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I forgot to add. Our highest ever rating was in March 2014, B1 outlook stable. In Dec 2014 we began the descent, B1 affirmed rating negative.
Hi ProdOpt, I liked the Sirius story but after a bruising encounter with Xcite I have stayed away from stocks with potential and dreams but a lack of cash. We had passed tilt with Kraken and couldn't stop. It will be a success story and all credit to the management for saving the company. I was out last night with two other EnQuest investors. Both ex investment banks working in structured debt. Each of us are frustrated by the undervaluation of EnQuest. A loose consensus was that debt is the reason. Debt is always the driver unless you have none. The analysts and funds have strict guidelines when running the slide rule over companies. They are almost stuck between tram-lines and are interconnected with credit rating agencies. These rules are rigid and it is painstaking to climb higher. We are still within Moody's rating "Highly speculative" and it was only in Nov 18 that we moved up to B2 from B3 CFR and the HY notes to B3 from Caa1. That meant the bonds moved one step from "Substantial risks" to "Highly speculative" so at least the CFR and bonds are together now rated in the same subset. A move to B1 would put us one step away from becoming "Non-investment grade speculative". I summed it up by saying that these priests of high finance aren't paid to think out of the box but preserve wealth.
And we think tankers move slowly!
I know someone who worked for Moody's and they said that as long as EnQuest are not "On watch" I should relax.
ProdOpt, I'm still digesting the ramifications of the points raised in your excellent post.
Like romaron I enjoy trying to understand that stuff. Unlike romaron I have the advantage of being an old school electronic engineer which means I've also a background in fluid systems amongst other disciplines, but nothing like enough to play more than a passing interest in the detail you raised.
As an investor in Enquest my goal is to try and understand how my investment is impacted. To recap the essentials, the challenge next year will be to add the Western Flank extension with minimal impact on existing Kraken operations. Interesting in light of the news that the 3 week maintenance planned for this quarter has now been postponed to next year. This became an option when unplanned shutdowns in July and August (apparent in tanker offloads) allowed some of the planned maintenance to be brought forward. While there's still some impact expected over the coming weeks, the opportunity/decision to move the 'large' shutdown to next year may also accommodate works on the WF ext.
If the WF ext challenges you raise are not explicitly referenced by Enquest I'll be taking particular interest in guidance on Kraken production for 2020 and maintenance activities, in light of your post.
* I took a look at your earlier posts. Interesting stuff. The Magnus note on WAG caught my eye but I struggled with the abstract so the full document would be wasted on me. But your thoughts on implications for investors would be appreciated.
Romaron,
Unfortunately I have a lot of Sirius shares ... Certainly hoping my Enquest position in time can mitigate some of the loss. Happy Enquest should no longer have to worry about securing more debt, and the only risk is a complete collapse in the oil price, which would require economic changes that would threaten a number of other aspects of our lives.
It's a challenge for sure and although I'm no engineer I do find this stuff fascinating. Sorry for anybody holding Sirius this morning and I thought "there but for the grace of God go EnQuest". Oil like any other business is always about money. I'm no longer concerned about our viability and happy to sit back and watch the company do what it says on the tin.
Be Lucky
romaron, the 'old stuff' is interesting. Helps understand the distinction between oil density (API) and viscosity (cP). Clearly, it is the oils ability to flow (viscosity) that is key to getting it out of the ground. But your friend's brother was clearly alert to and wary of the 'gentleman from Enquest'. when he says, 'Was the gentlemen from Enquest saying that the oil in Kracken flows without AR(artificial lift)? I know nothing about Kracken but saying the oil flows out of the ground without the need for a pump is a little surprising.'
Of course we know that artificial lift using HSPs is used to extract Kraken oil.
https://www.spe-uk.org/aberdeen/wp-content/uploads/2014/07/16.-The-HSP-Versatile-Artificial-Lift-Choice-for-the-Heavy-Oil-Subsea-Kraken-Development-EnQuest.pdf
The amber warning in relation to HSPs (slide 8) is interesting - Top side fluid handling burden. I'd guess that's the challenge the FSPO is struggling with.
My conclusion - if we need additional hot water handling, 'We're gonna need a bigger boat'. ;-)
https://www.youtube.com/watch?v=2I91DJZKRxs
ProdOpt's post made me go over some old stuff. I first invested in EnQuest because I was concerned about an investment I had in Xcite oil which meant I took a loss and exited. I lost a lot of money but saved a lot too. I had another contact (still have) whose brother is high up in BP and he wrote this in May 2015 post EnQ AGM.
"Mariner FDP was sanctioned by DECC in Feb 2013. There have been a series of contracts awarded to contractors for Mariner between October 2012 and Feb 2015. (totalling 16 so far). From what you write Neil McCulloch is saying the issue with Mariner and Bressay is that they’re not aligned with their economic requirements, which is an entirely different issue. That doesn’t actually mean they’re not making money, perhaps just not to the margins they want.
My brother, who works for BP wrote to me recently - "The field is Bentley which is a high viscosity crude. It could be challenging to produce at $60 but with estimated 250 million barrels one of the largest North Sea fields going.” His reference to $60 is the brent price. So you can see there is general skepticism in the industry at Xcite’s pricing.
API vs Centipoises
I started writing a reply on the MBB about this the other day but gave up. They are quite correct though. API is a measure of density. Oil API below 10 is denser than water, and above 10 is lighter than water. Whilst there is obviously a correlation between the heaviness of oil and it’s ability to flow, it’s not that straightforward. Centipoises (a division of poises, similar to centimetres and metres) is a measure of viscosity. This can get very technical, and is one of the reasons why my brother is as well paid at BP as he is. He’s their go to guy when they have issues anywhere in the world with this sort of stuff. (I read his PhD thesis once, it made no sense at all to me).
and this from the Canadian guy:
"The champagne reference is clearly a comparison between the bitumen that is mined or uses SAGD in Northern Alberta and Kracken oil. It resembles a plastic more than oil. I have gotten it on some downhole tools I was running when perforating gas wells. You can literally peel it off the tools with a knife in strips. But there are other fields in Alberta that have heavy oil cold production, like in the Lloydminster area where I live. Which I’m guessing is very similar oil to Bentley without the great reservoir characteristics that Bentley has. So making a comparison between bitumen and Kracken heavy oil is like comparing chalk and cheese.Was the gentlemen from Enquest saying that the oil in Kracken flows without AR(artificial lift)? I know nothing about Kracken but saying the oil flows out of the ground without the need for a pump is a little surprising. Or is he saying that SAGD or some other expensive method isn’t required? The gas pressure required to lift even a medium crude to surface without a pump is something that I haven’t seen. Typically flowing wells are very light oil. "
'2010 H2' Yep, that's a challenge.
I meant 2020 H2 (next year).
Hi ProdOpt, an interesting and technical post.
I've recently seen the comment, 'Fairly mature technology for Canadian heavy oil, but limited use offshore so far', in relation to Kraken's current operation, which blew a hole in an ill informed comment I made recently about engineers finding solutions to current Kraken issues - perhaps that still true but at the time I made the comment I wasn't aware how groundbreaking the Kraken development is! But back to your post.
My assessment of your comments is that the current demand for hot water from the FSPO will not diminish with fall off in oil production from the current well stock so either hot water capacity is added to the FSPO to support the Western Flank development or an alternative solution is developed. Hence consideration is being given to the 'downhole electrical heating and ESP' solution.
Grit in the flywheel. But at least romaron is confident a solution will be identified and implemented by 2010 H2.
Love your posts ProdOpt. A couple of points that may or may not be relevant. Our oil is very similar to Captain with similar cp but a lower API (14 v 19-21). Mariner is split Maureen67 cp & Heimdal 508cp (Kraken 78-161cp).
Your reference to Canadian HO reminded me of an investor in Bentley who worked with Canadian 'Tar' and wasn't deterred and Jim Buckee who famously said that Kraken is like champagne compared to Canadian HO.
HO brings its own problems and they are clearly not insurmountable but have a cost. I like that you say some of the technology is mature but has limited exposure offshore. This means that it is clearly a consideration for Equinor (Mariner) and the likes of Schlumberger. There is a lot of money and other parties interested in solving what you rightly call a 'challenge'. With OGA banging head and encouraging collaboration I feel confident an economic solution will be found.
Expanding Kraken without significant redesign of the FPSO is a challenge. Engineering design work appears to be starting at Enquest on how to add capacity to the FPSO for Worcester and Western Flank production without needing to add additional capacity for more hot water to power Hydraulic Submersible Pumps from the FPSO. Enquest looking at possibility of downhole electrical heating and ESP's, as having the least impact on the FPSO. Might be combined with vacuum insulated tubing to mitigate heat loss downhole. Fairly mature technology for Canadian heavy oil, but limited use offshore so far, and in different applications (to avoid wax formation, rather than produce heavy crude). ESP's will have a shorter run life, incurring OPEX for changeouts, than HSP's, but an easier and less CAPEX intensive option than expanding further the hot water treatment and pumping capacity while simultaneously producing offshore.