Member Info for Slift

Pages 11 and 12.

No mention of side track, but I'm under the impression that's what HUR are doing following past few RNS'..?

adoubleuk,

"Please elaborate."
Water injection is a technique used to provide pressure support.
The "future development plan" as according to the ERCE CPR only includes a sidetrack well P8; namely "Development Pending".
The water injection development plan for the CPR report is "Development Unclarified", i.e. HUR have not fully taken on board that idea yet.

So now the future development plan (the pending FWP), only includes a P8 well without any pressure support.
So to re-iterate:
The CPR indicates that the future development plan requires the field to be produced BELOW the bubble point.
HUR have also submitted an amendment to OGA to allow for production below bubble point.

The FWP kickoff is approx. 11months away. But this will be sanctioned a few months in advance. No reason to submit an amendment right now if the pressure support is going to hold for the next 6 months+.

And the answers to those questions regarding conditions:

Buybacks - There is a covenant prevents HUR, BOD or anyone directly linked to management of HUR from buying bond notes on the public market (at a discount). I believe HUR can only buy at full face value or above.

CAPEX - Yes, provisions in place to deal with CAPEX. But not only CAPEX.. but also right issues, share consolidations, share splits, etc.

Several other covenants too, which make it very difficult for HUR to secure new funding or loans.

The CPR indicates that the future development plan requires the field to be produced BELOW the bubble point.
HUR have also submitted an amendment to OGA to allow for production below bubble point.

I think it's safe to assume that the downhole pressure data will have reached bubble point in the next few months. I'd give it 6 months tops based on economic limit provided by ERCE.

Therapist,

Yes, both 2013 and 2016 information (Xcite and Whalsay) both had a similar development to bring the field to first oil.
Which was a first phase development plan for $700m, and as romaron correctly pointed out in a past post, it was simply an early production development with a couple wells; namely 7 and 7Z well which were already drilled and suspended.

So what would Xcite or Whalsay have got with $700m?:
- A manned production, utilities and quarters platform manufactured/modified with 20 slots for production wells and water injection as well as facility to de-gas the crude. (FPSO)
- Re-entry to well 7 and 7z (from suspension) and tie back to FPSO which would bring the field to first oil.

Following first oil, the infrastructure and facilities will be in place to further develop the field. However, with just those two wells, flow rate would have been 2-3k bopd.

Both 7 and 7Z have been P&A'd now.

The problem with Bentley is the payback period.
For ENQ, they can choose to re-drill 7 and 7Z or drill two new wells and tie this back to existing infrastructure.
2 new drills will cost c. $60-80m each to drill and tie back, as an estimate.
At $160m development cost and a flow rate of 2-3k bopd, over 5 years will provide (assuming wells are economic for 5 years here):
- c. 4.5m reserves
- Assuming $60/barrel average for the next 5 years, the development will provide ENQ with $270m revenue.
- It will take approx. 3 years to payback drill costs.
- Taking into account OPEX cost, FPSO modification, Decom, other liabilities associated with the development, ENQ may just about make a small profit here, over a 5 year period.

Basically, Bentley will only be commercial and economical (for ENQ) if there is confidence in the market for longterm oil prices of $60+/barrel.
But personally, the CAPEX should be spent on developing other more economical fields before thinking about Bentley. But it's always nice to have this field for the future, should any opportunities arise (oil price dependent).

mrc,

You're no longer worth replying to as you come across as an idiot. I'm not even using pricing and costs relevant to a decade ago.

"Xcite were looking at billions to develop the field whereas it is now estimated under $1 billion before any kraken / hub synergies."

From Xcites' RNS:
"Assuming a two year lead time to first oil, the economic projections in the Form 51-101F1 assume that capital expenditure incurred in 2013 to 2015 to take the Field into production in late 2015 will amount to approximately $700 million."

https://www.investegate.co.uk/xcite-energy-limited--xel-/rns/reserves-assessment-on-the-bentley-field/201304080700077491B/

Bye.

mrc,

I think you're just lacking a little research there.

Kraken crude is premium.
It's all to do with downstream processing and margins on that.

Don't compare Kraken to Bentley. The viscosity differences is significant. Kraken doesn't require much for oil to flow.
Bentley: 1500cP (which is actually defined "extra heavy crude")
Kraken: varies between 78-161cP

Not to mention lower reservoir pressure associated with Bentley oil in comparison to Kraken, it really doesn't help the flow of oil.

Isn't that what a CPR is? lmao

Also worth mentioning that Bentley crude is estimated to have an approx. 12% discount to Brent.

Romaron,

Yes, the $47.7/barrel figure was stated in that initial RNS by Xcite.
This was the figure for development, OPEX and Decom.
However, their FDP for the field was more of an EDP. I'm not sure how they got their inexpensive development costs, but comments from Steve Kew seem right to be regarding development costs ($80+/barrel just for full field development), and then with OPEX and decom costs, you're looking at more towards $90-100/barrel.

The reason being mainly because it's a heavy oil field, with significantly higher viscosities than light oil or easy to flow heavy oil. I'd assume that the flowlines will be required to be heated to aid flow of Bentley oil, etc.
Furthermore, as a standalone field (the situation Xcite was in), the cost to develop would have significantly increased with the requirements of unique FPSO being ordered for the heavy oil, etc.

As hitman1a states, the flow rates from each well will be very low. Again mainly due to viscosity and heavy oil characteristics. These flow rates are likely to be rates WITH heated lines.
However, it's not as simple as "just need another slot in Kraken FPSO" to partially develop the field. I'd imagine the Kraken FPSO will also require some modifications to be able process the heavy oil.
However, there is potential for Enquest to target high pressure, high wellhead temperatures/reservoirs in the field to get the heavy crude flowing and provide heated flowlines to a modified Kraken FPSO. Also targetting quick payback wells will also help.
Overall, development cost for this would be around $40-50/barrel, imo. Since Enquest already operate Kraken FPSO, the OPEX cost however for this would be minimal.

Also at current oil prices, not all 250mmboe 2P reserves would be economical. As mentioned above, if ENQ target quick payback wells and those with decent reservoir pressure/temperatures, then some of the reserves could be monetized. As a pure guess, i'd imagine maybe 50-60mmboe of 2P reserves COULD be economical at current oil prices.

That figure of 50-60mmboe could even be lower in the current uncertain times and will still require a significant amount of cash to develop and isn't really the time currently for ENQ to do this, IMO.
But i'm interested in AB's plan for this field as development and tieing back to Kraken will definitely have a significant material impact on ENQ's SP.
All in all, i'd rather not speculate nor be very optimistic about this field. Afterall, just acquisition for $2m is a great balance sheet boost, which should sit well with increasing net assets and refinance of RCF.

I think every CPR I've read has the SPE guidelines in the Appendix.

Afterall, the CPR is based on SPE guidelines.

It doesn't matter whether there is a FB expert or not. The SPE guidelines of estimating resources and reserves is applicable to both Conventional and Non conventional fields.

The "CPR" is just an analysis using Hurricane provided data in line with SPE guidelines to estimate the resources and reserves.
All the data they were provided us included in the report.

I don't have a problem with this CPR as it's to guidelines. It's just a "verify" using HUR data. It's not like ERCE work at HUR not have they been to site.

However, there is a huge error in table 3.6, which also came up in the summary.
Now that's ERCE's incompetence, whether they made a mistake, or haven't checked their work properly, who knows.

No, there will be a shortfall here for debt repayment.

Hurricane have clearly stated multiple times.
It's either significant dilution and CB extend bond, or HUR operates until uneconomical, at which point, the remainder of funds will go to pay off CB.

Is that all you got?

Nice gamble.

IMHO, FatSam82 is going to lose even more money here.

No idea why people even compare this AIM listed producer with mid sized oil producers..

First TLW.
Now ENQ.

Simplywallstreet does say HUR is worth £2.50, so must be true!

Quite amusing :')

lol what?

Kraken has STOIIP of c. 250-300mmboe.
What's more is that it's fully developed.

Enquest also have other fields.
Enquest has 2P reserves of 189mmboe as of 2020.
And has a market cap of c. £275m

Compare that with this failing company:
Has 2P reserves of 7.1mmboe
Market cap of £49m

Yes, that's STOIIP.

Have you even read the CPR? Lol

Galveston,

I think you're just optimistic.
Even if SFO is resolved this year, it will have minimal effects on revenue until at least 2023.

You don't just build revenue and backlog in a day.

Production projected to fall below 10k around about now according to that report.