Member Info for Slift

Hi adoubleuk,

Just thought i'd add that there's 2 ESPs in each well for maintenance purposes too.
E.g. regular pigging of the pipeline, or other regular maintenance required.
All to minimise downtime.

Slift.

Hi noelpbz,

Thanks for your response!
It's wrong to class depreciation and impairments as "General and Administrative" costs. I don't want to believe that they've included for these in G+A.

Both depreciation and impairments are indirect costs to the company - e.g. they do not need to generate cash flows from selling barrels to fund this. Both affect the value of the assets. Also, each of these will have an indirect cost of £>30m this year (at a pure guess).

Regarding depreciation, what could be a direct cost is depreciation of leased assets. This is usually included in OPEX (e.g the depreciation cost of the FPSO).

The impairments are usually write offs or changes to asset values based on valuation against current oil price (in comparison to the oil price the year before).

What they haven't included for in their costs are:
- CAPEX
- Finance costs (hedge + interest on FPSO, etc.)

Whilst CAPEX is likely to be under $30m this year, this was only visible following the updates in June (in regards with extension of licenses and deferral of drilling etc.) The company could not have predicted this when they provided these breakeven costs.
Also, CAPEX wouldn't really be "G+A" either.

It's likely that they have included for finance costs (including rig possibly?) as G+A. But I'm uncertain at this point. $30m extra as "G+A" cost is massive for the size of company HUR is.

Slift.

I'm questioning these production costs provided by HUR.

At 18,000 bopd, HUR have stated that OPEX costs are $17/barrel. HUR have also stated that OPEX+G&A+Bond coupon costs are $26/barrel.

At $17/barrel, OPEX costs would be $112m.
At $26/barrel, OPEX+G&A+Coupon costs would be $171m

This means that G&A + Coupon costs are $59m.

The $230m bond coupon cost is $17.25m.

Which means that HUR have allocated circa. $42m for G+A.
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Staff costs are circa. $10-12m. What else have they allocated as G&A for an extra $30m??

Positives:
- Circa. 15k bopd current production
- 56mmboe 2P reserves and 2325mmboe 2C resources (subject to downgrade, but still huge)
- Cash in bank of circa. $100-170m.
- License commitments extended to 2021
- Minimal CAPEX - CAPEX deferred to 2021
- Notice given by the OGA for field determination over local structure closure at the Lincoln discovery
- FPSO capacity and reliability (good enough for 6 and 7z)
- New management (hopefully corporate biased)
- Hedges in place to ensure earnings are safeguarded from drop in oil price
- Estimated to make positive cashflows this year
- ESPs in place that will "hopefully" improve production/reliability

Risks:
- Increasing water cut
- Uncertainty to production (no guidance)
- Downgrade of reserves/resources (due to model review and shallower oil-water contact)
- No solid evidence or confidence to support concept (struggle to find JV partners)
- Aquifer/perched water that will disturb Lancaster production
- COVID19/Oil price - still depressed and market is uncertain
- Uncertainty regarding Lancaster FFD, HUR need a partner.
- $230m Covertible Bond maturity in July 2022
- Large CAPEX requirement for 2021
- No forward activity work programme provided. Unclear the direction HUR are willing to take. (Future costs unknown)

Feel free to add.

Slift.

It has been almost a month since the assets and the company were put up for sale.

South Africa mines were able to operate at 100% from June 1st. If that is the case, Petra would have been operating at full capacity for almost a month and a half.
I'm still surprised we haven't seen any big diamond drops this year.

But the 100% operation of the mines (assuming Petra keeps up with production) should instill some confidence among stakeholders.
However, Petra hasn't informed anyone regarding ramping up mines to 100%.

Views anyone?

Hi adoubleuk,

"Slift ! PlantedBHA ! Please make peace with each other"
I have no problem with PlantedBHA. But obviously will stand my ground if being targeted.

I look forward to the RNS that will potentially be released this week.
Hopefully it does provide further evidence to Dr Trice's theory regarding perched water.
Be interesting what the average water production rate is and how HUR will manage and/or control it going forwards.

Good luck to everyone here.

PlantedBHA,

isn't it a common courtesy to give your own background and experience before you ask someone elses'?

Hi Mk111,

Thanks for this reference. Very useful.
Not to sound pessimistic, but I don't understand how the "the observed water trap behaviour immediately after restarting production following a shut in" is good evidence for the source being perched water.
The comment regarding "start up has high water cut which then dimishes over time" isn't really valid anymore as since these comments, water cut has increased following production for 4-5 months from this well.

The perched water being "above 7z well" - This could still be connected to an aquifer. Therefore, whilst his explanation is valid in terms of temperature, if this perched water being above 7z whilst still being connected to an aquifer through fractures makes the explanation invalid.

If this perched water is really above 7z, whilst being connected to an aquifer - I see it as more of a problem than the water being below the 7z well and being connected to an aquifer.

Obviously the above is just speculation. But I don't think they've provided solid evidence.

Having said the above, Lancaster has been producing for over a year now. I think this is the only solid evidence for these assets at the moment. Whilst perched water being connected to an aquifer may reduce the life and/or production of these wells, I'd imagine Hurricane can still tap into these reserves for the next few years at least (although in this scenario well 7z would be a write off).

ALL IMO. Slift.

@Mk111,

"The pesky perched water found in the first 40 metres of well 7z was not quantifiable so I assume it could deplete at any time now that it is back online."
Personally, I wouldn't say depleted.

Assuming it was perched water, the production through 7Z to date would have "broke the bubble" of this perched water - e.g. through production, the pressure in the well was lowered (due to the productivity index). What this would mean is that water would keep on drawing from the perched water reserve (into the oil reserve) until a point where the both the reserve are at equal pressures (or until the perched water empties).
I'm thinking whether this initial and ongoing "disturbance" within the oil reserve is what caused the interference between well 6 and 7z.

Now that the well 7z was shut for a few weeks (and assuming that the pressure has reached equilibrium (or perched water has emptied)):
This has given time for the well to settle. Ofcourse as water is more dense than oil, it would have settled to the bottom, providing an oil-water contact, rather than a disturbance.

This "theory" is one of two ways I see a reduction in watercut from well 7z, rather than an increase. Ofcourse, the other being control of the VSDs to ensure that the 7z does not draw from a perched water reserve.

@HebrideanSunset,
"What influence will Trice have now, with his shareholding and do you think the bod will take any notice/concern about what he thinks should happen in the event of a takeover approach?"
He's been demoted as a director hasn't he? He's only around to transfer knowledge for the next 6 months, and for any technical questions. Not much i'd have thought. His shareholding is around 1.5%.
IMO.

Slift.

Longish,

"fcf is based on $35 oil and we are currently $43 and we are 60% hedged this year, 40% next year?"
Yes, $35 is breakeven cashflow for the rest of the year.
Tullow has circa 45,000 barrels/day hedged at $57.28 for this year.
Really unsure about next year. Contradicting figures everywhere: 30% hedged, 40% hedged, 22,000 barrels/day hedged.

"It doesnt seem unreasonable to me to project 5 years+ at $60?"
Assuming Uganda has 25 year lifespan, my guess would be that oil would be above $60 for at least 20 of those 25 years.

"So, if we get some part/ all of the $1bn portfolio management,eg kenya, are we out of the wood?"
I'd say Tullow would have liquidity for operations following this portfolio management. But in regards to paying off debt, depends on oil price.

"And if years 1 and 2 conditions/ targets met, does that mean the new ceo is likely to explore growth funded from rights issues or revert to low interest debt based on solid cashflows etc?"
I'd imagine shareholders want returns in either buyback or dividends. But likely to revert to debt. Debt is good.

Hi cluelesstim,

"So its already a good debt strucutre which just needs paying down to a point of improving credit ratings and then extending maturities or reissuing bonds possibly at even lower interest rates. "
Yes this is what i meant sorry. I have no problem with the RBL, like to believe that TLW has room for some negotiation with the current facility. Credit ratings need to be improved by at least two ratings going forwards. And the maturity of the $650m senior note needs to be extended for the time being. Everything else is fine IMO until 2022-2023ish.

"but a small finger can be in the Hydrogen pie to generate energy so as to replace the energy needs for existing diesel powered E&P operations as a start. Then can be expanded to acquiring an R&D team for Hydrogen energy reserach which will attract a lot of ESG capital."
Not sure about this at the current state. This is a big change and comes with huge risk. TLW can try and diversify when in a better position, IMO.

Hi Megla,

"Guidance has always been done on a working interest basis, so next years 70K guidance is more like 65K, worth checking with IR to confirm for yourself, but most oil companies do the same"
You are right. I've always thought that the barrels that Tullow doesn't sell --> it keeps in inventory. Obviously not the case!, (although some of which Tullow does keep in inventory).

Hi cluelesstim,

Not a worry!

1. A YOY comparison would be more meaningful to compare if Tullow had liquidity. I posted a debt maturity chart showing the problem Tullow is facing going forwards (and have said that debt restructuring is very important).

2. The G&A cost savings is cumulative, rather than savings per year.
E.g. 2020: $30m saving, 2021: $30m + $25m forecasted(circular) + $Xm further savings, 2022: $30m + $25m + $Xm forecast + $Xm further savings = $200m total savings
Regarding CAPEX, you're right. We know that from Uganda there's a cost saving of $15m (pre-development expenditure) which isn't so far accounted for.
What may or may not be accounted for in the CAPEX forecast of $300m:
- Kenya Force Majeure (pre-development expenditure for Kenya was supposed to be circa $40m)
- Non operated portfolio capex deferral (I know Ruche Phase 1 was postponed)
- Ghana and Exploration - Some exploration activities have had Force Majeure declared. Not sure about Ghana, likely to be above CAPEX.

3. "Its very strange you say past results don't predict but you have been using past results to come up with your own estimates?"
Most of my estimates are forward guidance, rather than based on past results.

"why is sp c.80% lower at 30p?"
- Risk and uncertainty.
- Oil prices.
- COVID19.

"The current sp is a function of the wider market and its uncertainties as well."
Agree. In normal situations, oil and gas and the energy market is considered as a high risk.
Now if you combine that with COVID19 + depressed oil prices and loss of demand --> this sector becomes a whole new level of risk. This sector at the moment is facing a higher level of bankruptcies than most other sectors. Not many "safe" investors would want to invest here during this. But like I said in one of my previous post, markets are cyclical and once there is a sign of recovery, everyone invested in the oil and gas sector will be rewarded.

Hi oiluser,

Regarding H1 cashflow:
The following calculation is based on 78k production assuming 90% sold and $35/barrel breakeven cashflow. (e.g. FCF is anything above $35, hedges incldued):
FCF Q1 = +$68m
FCF Q2 = Est. +$75m

Estimate cashflow for 1st half: $143m
It's likely that this will differ by +/- $15m depending on:
- What cost savings have Tullow already achieved in 1st half (and what they haven't or unforeseen costs)
- Production in Q2
- Estimated brent oil prices Q2 (oil was all over the place during this period)

Hi Megla,

I believe the production is after royalties and government takes, and net to Tullow.

Yes, I was under the impression that the FPSO and other property lease costs was accounted for in the OPEX. But it seems as though only depreciation is accounted for in OPEX (makes sense as interest is finance costs :')). The net FPSO finance cost is likely to be $50m after income from partners for their share of the use.

It's likely that Tullow have tried to save other costs throughout the business (including triggering force majeure at Kenya) etc.
But overall, there's possibilities of Tullow not achieving all cost savings they had set out to do for the year (plus the unforeseeable costs). So on a worst case basis, the breakeven will be over $35/barrel.

I do agree that Tullow needs to find extra barrels for next year. I believe that there will be a few wells drilled in Gabon that will net Tullow circa. 1-2k+ barrels from non-operated portfolio. The Ntomme-9 well will also help when online.
But i'm not going to be naive and pretend that there won't be any problems in Ghana for 2021. But that's the risk that Tullow needs to manage. The forward strategy is very important here - whilst there's indication of growing production and focusing on Ghana going forwards, there's no proper clarification, yet.

Hi cluelesstim,

Not sure why this is directed at me, but i'll post as comments to your statements.

1. Borrowings are based on bonds, senior notes and restricted cash withdrawn from the RBL lending facility. The $3255m borrowing as at 31st May was posted officially by Tullow in the circular. This is the last known borrowing figure, this won't look "wildly different" unless ofc it's repaid.

2. Not sure why you're stating this, but i'm assuming this is in relation to my recent posts regarding the extra "$200m cost saving". The G&A savings for this year is circa $27m (and up to $30m). It certainly isn't $67m. Tullow have stated $200m over 3 years, but i'll let you figure this out.
The dividend was suspended in 2019, and was more a cost saving in 2019.
"Also, in the circular you will find the realised oil price through to 31st May 2020 is of $52/bbl." Yes, thanks for stating the circular, I have read this.

3. If you've been following my post, I have already said that net production is close to 78-80k, with calculation (rather than a wild guess). You've just stated this figure. I do also read Kosmos' regulatory news announcements regarding Ghana and Equatorial Guinea.

4. Past results doesn't predict the future. But you go ahead and use it to get your £15 share price from 2012.

5. I think I'm confident in making my own investment decisions. Whether that's 27p or 31p or even 50p. I certainly don't have the fear of missing out. I will invest when I want to in relation to the market as a whole, but thanks for your advice.
Whilst I don't claim to be Warren Buffett as an investor, I do my research and take the risk of investing in a company of my choice, when I feel like it's valuable. If i lose out, that's on me.

P.S. I don't follow major shareholders or anyone else. If Samuel invested at 40-50p, that's on him if he sees a 50% upside from there. Same with the CEO.

Slift.

Also adoubleuk,
"Such completions, from the get-go, imply that the company anticipated a certain water-cut right from the beginning, hence the inclusion of the ESP's"
Again from a design point of view, this makes sense. FEED is less costly than having to implement it at a later date. A LOT LESS costly too. It's also possible that this is part of industry standards. But who knows.

adoubleuk,

"But you seem a bit 'behind' on your 'Hurricane History'."
Yes, i must admit that I don't know the history as i've only really been following recent news and recent publications. Going forwards, past history will become clearer.
But thanks for the background information.

"'Y bypass' for natural flow"
From a design point of view, with this bypass, the ability to change between ESP and natural flow is surely beneficial for Hurricane (should they try natural flow again).

"And the fact that there are two of them in each well means redundancy, so they weren't planning any workovers in the close future"
Could also be to reduce downtime? E.g. if an ESP does seize, they can switch to the standby pump to continue production. In design, it's normal to have a duty-standby arrangement.

"Note the word 'optimizing' rather than 'maximizing': two different things"
I think the word "optimising" is subjective. It could mean quite a lot of things from optimised water production, optimised oil production, optimised production in terms of well pressure to even optimised pump operation etc.
Right now, what's important is water production and oil production. I'd like to think that Hurricane is willing to operate the ESP at unfavourable frequencies, as well as other factors at unfavourable conditions.

Slift.

mjga786,

Just so you're aware, the company has no influence on the share price directly. Good news influences the share price indirectly in the way that investors flock to buy, raising the price.
the "share price going down 50% with no SP price sensitive negative info" is due to investors and the market conditions. Nothing to do with the company.

Emailing the company to take out your frustration doesn't really achieve anything... but yes we can all hope for good news.

ALL IMO.

adoubleuk,

"you're obviously tech-minded like myself"
My oil and gas knowledge ends with my degree. Most other knowledge comes from working in project management. As with CaptainSwag, I do not have real world experience in the oil and gas sector so i'm happy to be corrected so I can learn.

""ESPs help control the water cut"
No they don't"
As CaptainSwag has said, the ESPs "control" or tries to maintain the watercut, not reduce. The watercut will increase (in conventional oil and gas systems) as more and more barrels are produced and the well draws from the aquifer, but at a much more controllable and manageable rate.

"The ESP's were installed on well 6 two years ago"
Ignoring the interference and focusing on just one well, there is no need for ESPs if the well can produce a decent PI (which HUR's well does) with little water cut. Two years ago, water cut from well 6 wasn't an issue. From the recent RNS, HUR have told us that the water cut in this well has increased from 8 to 11%. Going forwards, it makes sense to me ESPs are required to "control" this watercut.

"Personally I can see an advantage is running well 7z on ESP while retaining 6 on natural flow, as a means of artifically 'balancing' their pressure regimes and preventing 7z's higher water-cut from affecting and influencing 6."
I think having ESPs on both the wells provide you the ability to control the pressure at both wells. Almost as if the ability to control where the water should flow to in the reservoir.
A natural well without an ESP will just be "forced" production. E.g. the force being the HUGE pressure difference between atmospheric and the reservoir and thus, oil is forced out. In a 0% watercut situation, this is great since there's no limit to production (and no expenses of running pumps!).
In this case however, as the watercut is rising, a more controllable option with the ESPs works better IMO.

"But don't expect them to be some magic wand to reduce the water-cut in the near future. In fact, if 7z is put on preferential flow, percentage overall water-cut may increase"
Definitely not. Although it's quite hard to predict when the concept is FB.
I agree that it is more likely than not that the watercut will increase. But i'd like to think that the increase is more controllable (with ESPs as mentioned above).

@CaptainSwag
100% agree that RT didn't live in the real world and wanted data for his paper. I also noticed that he had no project management experience in comparison to the other directors.
Definitely good to have RT with the team for his expertise, but with more of a corporate head

Slift.