Jadestone Energy Share Discussion Threads

[king suarez] 01/6/2019 12:58

That makes sense, I think you're probably right. No reason why the logistics shouldn't be in the operating costs.

Either way this appears to be a very profitable and cash generative business. I see no reason why we can't get to £1 - 1.50 share price in a couple of years time once everything is fully on stream and the vietnam gas developments are demonstrating their potential too.

What are your thoughts on dividend? I think a 5% or so dividend at this stage wouldn't hurt?

[tim000] 01/6/2019 12:45

Good point. My calcs are as follows. As you have already done, we can reverse engineer the implied production costs consistent with a figure of $23.75. That gives costs of $27.9 mn. Operating costs and logistics are $23.6 mn. So the amount to be explained is $4.3 mn. The existing R&M figure is $4.5 mn. So that implies most of the R&M is routine rather than non-routine. I don't think it can be anything else.

[king suarez] 01/6/2019 12:33

It says the following in the accounts:

"After adjusting for non-routine opex including the RLWI as well as Stag workovers, repairs, and maintenance, this equates to US$23.75/bbl"

Which is why I did not include workovers, repair, maintenance costs from Note 5 - if not the staff costs, then there is something missing in my calc above - just not sure what it is :)

[tim000] 01/6/2019 12:09

PS: I agree with your last para, I too made those calcs.

[tim000] 01/6/2019 12:07

King Suarez, I don't think that is quite right. Staff costs are identified separately amongst other costs and won't be part of the calculation of operating costs within cost of sales. (Staff costs are Head Office staff, part of G&A.) Costs of operators (rig staff etc) will be within "Operating costs" in Note 5. I still haven't got to the bottom of how exactly the $23.75 figure is estimated, but it will be roughly the costs identified in Note 5 excluding costs of inventory (which sums to $31.2 mn), divided by production volumes of 1.175 mn bbls. But that gives $26.5, not $23.5. I might send the company another email asking clarification. My reply was from Dan Young, the FD, and was received extremely promptly. He seems very open to communications with PIs, no doubt provided PIs don't waste his time. Note that despite the inventory deduction within operating costs within the P/L accounts, unit op costs of sales were still $30. Assuming $23.75 is an accurate estimate of underlying unit production costs, there will be a correspondingly large offset to op costs when the inventories are sold (roughly a $5 mn reduction). I have been spending a lot of time trying to refine my P/L estimates for H1 and H2, based on all known information. It's clear that if all the company statements to date are accurate, the company is going to be highly profitable and cash generative in Q2 and in H2, as we imagined.

[mount teide] 01/6/2019 11:22

Malcy Blog - Jadestone Energy - 31 May 2019

'Results this week from Jadestone, but show no concept of comparison except that the company is growing, and fast. They do show that the acquisition and subsequent work on Montara will prove it to be a game changer and I expect this to continue.

I missed meeting with the company on their recent trip to London but i’m confident that the substantial increase in production from Montara and of course the Stag infill will continue to increase production and these, and others make Jadestone a must follow company in the sector.'

Malcy - if that's typical of the 'informed' and 'in-depth' research journalism your blog offers - perhaps it might be better to stick to sports commentary!

[king suarez] 01/6/2019 10:40

tim000,

Many thanks for posing the questions and your responses.

So barrels produced 1.175 million x $23.75 cost per barrel = $27.9m

Taking the figures from Note 5, which breaks down production costs into components, do you think the calculation could be something like:

Cost of production = $15.5m (excludes workovers, repair and maintenace)
Add back inventory = $8.5m
Plus staff costs = $3.8m
TOTAL COST = $27.8m

Looks about right to me?

The 'movement in inventory' figure $8,474k represents the difference between barrels produced v barrels sold of 426k, suggesting an operating cost for those barrels of just under $20 a barrel?

[tim000] 01/6/2019 06:38

I got the following response from the company to some queries I had. The text should be self explanatory.

the company had a convertible bond that was issued in mid 2016. Operative word here being had. It was redeemed in mid August 2018. As such, you will continue to see reference to it in relation to prior year/quarter comparable notes, until we are into 2020. But the bond is redeemed, and you see that in relation to current diluted shares outstanding calculations/notes which makes no reference to the bond since it is gone. If you’d like more detail on that, take a look at our Sep 2018 quarter results.

* (explaining the $23.75 estimate of unit operating costs) production costs on a per barrel basis are reported on a production basis not on a sales basis. Production costs in the income statement, are based on cost of goods sold - which is to say, after inventory movements (and we had a big inventory build im the Mar 2019 quarter, as we discussed on the webcast on Wednesday). Since both our production assets sell via lumpy liftings (especially Stag) this approach - taking out the effects of inventory movements to calculate a per barrel production cost - makes for a better/more meaningful comparison of per barrel production costs, quarter by quarter.

* total revenue in the income statement also includes hedging revenue. And conversely, for the avoidance of doubt, hedging revenue is not reflected in the per barrel price realisation number. That’s the difference.

[mount teide] 31/5/2019 21:38

Operating an FPSO with the offload flexibility of 900,000 bbls of storage, together with the Montara oil price hedge and regional & low sulphur crude premiums showed their value today, as spot Brent fell again to $61.75.

I calculate the average sales price of Stag and Montara's combined production is circa $69.56 today - 12.6% higher than Spot Brent.

With current Opex of circa $23.75/bbl - this should generate cash flow of $45.81/bbl at $61.75 Brent. At an estimated current production of 15,000 bopd this has the potential to generate quarterly cash flow of $62.5 million / $250 million annually.

Effectively, the Montara oil price hedge and current regional/low sulphur crude premium is reducing the Opex by circa $$7.81/bbl, from $23.75/bbl down to $15.94/bbl

Cash flow/bbl should be circa 74.2% of the current spot Brent price.


AIMHO/DYOR

[mount teide] 31/5/2019 21:09

Tumbling spot price of oil does not tell full story, say traders - FT

Premiums for prompt delivery are at five-year highs, suggesting a tight market

'Traders are warning that the spot price is not telling the full story. Instead, some are pointing at the way oil prices are moving for contracts on different delivery dates to tell a more nuanced tale. Brent contracts for the next few months are trading at large premiums versus those for delivery later this year — a classic sign of tightness in the market.

This could trigger a rebound in oil, should tensions between the US and China begin to ease.

“The reality is the physical market is extremely tight right now,” said Amrita Sen at Energy Aspects. “The problem for the spot price is [that] it is weighed down by economic concerns, which have been compounded by longer-term fears about US shale growth and the strength of demand. It is a battle between the tightness in the market right now and future fears of oversupply.”

The relative lack of oil supply can be seen most clearly in two closely watched spreads. The Brent contract for next-month delivery is trading at roughly $1.30 a barrel above the one for the following month, while its premium over contracts for delivery six months later has reached almost $4 a barrel.

In both cases that is the largest premium in at least five years. Put another way, the last time traders were prepared to pay this much extra to secure barrels, crude was trading closer to $115 a barrel and Isis was rampaging across swaths of northern Iraq, putting at risk supplies from Opec’s second-largest producer.

This time the tightness stems from US sanctions on Iran and Venezuela, while Opec and its allies have been cutting output to try to boost the price.

Russia, which has largely aligned with Saudi Arabia on oil policy for the past three years, has also seen its supplies hit by organic chloride contamination in one of its main pipelines to Europe.

But if the market is so tight, it raises a question: why is the spot price falling, even as it remains strong relative to contracts for later this year?

Traders point to a host of reasons, such as signs that US shale output is still growing rapidly, and pressure from US president Donald Trump on Opec to boost supplies to help keep prices low.

But traders are also anticipating that the US trade war could slow the world economy and weigh on oil demand growth later this year. For that reason, crude is closely tracking global equity markets.

“The mood is now definitely risk-off and this is putting oil under pressure for the time being,” said Tamas Varga at oil brokerage PVM.

But Mr Varga warned that the supply and demand balances did not make for comfortable reading for oil consumers, assuming Opec keeps its supply curbs in place when it meets in June and nothing else substantially changes in the market.

The group’s current output, factoring in supply losses from Iran and Venezuela, is at present little more than 30m barrels a day, according to Opec’s own numbers, while demand for the cartel’s crude could be as high as 31.2m b/d, Mr Varga noted.

“Unchanged Opec production of around 30m b/d for the rest of the year would mean a drastic global stock draw for the balance of 2019,” he said, referring to inventory reductions of crude around the world.

Oil’s slide, analysts say, might therefore be shortlived.'

[mount teide] 31/5/2019 01:05

Realised oil sales price at $65.5 Spot Brent.

After taking into consideration Jadestone's regional and low sulphur crude premium together with the Montara oil hedge, i calculate the average sales price of Stag and Montara production combined is circa $72.13

With current Opex of $23.75/bbl - this would generate cash flow of $48.23/bbl at $65.50 Brent.

Effectively, the current regional/low sulphur crude premium and Montara oil price hedge is having the impact of reducing the Opex of $23.75/bbl down to $17.12/bbl

Cash flow/bbl would be 74.5% of the current Brent price.

[cashandcard] 30/5/2019 15:55

Apart from 4, those 4 are probably majors and midcaps who continue to gobble up shale acreage. Look at the recent takeover of Anadarko by Occidental. Overpriced and Occi have said they will divest $10-15bln worth of Anadarko assets offshore like GOM fields, but not Shale acreage.

I think half the attraction for a major of having a giant bank of shale acreage is the fact, they are easy acres to play when prices are high and do not require vast amounts of capex which takes years to first oil. They are plug and go and cashflow is seen within a couple of months if things go well. The smaller players in that area, yes, they will be disproportionately affected in a downturn, especially if they have nothing else to fallback on.


Cash

[fardels bear] 30/5/2019 15:42

I think most of us on here probably avoided US shale players like the very plague, MT.

[mount teide] 30/5/2019 14:12

Anyone looking for positive Cash Flow in Q1/2019 should have avoided the US Shale Industry like the plague according to research carried out by Rystad Energy - just 4 out of 40 shale producers managed to generate positive cash flow and its on a falling trend!

Shale sector investors are fed up and “leaving no room for undisciplined spending in 2019" - if they're looking for positive cash flow, perhaps they should sell up and run their slide rule over Jadestone Energy!


Shale Drillers Keep On Falling Into The Same Trap - OilPrice today

Despite the hype of lower breakeven prices, and despite the hype around longer laterals, energy digitalization, and other technological breakthroughs, most shale companies are still not profitable.

In fact, roughly 9 out of every 10 U.S. shale companies are burning cash, according to Rystad Energy. The Oslo-based consultancy studied 40 U.S. shale companies and found that only 4 of them had positive cash flow in the first quarter of 2019. In fact, the number of companies with positive cash flow was lower than it was previously, and total cash flow from the group fell from $14 billion in the fourth quarter to just $9.9 billion in the first.

“The gap between capex and [cash flow from operating activities] has reached a staggering $4.7 billion. This implies tremendous overspend, the likes of which have not been seen since the third quarter of 2017,” Alisa Lukash, Senior Analyst on Rystad Energy’s North American Shale team, said in a press release.

U.S. shale drillers have historically loaded up on debt in order to continue to finance their cash burn. But investors have soured on the sector, finally waking up to the fact that shale drillers by and large are money losers. According to Rystad, no shale company has made a public offering since the collapse of oil prices last year, the longest stretch of time with no public capital issuance since 2014. “Recently released data, which confirmed dismal first quarter earnings, only served to cement negative market sentiment,” Lukash said. Investors are fed up and are “leaving no room for undisciplined spending in 2019.”

The financial position should improve in the second quarter Rystad said. Capex is supposed to be roughly flat, while higher production should improve cash flow.

Smaller shale companies are in a particularly tough position. Even as investors demand capital discipline and an end to reckless spending, small drillers are unable to sit still because of the treadmill of declining shale wells. Rapid declines in output require constant drilling, which, if you are an unprofitable company, requires constant reinjections of capital. For years, that was not too much of problem as long as Wall Street kept the taps open.

However, financing is becoming less abundant as tightfisted investors become more demanding. Instead, in order to survive, small shale companies are under pressure to either grow their way out of the problem or find a buyer, Robert Kaplan, president of the Federal Reserve Bank of Dallas said in an interview with the FT.

While the early years of the shale revolution were characterized by countless small drillers, the industry is consolidating and the majors are increasingly taking over. Large companies have the advantage of being able to stomach years of negative cash flow. They also have easy access to capital markets, and they can use scale to their advantage, such as stitching together contiguous plots and using the same infrastructure for multiple drilling areas.

As investors sour on the energy complex, small mom-and-pop companies are having trouble finding financing. “Because if you’re going to have to drill upon drill upon drill upon drill to maintain just the same level of production, it’s expensive, and people are realising just to do that, I need scale,” Kaplan told the FT.

Yields on junk bonds for E&Ps jumped over the past month, rising from a little over 7.5 percent in late April to almost 8.5 percent in late May.

The latest company to throw in the towel was White Start Petroleum LLC, which filed for chapter 11 bankruptcy protection on Tuesday. The company was founded by the late Aubrey McClendon under a different name, American Energy Partners LP, shortly after McClendon was forced out of Chesapeake Energy. The company has been “stressed financially in recent years, partly due to low production volumes and higher-than-expected operational costs,” the Wall Street Journal reported. Ravaged by the collapse of oil prices in late 2018, the company stopped drilling new wells in April, the WSJ said.

WTI is back below $60 per barrel and, unless it rebounds, scrutiny on the entire sector is likely to pick up.'

[croasdalelfc] 30/5/2019 13:47

There should be 8 liftings from Montara in 2019 by quarter 1,2,3 and then 2 in Q4.It will depend on the amount of offline days in Q2 and Q3 for the LWIs and other work . 8 x 575k should be 4.6m barrels .Stag should be 4 x average 200k or 800k barrels .Year total 5.4m @ $70 oil is $378m with Q1 just 14% of the year due to inventory build

[tim000] 30/5/2019 06:59

This may be obvious, but it's worth emphasising. Obviously profits in Q1 were below normal for the year, for a variety of factors. Production was 13059 bopd in Q1, or 1.175 mn bbl for the quarter. By contrast, sales volumes were 0.75 mn bbl, implying an increase in inventories of 0.425 mn bbl, worth about $30 mn revenue. Assume production (ie 1.175 mn bbl) and oil prices in Q2 are the same, and that all of the increase in inventory is cleared. Then sales increase to 1.6 mn bbl in Q2, which is a 113% increase on Q1. Revenue increases by nearly $60 mn. Of course the P/L accounts will net off higher production costs. But given how high margins are for JSE, the impact on net revenues should be circa $42 mn. There will be other offsets in depreciation etc. However, PBT in Q2 will be much higher than in Q1, I can say that with almost complete certainty. But it is the H1 figures that will give a more representative picture of the business.

[spangle93] 30/5/2019 00:40

@Alan ref 1188 and @Tim1192

While MT is correct to raise the improved uptime as a reason for the increased production rates in 1Q, I believe from this presentation there's more to it. Caveat: I've read the slides but not played the webcast.

Look at slide 9 - ref optimisations
I think they've done a wee re-routing of pipework during the shutdown, such that the flow from the subsea well risers is now diverted to an LP separator. The effect of this is to drop the system back pressure, so wells can flow naturally, without needing the gas lift.

It's not clear whether the top two lines can be added, or whether the 1000 is part of the 2500. What is clear is that through this move, the wells in line for remediation with the LVI have been contributing quite significant flows since the restart, and that confirms what I suspected in an answer to MT in April, that what we thought was flush production causing higher rates immediately after the restart is actually sustained longer due to these previously shut in wells flowing.

I guess that means there will be a temporary drop in production when the LVIs proceed, but once they are done, we should get reliable, meaningful flows from the satellite wells, many of which were not producing when the CPR was written.

[mount teide] 29/5/2019 22:59

Our research strongly indicated that Montara has been incredibly poorly managed by the Thai's throughout its operational life and picked up for a song by Jadestone at the very bottom of the oil market cycle.

The first clue as to the upside potential of Montara was the stunning revelation that even with much lower than 72% field uptime in the first 9 months of 2018 and, production of just circa 7,500 bopd, the field still generated a $92 million cash transfer to Jadestone on completion, largely from a recovery in Brent to an average price of $68, still some 20% below the previous 10 year average price.

In a maturing oil field serviced by a FPSO on long term charter the OPEX/bbl will be substantially higher than in the early years as a result of the largely fixed operating cost.

The FPSO charter cost is usually a very high percentage of the total field OPEX - Premier Oil has the FPSO BW Catcher on a 10 year charter at $210 million a year plus annual uplift.

Unlike Premier Oil, Jadestone should now be incurring just the physical cost of operating the Montara FPSO. Premier will be paying the physical operating cost PLUS the overwhelming majority of the build cost of the FPSO spread over the duration of the first fixed charter period, plus a profit margin - the build cost alone of BW Catcher was circa $600m.

If Jadestone had BW Catcher on charter on Montara at its present charter rate to Premier the operating cost of just the FPSO would be circa $53/bbl.

Having FPSO Montara Venture thrown in as part of the deal, means that the FPSO operating cost per barrel on Montara at 11,000 bopd of production would be nearly identical to the Catcher Field's FPSO with 66,000 bopd going through it.

Consequently, Jadestone has the potential to materially reduce Montara's OPEX even from the current level through a relatively modest increase in production.

[tim000] 29/5/2019 19:57

On another note, the company is confident of not being liable for any Australian corporation tax on 2019 profits, as past Montara losses are carried forward to fully offset 2019 liabilities. (The Montara and Stag businesses are being consolidated into one entity, so the past Montara losses can also wipe out corporation tax liabilities from Stag.) Those were likely to be substantial, so the outlook for cashflow this year is getting better and better. I'm not sure what the catch is?!

[king suarez] 29/5/2019 19:38

I'm wrong, sorry. The P&L has a separate line for depreciation, so not included under 'cost of production'.

Note 5 of the accounts breaks down the cost of production figure and the narrative re: $23.75 opex per barrel states that this is after excluding work overs and repair and maintenance.

The operating costs in note 5 are stated as $15.5m, but on 749k of sales @ $23.75 a barrel would need to be c$17.8m, so I guess perhaps only part of the $8m 'logistics' figure may be included?

Worth clarifying as it's not entirely clear!

[tim000] 29/5/2019 16:54

That sounds possible. What I don't yet fully understand is whether the company is claiming to massively reduce operating costs this year, and uses the $23.75 figure as evidence, and if so whether the published P/L accounts will bear that out. More work is needed! Because many operating costs are fixed, obviously increasing the utilisation rate (and hence production) proportionately reduces unit operating costs. But the company is claiming more than that. I think they are indeed introducing efficiencies, as MT has pointed out, but I want to see that reflected clearly in the P/L account too.

[king suarez] 29/5/2019 16:39

Might be that the operating costs per barrel excludes the non-cash cost amortisation and depletion (which is included in the total cost of production figure)? This would be similar to mining companies not including the depreciation charge in the quoted AISC per ounce..

[tim000] 29/5/2019 15:40

Regarding Spangle's query in post 1178 re: operating costs, these are quoted in the RNS at $23.75 per bbl. But another way to look at unit operating costs is simply to divide published total production costs (ie $22721k) by sales volumes (749k bbl). That yields operating costs per bbl sold of $30.3, which is roughly what I had assumed before today. It's difficult to tell how $23.75 was calculated, the picture is confused by the build-up of inventories. However, on the assumption that unit costs do indeed fall over the rest of the year to the targeted figures, and production reaches 15.6k bopd in H2, and oil prices etc are unchanged from current levels, then fwiw my own rough analysis indicates that post-tax eps this year are on target to be in the range of 15-20p in 2019.

I haven't yet heard the conference call, I imagine that will be on the company's website idc.

[croasdalelfc] 29/5/2019 12:21

A good question for the conference call ?

[alan00] 29/5/2019 12:04

Hi,

With regard to "The Company is preparing for a substantial scope of work on the Montara complex in Q2 and Q3, including replacement of the subsea umbilical from the Skua and Swift/Swallow subsea wells to the Company's owned FPSO, together with a riserless light well intervention ("RLWI") programme that will restore gas lift to the Skua-11 and Swift-2 wells, perforate additional sands in the Swallow-1 well, and unlock new heel volumes in the Skua-11 well. The RLWI is targeting 3,200 bbls/d, including continued production from Swift-2 and Skua-11, in addition to the new incremental volumes."

Does anyone understand how much of the 3,200 bbls/d targeted by the RLWI is incremental to current production?