Hurricane Energy (HUR)

[dspp]

I'm missing some info .... can anyone help me with the missing bits ? I'm just trying to calculate a fully diluted valuation for HUR and have realised that I am probably missing some options that have yet to be exercised.

Share issued = 1227988123+731222213 = 1,959,210,336 (that's the latest I have: am I right ?)

Convertible bonds = 230000000/0.52 = 442,307,692

Cenkos = 0 (because they are the 10 in 220m + 10m = 230m above)

Other options = ?? (Do Ker and CA have options. Any others ? My memory is yes but I cannot locate this)

total so far = 2,401,518,028

Am I missing anything. I am sure I am ...... Any answers ?

regards, dspp

[PeterGray]

Hi dspp,

According to the AR there were 901k options outstanding at the end of 2016

Both those and the converts had an exercise/conversion price of 52p or 53p. That does complicate your calculations of the effects of dilution as when/if the dilution occurs there will be a cash inflow - currently at a significant premium to the market value of the shares that would be created.

Peter

[dspp]

Hi dspp,

According to the AR there were 901k options outstanding at the end of 2016

Both those and the converts had an exercise/conversion price of 52p or 53p. That does complicate your calculations of the effects of dilution as when/if the dilution occurs there will be a cash inflow - currently at a significant premium to the market value of the shares that would be created.

Peter

Thank you Peter. I have a little adjustments table for non-reservoir stuff such as this, cash, etc but in all honesty that's not looking material compared to the reservoir stuff.

regards, dspp

[dspp]

I’ve just been pulling together my simplistic view of figures ahead of the pending CPR and with 14-18 months to run until the window in which the Lancaster EPS might achieve first oil (H1 2019, though Xmas 2018 also possible).

========NOW=======
To my mind the situation now is best set out in this table:
Table 1

Code: Select all

               
                 | MMboe  | Cat           | $/bbl        | $mln               
Lancaster - FFD  |   529  | 2C (50%)      |  $     1.00  |    $           529
Lancaster  - EPS |    62  | 2P (50%) 10yr |  $     5.00  |    $           311
Halifax          |   400  | guesstimate   |  $     0.01  |  $               4
Lincoln          |   250  | 2C            |  $     1.00  |    $           250
Warwick          |    400 | guesstimate   |  $     0.01  |  $               4
Whirlwind        |   117  | 2C            |  $     0.50  |   $             59
Strathmore       |   182  | P50           |  $     0.01  |  $               2
Tempest/Typhoon  | 1,307  | P50           |  $     0.01  |   $             13
Subtotal         | 3,247  |               |              |      $       1,171
               


Re volumetrics : I am using the latest 50/50 numbers wherever I could find them. For the Lancaster field I have split it into the volume attributable to the FFD and the separate volume attributable to the EPS. The Halifax and Warwick 50/50 resource numbers are pure guesstimates but I do assume an equivalent situation to that fairly optimistically hypothesised so far. Trying to be accurate is not really the point of this exercise. (If you have a better opinion than mine please speak up).

Re pricing: The $/bbl numbers I have used are just my opinion.

Re adjustments: In the simplistic view I make no adjustment for balance sheet cash, oil price, or for any other factors such as asset values, cash for options, interest payments, liabilities, etc. Then I take the fully diluted number of shares as best I can find:

Table 2

Code: Select all

issued shares (mln)          | 1,959
convertible bonds (30 06 17) |   442
future options               |    0.9
Fully diluted (mln)          | 2,402
                           


Dividing the two numbers gives $0.49 per share and using USD/GBP of 1.30 gives £0.37 per share. As I write the market is at £0.29 per share so not hugely different.

=======NEXT CPR END 2017========

The coming CPR may or may not make a difference to the volumes and valuations ascribed. We’ll see.

=======EPS etc LATE 2019=========

Following that (and ignoring any farm-in outcomes) the next major step is for the EPS to be operating, and I am assuming that the contracted rig does two other jobs at the same time. Firstly renter Halifax for a DST and OWC determination. Secondly drilling Warwick and a DST. I assume they can be done out of spare change so this is an operationally optimistic case. Assuming success in all three then the (late) 2019 picture might become:

Table 3

Code: Select all

                 | MMboe  | Cat           | $/bbl        | $mln               
Lancaster - FFD  |   529  | 2C (50%)      |  $     5.00  |      $       2,645
Lancaster  - EPS |    62  | 2P (50%) 10yr |   $   14.65  |    $           910
Halifax          |   400  | guesstimate   |  $     0.50  |    $           200
Lincoln          |   250  | 2C            |  $     1.00  |    $           250
Warwick          |    400 | guesstimate   |  $     0.50  |    $           200
Whirlwind        |   117  | 2C            |  $     0.50  |   $             59
Strathmore       |   182  | P50           |  $     0.01  |  $               2
Tempest/Typhoon  | 1,307  | P50           |  $     0.01  |   $             13
Subtotal         | 3,247  |               |              |       $       4,278
               


This time the EPS valuation goes up to $14/bbl which is my discounted view of a 10-yr life one year into the future using a 10% rate and $25/bbl margin. Again your view may vary but I am trying not to overcomplicate. I am assuming success at Halifax and Warwick to bring these to $0.50 valuations.

In this case the EPS is paying the bills but to balance out some of my optimism I don’t take into account any cash generation.

With no new shares needing to be issued this leads to $1.78/share and £1.37/share as a reasonable aim point in late 2019. If the market prices in success early then it could overshoot but that would be before EPS results had become available – the more oil that comes out the better the available dataset becomes for reservoir analysis purposes (i.e. RF%).

========FFD APPRAISAL 2021 ======

It will not have escaped anybody’s attention that in the case where the entire Rona Ridge area of GLA + GWA is oil full then this is a Brent or Forties scale reservoir. That would imply several $bn of capex, maybe 50-100+ wells, and three or four (jacket) facilities.

I’m ignoring gas handling issues as this looks to be in the sweet spot GOR-wise, so no export pipeline (Whirlwind may be gassy, and there is a hint of a possibility of a gas cap on the top of Halifax btw). The tilted OWC hypothesis tends to indicate a good aquifer underlying everything, so that eases reservoir development if it proves out.

Nonetheless the optimal pathway to develop that is non-trivial to figure out but at the very least involves a serious appraisal campaign. Sketching out a possible sequence that aims to as rapidly as possible prove up value for HUR shareholders gives the following with about four more wells.

Table 4

Code: Select all

                 | MMboe  | Cat           | $/bbl        | $mln                |                                                               
Lancaster - FFD  |   529  | 2C (50%)      |  $     5.00  |      $       2,645  | needs an FFD design and an EPS to prove up                     
Lancaster  - EPS |    62  | 2P (50%) 10yr |   $   14.65  |    $           910  | needs the EPS to work                                         
Halifax          |   400  | Guesstimate   |  $     5.00  |      $       2,000  | needs an EWT of the X-well to prove up, plus one or two A-wells
Lincoln          |   250  | 2C            |  $     5.00  |      $       1,250  | needs a well tieing in to the EPS to prove up                 
Warwick          |    400 | Guesstimate   |  $     5.00  |      $       2,000  | needs an X-well and an X-EWT                                   
Whirlwind        |   117  | 2C            |  $     1.00  |    $           117  | likely gassy; when is latest drill-by-date ?                   
Strathmore       |   182  | P50           |  $     0.01  |  $               2  | useful chip                                                   
Tempest/Typhoon  | 1,307  | P50           |  $     0.01  |   $             13  | needs to be drilled in 2018 to hold                           
Subtotal         | 3,247  |               |              |       $       8,936 |                                                               
               


The above can be done by an EPS at the current location I think, but that’s just an opinion. It would require tying back the Lincoln well to the EPS and likely backing out Lancaster to get capacity, but that’s exactly what this EPS-FPSO is for. Maybe even a Warwick well tie back but I am assuming just a EWT on the X-well.

Re Halifax it is too far to get tied back, so I am assuming just an EWT and then one or two appraisal wells down the ridge.

Since in the success case the EPS is generating $310m/yr the above campaign could be funded without external resources. So no need to accept more dilution through share placements or a farm-in.

The biggest constraint in the above is the capacity of the subsurface team to process the data. I am assuming a single rig for this reason and that leads to a late 2021 outcome, i.e. approx. four more wells post 2019, or six more well entries post now.

That in turn leads to a highly optimistic valuation in late 2021 of $3.72/share or £2.86/share.

========= FARM-IN========
I have lots of opinions on farm-ins and the dynamics in play, but the above gives an indication of why the HUR management team are well-placed to play hard-ball over valuations. Basically it shows that HUR can take this through to the gates of a FFD on their own, and maybe even with no further dilution. If the majors won’t want to pay-to-play then there are ways of doing this without a major being involved. It would not be ideal, but it can be done.

There is for example the option of some time in (say) 2020 seeking a 100,000 bbl/d full-size FPSO on the market (at about $1bln) and placing her where the EPS-FPSO is destined, By then that location would have four wells available to produce (maybe more) and some more wells added. The EPS-FPSO could be shifted north to fully appraise Halifax. Whilst that was chugging away the FFD could be properly optimised and funded with a decent dataset, using the normal oilpatch contractors. It would likely take a non-conventional contracting approach but people are up for that these days. There are other ways. The point I am making is that there is a reasonable risk pathway that can be pursued that prevents the majors forcing a low-ball valuation onto HUR. Having enough, but not too much, gas greatly helps HUR’s hand as there is less exposure to an export gas line to force capex upfront.

All this assumes the success case and 50/50 volumetrics. Clearly that is not the only possible outcome. More and less are both possible pathways. As the data comes in over the next few years we will be able to revise the analysis.

========CURRENT SHARE PRICE ========

The 29p/share today is not irrational. A higher one at this point can be defended, or post-CPR, but are not necessarily correct. The same assumptions that can make a 29p rational now can make far higher ones rational looking forwards. It's a fun game to play isn't it !

Please excuse formatting, but must catch a plane so no time to tidy up further. It is a long flight .........

regards, dspp

[edited 28/10/17 to insert table numbers]

[PeterGray]

Thanks dspp,

An interesting analysis. Clearly there is a very large degree of uncertainty with the estimate $/bbl valuations, and thus the final answers, but it's certainly a very useful piece of analysis to put the current price, and possible future prices in context.

Peter

[Sorcery]

Thanks from me too dspp.
I'm not sure I understand the $/bbl column, the numbers seem awfully low even if they are net margins.

[dspp]

@FB
- Agree re funded to first oil being a nice position.
- The way I see it they are actually funded for the next 4-5 years worth of appraisal work, including being able to do an Initial Field Development (IFD) if they want using a 100k bbl/d FPSO if there is no interim M&A or farm-in activity. That IFD is a no-regrets pathway and one they are quite capable of doing with the existing team and a few extras.
- So any M&A or farm-in must add serious value by either reducing HUR shareholder risk and/or accelerating FFD volumes.
- So any preferences re doing or not doing the FFD itself are quite a long way down my concerns list. First carry on derisking the reservoir.

@PG
- That was exactly why I did it for myself.
- Clearly more complex approaches are possible.

@Sorcery
- the $/bbl values reflect (time value of money) x (probability of success)
- there are much more complicated ways but these are a ready-reckoner that can get to a good-enough answer in cases like this
- the numbers I have selected yield about the same outcome as the last share issuing (32p/share) and so are directionally agreed with by the market
- if you do the table 3 DCF calculation to yield $14/bbl for the EPS-FPSO oil for yourself (using the data I give) you'll begin to see how & why these values come about

regards, dspp

[Sorcery]

I can just about do a DCF valuation but I don't think I understand the assumptions being used here.
Table 1 indicates $0.01/bbl for Halifax, Warwick, Strathmore and Tempest/Typhoon.

Table 1
CODE: SELECT ALL
               
                 | MMboe  | Cat           | $/bbl        | $mln               
Lancaster - FFD  |   529  | 2C (50%)      |  $     1.00  |    $           529
Lancaster  - EPS |    62  | 2P (50%) 10yr |  $     5.00  |    $           311
Halifax          |   400  | guesstimate   |  $     0.01  |  $               4
Lincoln          |   250  | 2C            |  $     1.00  |    $           250
Warwick          |  400 | guesstimate   |  $     0.01  |  $               4
Whirlwind        |   117  | 2C            |  $     0.50  |   $             59
Strathmore      |   182  | P50            |  $     0.01  |  $               2
Tempest/Typhoon  | 1,307 | P50            |  $     0.01  |   $             13
Subtotal          | 3,247 |                |              |      $       1,171

Not sure I understand what the upside is for even an exploration well at those locations unless the rest of the block(s) is/are brimming. Perhaps you mean to show that at even with those discounted to almost zero, Hurricane could fly.
I share your enthusiasm, I bought quite a lot more at the placement price in the market after the placement.

Regards
Sorcery

[petroleum1]

dspp
Just remember that the resources are 2C category. A competent person report cannot do much about that and a full field development plan cannot be carried out on 2C resources.

[PeterGray]

dspp
Just remember that the resources are 2C category. A competent person report cannot do much about that and a full field development plan cannot be carried out on 2C resources.

Not sure what you mean here. Most of those 2Cs are presumably contingent because there is no current plan for production.

Peter

[petroleum1]

peter
Hurricane reservoirs are non conventional reservoirs where the oil exists in fractures and not pores. In a conventional reservoir you have geological maps derived from seismic plus few wells that will give you porosity, permeability and other reservoir parameters. This together with long term flow tests of selected locations will help you determine oil in place and recoverable oil and hence full field development plan.

In fractured reservoir you do not know how many fractures exist and whether they interconnect with each other. More over you do not know whether the well drilled will hit a fracture or not. The fractures could be cemented with deposits over long period of time. I think this is the reason why the majors are playing a hard ball.

In the Middle East you can drill 100 wells that do not intersect fracture but that do will give enormous flow rate. So the question is can you afford to do that in an offshore environment.

I remember Emptyend was enthusiastic about a fractured reservoir in Vietnam but later reversed his views.

This post is not meant to be destructive but constructive. I personally will seek advice from posters who are reservoir engineers like Flyingbull or Nimrud...

Rgds

[dspp]

dspp
Just remember that the resources are 2C category. A competent person report cannot do much about that and a full field development plan cannot be carried out on 2C resources.

Some are 2P, most at present are 2C, some are just 50/50 exploration hopes. I ought to have shown in those tables the to-be-hoped for category transitions at each step to help other people. I'm not sure a CPR is of great value but others seem to set great store by them.

I fully agree re caution with fractured reservoirs (whether basement or not).

We will see how it goes.

regards, dspp

[petroleum1]

dspp
Your contribution to this board is great. Do you remember XEL (Exite energy) carried out an EWT(extended well test) for the heavy oil of Bentley using FPSO that did not cost a lot of money. Why can't HUR do the same?

Regards

[dspp]

dspp
Your contribution to this board is great. Do you remember XEL (Exite energy) carried out an EWT(extended well test) for the heavy oil of Bentley using FPSO that did not cost a lot of money. Why can't HUR do the same?

Regards

Thank you for the flattery

I don't recall XEL's EWT in particular. Sorry but I may have had my head down on something else at the time.

However the Lancaster EPS is essentially a longer duration EWT. The costs are about right given the GOR and the location (WoS). What I have proposed in the posts below is that the next step is not to feel forced into a full-on capex heavy FFD but instead to go to an IFD at about the same location* using a bigger floater @100kbpd (assuming the success case on Lanc) that in turn would release the AM to go as an EPS on some other location sufficiently far away that it can't be tied into the IFD. Halifax is the most obvious candidate (again assuming the success case on the Halifax reentry).

Standards have changed over the years. I recall inspecting a rig for FPSO conversion use that would not even pass the laugh test in UK waters these days. Back then it was put forwards as a serious contender (which I did laugh at for us back then mind you). But location (weather, moorings, time of year) and oil/gas characteristics and reservoir issues all affect EPS/EWT costs. I am happy with the HUR costs for the AM as an EPS.

regards, dspp

* the mooring type selected for the AM will, I hope, not be piles for this reason - unless over-engineered enough to take something much bigger !

[HURfan]

dspp,

A big thank you from me as well for your contributions. And of course to all you others supporters out there.

I'm hoping the forthcoming CPR will bring some good news.

Regards

HURfan

[NigWit]

Hello

I am an alien from another board and I come in peace.

I also thank dspp for his interesting insights.

I do hope he keeps the model up to date with developments and posts it as and when.

Thank you again.

[PeterGray]

Petroleum

In fractured reservoir you do not know how many fractures exist and whether they interconnect with each other. More over you do not know whether the well drilled will hit a fracture or not. The fractures could be cemented with deposits over long period of time. I think this is the reason why the majors are playing a hard ball.

Late replying as I've been enjoying a few days away!

I totally agree that the unconventional nature of the reservoir is a key factor in the caution of the majors, hence the EPS. However, I don't think that it's the reason for the characterisation of much of the potential resource as 2C - it's pretty standard that if you don't have a development plan then it can't be 2P. I think that is the main issue in terms of the 2P/2C characterisation here.

Peter

[Nimrod103]

Petroleum

In fractured reservoir you do not know how many fractures exist and whether they interconnect with each other. More over you do not know whether the well drilled will hit a fracture or not. The fractures could be cemented with deposits over long period of time. I think this is the reason why the majors are playing a hard ball.

Late replying as I've been enjoying a few days away!

I totally agree that the unconventional nature of the reservoir is a key factor in the caution of the majors, hence the EPS. However, I don't think that it's the reason for the characterisation of much of the potential resource as 2C - it's pretty standard that if you don't have a development plan then it can't be 2P. I think that is the main issue in terms of the 2P/2C characterisation here.

Peter

Your comments are entirely correct, but I would add that the principle risk in a fractured reservoir is estimating just how much oil is in place, and to a lesser extent how much of that is recoverable. Something that the EWT will not tell you, if there are strong water or gas cap drives, which AIUI is the case in Lancaster.

[petroleum1]

I would add that the principle risk in a fractured reservoir is estimating just how much oil is in place, and to a lesser extent how much of that is recoverable. Something that the EWT will not tell you, if there are strong water or gas cap drives, which AIUI is the case in Lancaster.

Well said Nimrod. EWT will pay for itself assuming there is enough oil down there.

[dspp]

Edison have popped out a updated research note
http://www.edisoninvestmentresearch.com ... 0/preview/

You can download a pdf that has additional discussion. They too have picked up the GOR issue and the need to either reinject or get an additional flare consent [longer term, if unable to mop it up with powergen needs for ESP]. They are hoping for a FO with a full carry of HUR through to first oil from an FFD. It would be nice if that could be achieved at a reasonable dilution as it is certainly one scenario. They've carried out a full DCF & oil price sensitivity analysis, but are holding lower reserves numbers than I used. They too are expecting a 5-well appraisal programme at $350m.

BTW (@Petroleum1 & @Nimrod) if I recall correctly are not HUR claiming to be able to get some fracture data from the seismic interpretation ? Fracture volumes (sorted into two classes if I recall correctly), connectivity, and orientation were all in their model as discussed in the last CPR. Technology is moving on. I am sure it will be further discussed in the new CPRs so I am not too fussed. Truth is in the drillbit mind you.

regards, dspp

[edit to clarify]