework at SC and Magnus could surprise - I'm looking forward to the Magnus June number.

How dare Investors Chronicle write a negative article when we know that companies only grow and share prices only go up. ;-)

When I saw this link I thought great an IC update on Enquest, but then realized it's an old article. I read it when it was released 17th Jan. It’s easy to forget Enquest’' position at the time, there had been a rights issue for £107m, Kraken output was falling and Brent had just dropped to below $55 and was sitting around $60. My conclusion at the time was, too risky, but noted Enquest's strong gearing to a better oil price.

In May, following a Cairn update, which drew my attention to Kraken, I took another look at Enquest. Brent had been on a roll, peaking at $74, but importantly had been above $65 for over 2 months. I appreciated that could have a very favorable impact on Enquest's finances, so took a closer look. I also looked again at the IC article. I felt that Barclay's and RCB were a bit more negative than my view but not by much, remember that the Barclay assessment assumed a Brent average of $60 for 2019. The Enquest update also stated that Kraken had bottomed in Feb and was now improving. I opened a position in Enquest, which I have added to as my knowledge improved and confidence in Enquest meeting their upcoming liquidity hurdle increased.

Today I've read the IC article for a 3rd time. I wish Investors Chronicle produced a similar critical review of every investment in my portfolio alongside broker comment, although even in this piece I'd have liked a bit more detail.

I prefer my investment decisions challenged.

Hi L3.
Cairn's comment
https://www.petroleum-economist.com/articles/politics-economics/europe-eurasia/2019/interview-cairn-energy-targets-transformative-changes
I posted a week or so back on my interpretation.

Thanks for the link to the Capital Markets presentation - oh those heady days of $100 oil. Slide 35 refers to the 10M fuel. Slide 39 is interesting but confuses the fuel question. 5MMscfpd produced and 15MMscfpd imported making a total of 20MMscfpd - for what? 20MMscfpd gas supply is about right for the FSPO's 62MW generator. I've had my doubts that a generator would run on API12 crude, but other posters here have said it's designed to handle it. I'm still doubtful and the fact that ENQ and OAG oil numbers match suggest no crude is used as fuel. Does anyone know if a 15MMscfpd import pipe was constructed?

I hadn't seen a reference to Kraken Central before - I guess this is the DC4 development.

IRR, what's that? Oh yes, it's one of those numbers put out to sell a large capital investment to investors, and they bite every time! We're way past that. The money has been spent, for better or worse, and the share price reflects it. What matters now is ongoing capex, production volume and the price of oil, or as I prefer to think of it 'netback' per barrel. Yes, a heavy oil premium on Brent would be good, but has it ever been confirmed?

On reflection I'm more relaxed about Enquest hitting their near term liquidity targets than I hinted in my earlier email. I had in mind the outlook from the start of the year but we are now into H2. The cash position 4 months in looked good, and by my estimate Brent has averaged a $1 or two above my reference $65 bbl, and has just ticked back above that level. I'd guess that as long as Kraken can produce for 12 day offloads the planned Q3 maintenance will be held off till later in the period - I think the $100m RCF limit reduction occurs 1st Oct.

Magnus has been in slight decline since it peaked at 18.6Kbopd in Jan. Last OAG report was 16.8Kbopd in April. We know there was a 2 week maintenance period concluded in May so that number will be down but with improvements to water processing I'm hopeful June will see it back above 18K. I'd expect news on the new Magnus wells at the next update - one of those capex options available to ENQ to clear the next liquidity event.

Hi L3, both ENQ and OAG (oil) have provided numbers for the first 4 months - each has an average of 28Kbopd for the 4 month period. For Jan - Apr OAG (oil) was 23.7K, 21.7K, 32.3K & 34.4K.
My estimate for May is 37.4K - 38 Kbopd, and for June is 42.4Kbopd - this is based on tanker assessments to 7th July. Obviously, I can't determine the relative performance between the last week of June and the first week of July, so any adjustment gets carried over. Hence my range for the May number.

I haven't seen the 148/10 numbers you quote. 6.8% seems high - perhaps this includes fuel and shrinkage. However, gas will account for 2-3%, which isn't counted in ENQ numbers.

Hi gkb47, they check out. I'm not looking at any distinction between AB and the foundation but according to this website since (and including) 29th Mar 2019 Amjad Bseisu has 'notified' the purchase of 7.8m shares or 0.5% (0.46% to be more precise), as I stated . However, looking at the Barclays site I note that they show two additional purchases in late May bringing the total up to 8.6m.

I didn't refer to his total holding but your 6m number looks very short. There were 43m bought in the last year's rights issue. Barclays website has him down for 167m (10%). As I said I don't make any distinction between AB and the foundation.

skippy999, I understand your concerns about Peter Tom. No doubt he has been a big force in the development of Breedon and until two years ago Breedon had been a great contributor to my portfolio. What's happened since to cause the SP fall from grace? Primarily, I think the issue has been costs - the big recovery in oil impacting Bitumen pricing and carbon pricing impacting cement costs, particularly last year. It was only the acquisition of Lagan last year that kept earnings per share in growth. I saw those cost impacts too late to react but I've been watching since, and both have stabilised to a more manageable level. I calculated that in 2018 Bitumen costs impacted EBIT by £8.3M and cement costs hit Breedon to the tune of £2.4m. The impact on Lagan cement could have been another £1.5m. That a total hit of £12.2m on the final EBIT number of £103.5m - quite an impact. The unknown is to how much of the 10% revenue growth reported for the first 3 months is pricing rather than volume. We'll know more later this month.

Back to PT. He's still mates with the current crew so I'm sure he'll be asked for an opinion now and again. That said, I think the big M&M and capital decisions have been taken for the medium term. so focus now is on squeezing the existing assets. With over £100m of cash being generated each year I suspect dividends may be back on the agenda unless theirs another acquisition soon, and I suspect that would at most be a £30m infill.

I was encouraged by the new chairman's wiliness to take PT's share offering at 72p. Unfortunately, liquidity was overtaken by the Woodford woes. I'm pleased to see from today's RNS that another chunk of that overhang has been cleared.

I would argue that AB's purchases have affected the share price, but I think the impact is more sentiment than numerical.
Since he started a frequent buying programme on 29th Mar he has purchased 7.8m shares which represent approx. 0.5% of the total capitalisation. While we might expect to see a significant impact if such a purchase was made in one day, over 3 months any impact would be negligible.

However, I for one am encouraged by his buying and probably have a slightly greater holding than I would without his buying - albeit my holding represents less than a normal stake for me, as I'm still assessing the stock.

Reflecting on his recent purchase I wonder what does he know that I don't, and what is his risk profile if say the oil price dropped below what I consider a key range of $60 - $70 bbl.

I'm okay with where the price is now - I think ENQ would get through the upcoming liquidity challenges - but I am nervious at $60. I don't think AB has any better insight into the future direction of oil but he does know liquidity thresholds and the company's options.

I've just started to take a closer look at AB's incentives, salary, bonus etc. and while the detail of the recent report only covers 2018, with 2019 rightly deemed commercially sensitive, I'd guess there is a strong read across. In 2018 30% of weighting was to prodcution growth and 30% weighting towards debt reduction. While AB can have a strong influence on production growth, debt reduction is more closely linked to the oil price.

For example, I believe the the H1 Kraken gross average production will be 32Kbopd, after my estimate of 42.4Kbopd for June. If 42.4Kbopd is maintained for H2, deducting for a 3 week maintenance window in Q3, the full year average would be 34.8Kbopd (24.5Kbopd net to ENQ) right at the top of the forecast range 30K-35Kbopd. Based on 50K peak gross that's an 85% production efficiency for H2. Let's say it hits 90% PE in H2. Then the 2019 average would be 35.9Kbopd gross (25.3Kbopd net). An increase in net production of 800 bopd, which at $65 oil, $5 transport and fixed costs equates to an additional $17.5m FCF.

I think that ending the year with Kraken performing at 90% PE would be a good operational/management performance, but putting this additional cash flow into perspective, an additional $1 on the total ENQ production of 70Kboepd equates to an additional $25.5m FCF. To clarify, an extra $1 average on the oil price beats an 1,165 bopd increase in yearly production.

AB can't affect the oil price, but he can affect the performance of Kraken. I wonder if the 2018 10% bonus weighting on the sale of up to 20% Kraken has been extended into 2019.

Incidentally, another 10% weighting was assigned to 'liquidity management - funding arrangements'. This was paid out so I'd guess the RI, OZ loan and Mercurial loan were considered success stories, in that ENQ is still solvent.

Hi MO, very similar numbers to mine. I have a detailed data sheet for the Amundsen class, cargo, ballast, etc and then scale for other size tankers - I've dropped my focus on gross tonnage. By design rules her ballast must provide a draught of at least 6.9m, so my assumption is that she arrives with full ballast and no ballast on departure. In my spreadsheet 12.1m equates to 507Kbo and 12.9m to 560Kbo Looks like we are working from similar data sets.

I use departure times for cycles and recorded 12.8 days for this one.

I'd estimate a depart at 2pm

TimTimebomb, in one sentence you cover three key factors affecting Kraken production, fuel for the FSPO, load size and Cairn's 50K comment. The comment was, "The last few weeks it has been doing over 50,000bl/d."

Fuel oil - some wells are 'plug and play', Kraken isn't, it requires a lot of energy to extract the heavy oil through heating, water injection and liquid handling. My understanding from informed posters here is that the power unit is around 62MW, split into four separate multi-fuel units, and fuel consumption is around 1,500 boepd. Based on EOG data at 40Kbopd oil production gas production is <1,000 boepd so some extracted oil would be used. However, even if gas wasn't used 1,500 bopd doesn't make up the difference you ask about. Incidentally, excess gas is flared.

Load size - my understanding is that cargoes are 'allocated' to customers up to two months ahead of lifting - taken from the rights issue document. To me this means that an order will be for say, 500Kbo, so in this case a shuttle tanker will take off 500Kbo and no more. It doesn't empty the FSPO storage. That isn't to say that there might not be an order for 525Kbo or 550Kbo, but with a 600Kbo FSPO capacity there isn't much margin for error on a facility capable of producing over 50Kbopd. ENQ would not want to shut down production because the storage tanks are full. On these numbers a 12 day tanker cycle equates to around 42Kbopd. A recent tanker cycle was just over 11 days. If the tanker cycle maintains 10 days then I'd go with 50Kbopd production. I know other posters have a different view on this but that's my take. If a tanker slows down on it's approach to the FSPO then I interpret that as an sign that there isn't 500Kbo available or there's a problem with the weather. I think load #36 (1st May) was an example of the former and explains why April production was 34,366 bopd and not the 40Kbod predicted on the two earlier offloads (#34 & #35).

Cairn's 50K comment - I think the Cairn CEO is referring to reservoir performance rather than production efficiency and I think the comment is very encouraging. Even outside of the planned maintenance window - 3 weeks in Q3 - production efficiency will not be 100%. I'd say that >90% would be good, >95% excellent, which equates to >45Kbopd and >47.5Kbopd respectively. I don't have any first hand knowledge of the oil industry but I'm an engineer and would guess that while some issues will force a complete shut down in production others may be delayed, so if a tanker is on her way and an issue occurs, within the bounds of safety, everything will be done to get the required oil into storage before shutting off production. Extending this view to load #36 I suspect a forced shutdown occurred a few days before the end of April with a tanker already commissioned. A day or two after arrival a decision was make to do a partial offtake. Production was restarted and 8 days later the 500Kbo order was completed.

Thanks for the clarification.

Hi chilting, I was looking at the NA vessel details when she moved off. I noted the destination wasn't right but just wondered if it might be bogus as it highlighted as "not recognised". That's why I put it out for the more experienced ship watchers. Yes, AS looks a candidate but some way off.

Thoughts?

No, Strawn wasn't that bad. It was generating cash at the operating level, probably the $75K they got over a two year period. I guess Mosman felt that $75K in the pocket now is more valuable.

Posters shouldn't confuse operating cash with the profit loss account. At the P&L level I'd be surprised if either Welch or Arkoma are profitable. They generate cash now but that's after a pile of cash invested.

I smiled at the idea that anyone would put out an ENQ earnings estimate for FY2023.

I've just seen the media presentation so wanted to add that it was much in line with his presentation. This might explain why he wasn't around during the coffee break. I guess he decided he'd have an easier time in the studio than facing me ;-)

Two other points from yesterday. A key attraction with the Champion project is that key infrastructure is already in place from previous developments, pad, roads, etc. The Santos drill was a significant part of yesterday's presentation but I haven't reflected on it because I'm unsure of how it pans out one way or the other and I find the update on negotiations over access for seismic odd considering how long Mosman has had the licence. Great if it pays off but IMO one for the traders.

Out of space on previous post.

I didn't expect a production update. I'd expect one in July for Q2, H1, and I'll be looking for sustainability on Arkoma - it's now a large part of the mix.

The regulator/hostess asked the best question, "When do you expect to be profitable at the corporative level?". Andy. "After the next two wells."

I attended yesterday's Oil Capital Conference.

Seven companies presented. The format was a 20 minute presentation followed by a 10 minute Q&Q. About 150 people present, difficult to split but I'd guess less than 50% private investors and the rest from the industry, analysts, funding, etc. Of the 8-10 people I spoke to during the break-outs none were PIs, and there were very few questions from the floor, hence my assessment of <50% PIs. Fortunately, the regulator/hostess performed an excellent role in padding out what would have been dull Q&A sessions - she asked the best questions.

With a couple of exceptions the presentations were forget the past, I've a new story to tell, this time will be different. I'm always struck by how many ways there are to sell an oil investment. The term 'snake oil salesman' always springs to mind. That said, I found it interesting and the day expanded my views of the industry. I'm surprised more investors don't take these opportunities to meet and question. Senior management presented except for the Head of Investor Relations for PMO. The young lady did an effective presentation but if I was attending as a PMO investor I'd have been very disappointed not to be able to question key management.

Andy presented for Mosman and was up first. No doubt you've seen the presentation and yesterday's news update. The decision on S3 is recent. The presentation isn't fully up to date with developments but it's a minor point. Slide 13 first and second projections need a refresh with the new mix..

I'd seen the RNS before the presentation and picked up on a couple of things on Welch and E154. In May the Welch comment was, "At Welch, consideration is being given to further workovers to further increase production levels". Yesterday's update was, "Routine workovers are being performed at Welch to maintain production". A subtle but important difference. One that seems to be missed on some posters here whose expectations for Welch exceed BOD guidance as presented in slide 13.

Mine was the first and only question from the floor and in view of the presentation comment that Strawn, Arkoma and Welch workovers are complete, I asked why news of a requirement for Welch workovers but not Arkoma and therefore whether the surprisingly good Q1 from Arkoma was sustainable. I don't think Andy was ready for a question on Arkoma and went slightly off tangent, by then I'd lost the microphone but was able to get back to the question and I essentially got an answer, with some reading between the lines.

Welch is old infrastructure which is prone to rod breaks etc. The weather window for fixes is now. Stanley flows without assistance. Andy didn't state it, but Arkoma is ESP - usually good for a few years but when they fail expensive to replace. Arkoma is not Mosman operated (27%) so I sense the operator is doing their stuff and Mosman is hoping for good results.

It wasn't a question, it was a statement. We will know their approach on the 11th.