Member Info for londoner7

OAG release their figures on the 1st business day of the month. The last release was 1st Oct covering the FULL month of July - the 15th July date is a mid month value for the graphics.

Nothing reported for Hurricane/Lancaster so far, which is odd as we know they have been producing since June.

November 2018.
https://www.gov.uk/government/publications/oil-and-gas-taxation-transferable-tax-history-and-retention-of-decommissioning-expenditure/oil-and-gas-taxation-transferable-tax-history-and-retention-of-decommissioning-expenditure

'A Bovis shareholder said it would “need to come back with a lot of cash”. Analysts estimate the construction unit would need between £200m and £300m to survive without Linden. '

At least one shareholder has got their wish.

'A majority of the drop in production came as federal offshore Gulf of Mexico production slid about 332,000 bpd to 1.58 million bpd, the data showed.
Output in North Dakota rose by 14,000 bpd to a record 1.41 million bpd while Texas production climbed by 40,000 bpd, rising above 5 million bpd for the first time since the agency began tracking output in 1981.'

A trend or a summer maintenance (GOM) dip?

I think the most positive thing for anyone looking for a drop in Shale production is that growth is slowing.

A falling rig count is one factor but a closely related number is 'average production per rig'. All rigs are not created equal - it is probably the smaller, older and less efficient rigs that are being dropped, along with crews. This brings down the stock, which will impact over time. But OPEC has significant spare supply and the marginal cost of new supply is still well below current prices - I'm also an investor in CNE and expect them to sanction SNE before end 2019. If they pulled it that would be a positive indicator of supply constraint. But a more important consideration is oil demand.

Those of us watching knew what was coming with Kraken. Enquest warned on maintenance and replacement pipework - expect some impact in Aug too before we see what the S/C rework brings in Sept.

But Magnus!!! Enquest knew this number at the interims so I took a look back at their statement. Yep, it was in there. 'At Magnus, production performance remained in line with expectations with production efficiency of around 80%, including the impact of the planned three-week shutdown in May'.

L3Trader, it's good to see you took my comments as intended and demonstrate a sense of humour.

You ask, 'how do you get 7.4M recovered?' I use the OGA dash board. If I select Alma and Galia I get 7.4MM cumulative production to date. (I wonder if your number is Alma only).

https://data-ogauthority.opendata.arcgis.com/pages/production

I've spent limited time looking at the A/G development - to a large extent it's history - so I don't have full insight and may have errors in my assessment but as I recall my reading I struggle to understand what was compelling about the project. I saw about $1,500m net capex, which Squif confirmed. At 34MM bbls that equates to $44 per bbl capex! I feel this number must be wrong but don't see where - someone put me right. Enquest now has a 65% working interest - I don't know how that impacts the Capex number. The 7.4MM production to date is gross.

The field was abandoned at a 70% water cut. The Alma development concept was to produce from that historic level to 95%. To this non-oil person that alone sounds like an area where the 2P estimate could be prone to significant error. The OAG dash board indicates produced water in the low 90s for June - 36427/(36427+2944)=92.5%. (I've never worked water cut before so happy to be corrected).

As I say, it's history. Currently producing 2Kbopd net, but I wonder for how much longer. Enquest Producer had a 15 year field life expectancy so I guess there's value there - it's in the balance sheet.

Is there a read across to Kraken's 2P estimate? Enquest and partner Cairn differ - time will tell who is right.

On more general points, I noticed comments on definitions of debt, Opex etc. I think so long as an investor understands the various elements and includes them in their model the precise definition isn't material. I'm happy to go with Enquest's assessment of debt as being those components which carry a cash interest charge. In my model I account for leasing separate to interest. Whatever works for you.

karv1, the current BVS share price of 1102p includes roughly 84p of dividends/capital return due by year end, which will not be available to GFRD shareholders.

L3Trader, a correction.

Reading my post I note you did ask about the Western Flank, when you said, 'Could ENQ send the Enquest Producer FPSO to the WF?

I took that to be a joke. I don't know you but I'm guessing you have a sense of humour. Were you baiting us?

I was interested in the technicals raised by ProdOpt, but wouldn't know where to start in the financial aspects of either proposal, never mind moving another FSPO to the field. You were joking - right?

Next you'll be asking for my prediction on the Brent oil price next month!!!!

Hi L3Trader, I saw your earlier posts but didn't see much to respond too.

You didn't ask a question on the Western Flank. You asked, 'Could ENQ send the Enquest Producer FPSO to the WF? We know that Alma/Galia project failed, so can the FPSO be sent to Kraken? By the way does any of you know why Alma/Galia
did not perform?

I took that to be one for ProdOpt as it's way before my time - I came aboard in May this year but I'll have a go at current status. As I understand it the Alma/Galia is a 2Kbopd net (3kbopd gross) producer in decline with decommission plans in the pipeline. The 2Kbopd is useful but has it got 2 years, 5 years, or more? A concern here is the decom costs. The project was targeting 13Kbopd gross with $20boe operating costs in 2015. Recently Enquest said on A/G , 'The focus remains on production optimisation, cost reduction and the preparation of detailed decommissioning plans.' I am left with the impression that A/G may be producing little FCF and may soon be incurring decom costs. I'd expect these to be quantified in the next 12-24 months.

As a project it looks a disaster but then many projects kicked off in the heady days of $100 oil went that way. As you say the initial estimate was 34MM 2P reserves, but remember that is based on commercial recovery factors. Brent oil is no longer $100 and I'd guess costs are >>$20 bbl. That's why after 7.4MM of production (to June 19) and yearly production of 1MM pa the play is almost up. The 2P number will have been written down over recent years - we just don't see the detail/breakdown. I've commented on costs before - not including the FSPO charge in operating costs is misleading. My sense is that North Sea operations outside of Kraken and Magnus are >>$30 bbl.

Thanks for the link to Eagle. Very interesting. 8,500 bopd perhaps two years away, but short lived. If it works at the CapEx (tbd) then other opportunities in the area.

'The Issuer hereby informs you that the Cash Payment Condition has been satisfied in respect of the Interest Payment Date falling on 15 October 2019 and accrued interest on the Notes from (and including) 15 April 2019 will be paid in cash. '

API variations within a reservoir are not unusual. Google it and you'll find lots of examples.

You're all over thinking it.

There is a process to follow with the regulatory body. HUR has requested a suspension with gauges installed until 22 June 2020, when another request will be made. The plan is still to tie it into the AK, but before then it has a useful function to provide interference data from the other GWA wells.

it has a guage in it.

I think it's interesting that HUR didn't include any CapEx guidance in the presentation - some CapEx numbers were presented for 2020 and 2021 in the CMD presentation. This suggests to me that they have some options to consider which may differ from earlier plans.

This is the bit that caught my eye

'Hurricane continues to have a 100% interest in the GLA and is exploring a number of structures to fund full field development, including those that do not result in a reduction in licence equity. '

So Jefferies = Double A.

That makes sense wrt numbers. Thanks.

Beerbull, I agree, closure this year is important. But I'm relaxed on timescales and weather windows. The three well plan has only been delayed by perhaps two weeks on the Warwick Deep drill. The spud to results cycle looks to be about 2 months and the news on spudding the 3rd well is likely to come in the next week or so.

Storms can spring up in the WOS region anytime but I understand the worst weather is generally Q1. I've also heard there are some tough old boys (and no doubt girls) on these rigs but can't personally vouch for that.

romaron, I use the stock fact sheet on Barclay's Smart Investor website. I don't know if it allows non-investor access.

I've noted that the list is updated on the day or the following day of an RNS stating a change in holdings. That isn't to say it is entirely accurate but it gives me confidence. The list is substantially different from the FT list. I note that the FT doesn't include the largest holding 'Double A'. Double A Limited is a company beneficially owned by the extended family of Amjad Bseisu. Also of note, Jefferies isn't on the Barclays list so perhaps not so patient.

I'm in Scotland at a place I fell for on a fleeting visit a couple of years ago. After travelling for two years I planned to move to another of those towns 20-30 mins outside London - been there and done that twice before - but came upon this place and very happy. Now have the wonderful cities of Edinburgh and Glasgow on my door step. However, I'm a restless individual - a year from now who knows.

Just about to catch a train into Glasgow to catch tonight's game at the Spurs Supporters Club.

donnodertrader, you raise an interesting point but I have no idea whether ENQ activities to attract IIs is at fault. ENQ employ an II relations manager as well as a PI relations manager. I'm sure the IIRM is on the task and would be happy to answer any questions on his activities. Most of my PI questions to IR are addressed by him.

I took a look at the latest II holdings. Your 8th Mar list is out of date and Blackrock no longer feature above 3%, but other significant institutions have joined since - Schroders and Aberdeen are two. (In practice these IIs sometimes swap holdings outside of the market).

The good news is that there are big IIs invested in ENQ so are alert to developments. As an exercise I looked at the % II holdings (>3%) for each company. CNE is 70% and ENQ is 40% so scope for improvement. But it should be remembered that the Rights Issue was only one year ago. While that might seem an age to the retail investor looking for a quick return it's a short time for IIs. Retail investors like to bottom fish and can be very vocal and impatient on these boards when the rest of the world doesn't see things their way. The 12,000 retail investors in SXX 'hanging in there' is testimony to that.

romaron has frequently raised the profile ENQ has in the credit market as being a negative for the share price. I'm sure he's right and IIs will have investment constraints in this regard. I support Tottenham Hotspur, the best football club in the world. If they have a hic-up and dropped a division I'd still be a follower. I don't view Enquest in the same way. If I don't think they'll make me money I'll take my losses and go else where - key, I invest in more than one oil company so my loyalties to any one, hopefully, are irrelevant. I was here and holding around $60 oil, feeling okay. Feeling much better at $65. But if things go well for Enquest I don't expect to exit tomorrow, next month or even next year. If things go well I hope to exit because I consider it is over valued in say 3 years from now with oil averaging at least $60 during the interim. IIs will have similar timeframes.

I agree, it was AS who raised the prospect of bringing the Rona Ridge wells forward to 2020. His prime consideration seemed to be whether it was HUR that broke the news or the drilling contractor. Let's see if he takes the opportunity this Friday to be 'first to the post'.

On cash flow the step that made this a possibility is the higher cash flow due to 'covering' the 15% FSPO downtime during the uptime. HUR could end the year with $150m in cash. Slide 21 slows their expectations for cash flows and Capex through 2020.

$47m from HUR covers the full tieback of the LC and the gas export requirements, leaving the 50% of the 3x GWA wells to fund from the balance of what appears to be $120m 2020 Capex guidance. The guidance for the Rona Ridge wells in 2021 looks around $100-120m. This looks very doable in 2020 from HUR cash flows.

It is only two and a bit months since the CMD but I for one will be listening for any stronger hints Friday as to whether this work is brought forward. If successful the payback on de-risking the GLA area further, i.e. in addition to good progress on the EPS would be significant.