Description

Long Jadestone Energy

All values are given in USD unless otherwise stated

“Figure out what works and do it (again)” Charlie Munger

Text in () added by the author of this writeup

Jadestone Energy has been written up on this site around 2.5 years ago and since the last write-up, more has changed than just the share-price (about x2.5 times since then).

With Jadestone you have the opportunity to invest in a management team which has done it all before, and from the looks of it (about 4 years into their stint at JSE) are pulling it off again, and maybe even better than the first time.

Since people on this site are quite fond of numbers, here are the numbers of their previous venture. There may be some small differences in numbers over the years since some segments which were listed under other were grouped differently over the years in their reporting.

This management team created above 6 billion of value (2.4 billion in Free-cashflow and 3.7 billion NPV at the time of sale to Repsol) over a period of 15 years on an initial balance sheet total of 600 million. What is more remarkable is that these outsized returns were achieved while running a business with a lower risk profile as a traditional E&P business. Management is also very cognizant of balance sheet risk, which is quite important in a commodity business. A last point, the previous business they created was the lowest cost and highest margin operation in Talisman Energy. Some even went so far as calling it Talisman Energy’s crown jewel.

Modus Operandi 

Jadestone Energy operates with less risk than the traditional E&P company while attaining a higher return. They run very low exploration risk since they acquire already producing fields and optimize them, or they acquire licenses with discovered but undeveloped resources. Since 2 of the largest risks in the E&P business are reservoir and exploration risk, they are bypassing most of these risks here (long operating history on some acquired fields, and no exploration risk on stranded developments).

To give some examples:

At Talisman, they acquired Lundin Oil in 2001 for about 344 Million. They managed to sell some parts of the company for 75 Million, and kept a few smaller North Sea interests. With it came a 41.44% interest in the PM-3 Commercial Arrangement Area (PM3-CAA), a license shared between Vietnam and Malaysia containing an estimated 440 MMboe on a gross basis in 2000. At the time of the acquisition, these fields were producing about 14 thousand barrels of oil equivalent on a gross basis (6,000 barrels net). Most of the capex for the years 2002-2004 in the table above were for this asset.

The Talisman management (and now Jadestone management) cut costs on the field expansion by 100 million with a redesigned Phase II development. In less than 3 years’ time, the production was increased to above 105 thousand barrels on a gross basis (or a little over 40 thousand barrels on a net basis) at a production cost of less than 3 dollars per barrel. To put it in numbers, they paid less than 2 dollars per barrel of reserves (which later increased after more discoveries in the block). In the end, after all the capex, they created this business at a price of less than 20.000 dollars per flowing barrel, for a high margin, long reserve asset. This was probably the best deal they did in their history.

A different acquisition was the Jambi Merang Production license from Hess in 2010. They paid 189 million for a 25% WI in this PSC containing 190 million barrels of 2P reserves (4 dollars per barrel, but in reality closer to 6-7 due to the inability to exploit all the reserves before the expiration of the license). This area contained 2 discoveries made in 2001 and 1995. Since the discovery of these fields, a few exploration and delineation wells were drilled but no work was done by the parties involved in the license. This PSC was due to expire in 2019. The Talisman management took over this license and in a little more than a year (11 months) brought the license into production.
Production at peak was close to 25,000 boe, with around 20.000 barrels of gas and the rest were liquids. This was a decent acquisition, but nothing really spectacular like the PM3-CAA license.

Not all acquisitions were excellent. A nice example is the Red Emperor acquisition from Premier Oil. After having spent 200 million in FEED and appraisal costs the company decided to shelve this development due to pressure from China around the maritime border issue.

But even then, everything combined they managed to produce a great track record over the years doing these kind of deals.

At Jadestone, until now there have been 4 acquisitions, of which 3 deals closed,  one fell through and one has been announced and should close later this year. Each of these deals have very interesting and enticing acquisition metrics, which have been far superior to most deals done under Talisman.

Stag – the first

The Stag field was acquired from Santos and Quadrant Energy in 2016 for 10 million (6 million after WC adjustment). This compares very favorably to a previous deal in 2015 to sell Stag by Santos and Quadrant to Sona Petroleum for 50 million, later lowered to 25 million (Sona Petroleum was a Malaysian SPAC which has since been liquidated). The Sona deal fell through on concerns of asset quality and the fact that the license expired in 2018 if it couldn’t be extended.

Stag is a sweet heavy oil field of the coast of West-Australia that has been in production since 1998. Stag contained 2P reserves of about 14.6 million barrels of oil at the time of acquisition and 3P reserves of 22 million barrels. As of January 2019 the 2P reserves were 16.2 million barrels and 2.7 million barrels in 2C resources. This equates to an RLI of 10 years in 2020 excluding 2C.

No matter how you look at it, this acquisition was dirt cheap at less than 0.5 dollars per barrel of 2P reserves and below 5,000 dollars per flowing barrel.

The plan for Jadestone is to lower fixed costs (they lowered operating costs by 35% since taking over operatorship with some minor improvements still to come), increase production to lower the fixed costs per barrel of operating an offshore oil platform and access more reserves to extend field life. This should be achieved through infill drilling and the possible upside with near field exploration (for example the near field but small Centaur and Antler discoveries and the Stag South and Hart Prospects).

At the time of acquisition, the field was producing around 2,600 barrels of oil per day. Improvements and one infill well have increased production to about 3,800 barrels in Q3 19. They plan to drill 4 more infill wells over the next few years. These initiatives should lower the lifting costs from about 40-45 dollars per barrel under the previous owner to around 20-25 dollars per barrel in the future (they already achieved 23 dollars per barrel in Q3 2019).

Given that OOIP was estimated to be around 170-180 million barrels for this field and the recovered amount is around 65-70 million barrels, determining field life will be based on how much they can stretch the recovery factor. In essence, by every 1% improvement in recovery factor it extends field life with about 1-1.5 years.

The largest liability and uncertainty about Stag is of course the decommissioning cost of 80 million barrels in 2033, discounted at 2.7%. The further this liability is extended (some Jadestone plans speak about 2039), the more value Jadestone will have created. The number of 80 million also assumes the need for a rig to be chartered. Management mentioned they are investigating if it is possible to use the Stag platform drilling rig to plug most of the wells on decommissioning. This could lower the total cost of decommissioning quite substantially.

2 more nice considerations:
- The premium for heavy sweet oil in the APAC region has increased dramatically since the regulation to use scrubbers on ships. For Stag, this meant that they are able to sell their oil at a more than 10 dollar premium to Brent. How long this will remain is hard to estimate, but it is a nice benefit which wasn’t really expected at the time of the purchase.
- Another nice one is the optionality this field creates when oil prices would rise. At higher oil prices it is possible to extend the productive life for longer, and thus again extending the date, and cost, of decommissioning.

The 05-1b&c licenses offshore Vietnam – the one that fell through

In august 2016, Jadestone announced the possible acquisition of a 30% interest in Blocks 05-1B And 05-1C offshore Vietnam from Inpex. They bought these interest for 14.3 million and a deferred consideration of 15.7 million, in 2 tranches upon sanctioning and first production from the field.

These blocks contained 2 discoveries with estimated resources between 20 and 55 million barrels oil equivalent. Of these, there was about 82% gas and 18% gas liquids. This equates to an acquisition price of between 0.55 and 1.5 dollar per barrel, depending on the amount of gas and liquids in play.

There was an estimate made of development costs, which was reasonable due to nearby infrastructure (pipeline etc.. already in place) and an NPV between the low and high estimate went from 100 million to above 400 million in the high case. Even the mid-case gave an NPV of 314 million. One thing to take into consideration was that the price assumptions for the liquids were a bit high though.

In the end, the deal fell through because Inpex terminated the agreement after Petrovietnam waived their statutory pre-emption right to enter the block.

While not useful anymore for an investment in Jadestone, it is a nice illustration of the way this management team works and the white rabbits they can pull.

Montara

In July 2018, Jadestone announced the acquisition of the Montara oilfield offshore North-West Australia for 195 million from PTTEP, the Thai national oil company. In reality, the acquisition was done at 133 million for a WC adjustment of 13 million and because they back-dated the acquisition, which reduced the purchase price by 75 million. Another nice detail was that the acquisition was done on an asset basis, not a purchase of shares, because Montara was responsible for one of the largest offshore oil spills in Australia’s history. This way, they hope to shield them from any liability going forward.

At the time of acquisition, they paid just below 7 dollars per 2P barrel, 1.6 times EV/EBITDA and below 20K dollar per flowing barrel for a field with a reserve life of 7 years on a 2P basis.

Since being acquired more than a year ago, Montara has already returned the cash price paid to Jadestone in cashflow from operations, which they have mostly reinvested into the field to optimize the current wells using a riserless light well intervention vessel (the cheapest and most efficient option), replacing the umbilical (mostly for future tie-backs I assume) and used the remaining cashflow to repay debt taken on for the acquisition of Montara.

On its own, Montara is quite a nice acquisition. For upside, there was some low hanging fruit in cost savings and higher uptime (Montara was quite badly run by PTTEP). Most of these cost savings have now been achieved, with some minor savings still to come, mostly shared costs with their Stag oilfield. As of the date of writing this write-up, Montara is producing oil at a cash cost of around 20 dollars per barrel.The current plan relies mostly on infill drilling on the already producing fields (Montara and Skua) where a few locations have been identified which target unswept or bypassed oil.

There are many additional opportunities further out in the future. The acreage around Montara has multiple discoveries, many even in the same blocks that Jadestone controls. In the same block as Montara, there have been 4 gas discoveries (Bilyara, Padthaway, Tahbilk and Leeuwin), of which at least Bilyara contains moveable oil.

In neighboring blocks to the Jadestone acreage are a few stranded discoveries which haven’t been developed to this date. The closest one’s are Maret and Great-Auk, but Talbot and Keeling may also be a possibility.

In the recent Capital Markets Event, Jadestone even mentioned the possibility of developing the nearby Puffin Field. If they could do this in a successful way by tying it back to the Montara FPSO, the upside here is very large.

In 2007, the Puffin field was developed by asx listed AED Oil (they later brought in Sinopec which paid 600 million for a 60% interest). The wells were initially very productive (close to 10,000 barrels per well) but watered out very quickly. The real reason for this were never discovered since all sorts of drama happened and the field had to be shut in 1.5 years later. The FPSO was shut down due to occupational health breaches by the operator and after that the field had a minor gas leak. There were massive lawsuits between the operator and the owner, which went into administration a few years later. This makes the reserve estimate for the field very difficult, but before the development, reliable sources frequently mentioned 40 million barrels of recoverable oil. During the development, all sorts of numbers were used from 10 million barrels in the lowest case to 100 million plus.

Given all the above points, I find it quite likely production will at least continue into the next decade, and thus defer the decommissioning liability of 183 million far into the future.

One more thing, included in the acquisition price is a fully owned FPSO which is currently worth around 40-50 million.

Maari (and Manaia) – the big one

In November 2019, Jadestone maybe made their best acquisition to date by taking over OMV’s 69% operator interest in the Maari/Manaia fields in New-Zealand for 50 million. This 50 million acquisition price will probably be financed by OMV since Jadestone again back-dated the acquisition, effective January 1^st 2019, and the deal will close somewhere in H2 2020. This field produced free-cash in 2018 of 40 million. As of the date of this write-up, Maari produced around 7,000 barrels of oil on a gross basis at around 25-30 dollar per barrel cash operating cost.

The acquisition metrics are again excellent at less than 4 dollars per barrel, probably 1.5 times EV/EBITDA and about 10,000 dollars per flowing barrel .

While Maari is a complex field, with a difficult and waxy oil, the opportunity here is very large. Maari has a high OOIP of more than 300 million barrels, and maybe even more than 500 million including an undeveloped zone which was discovered but never developed in 2014. Since the field has produced less than 40 million barrels to date, the opportunity set here is pretty large.

If Jadestone would do nothing, the current set-up means the field would keep producing until 2031. That however would mean recovery factor’s in the Maari 0 sequence in the low single digits due to a single well that has to produce a complex reservoir of 70 million barrels, one single horizontal producer in the Manaia Mangahewa reservoir for an OOIP of 46 million barrels and a recovery factor of 27% in the largest zone containing more than 150 million barrels in place.

Since this field has been plagued by low deliverability of the wells (the field was designed for peak production rates of 35,000 barrels but produced this amount for just months), it is surprising they have been producing with very little water flood to maintain pressure. Jadestone’s management has recognized this and are rethinking ways to increase pressure in the field. One advantage about the lower deliverability is that decline rates have stayed relatively shallow over the years.

In essence, the basic setup will be to increase the amount of producers and injectors to obtain higher recovery factors going forward. These measures should extend the field life at least to 2038. This does not include any potential upside from the Manaia Moki reservoir.

Since Jadestone also applied for an exploration permit in New Zealand, it stands to reason they are also looking at near-field exploration in the long run.

As an added bonus, the acquisition of this field came with a full work-over drilling rig in the platform which should make the development of some wells a lot cheaper. A 69% interest in a fully owned FPSO, a sister ship of the Montara FPSO which should be worth about 30 million, means more than just lower operating costs.

The Nam Du and U Minh gas fields (and Tho Chu) – the legacy

These were the only fields left over from Mitra Energy, the predecessor company from which Jadestone was born in 2016 after the new management was brought in. These are also the fields that should provide the production growth in the next 2-3 years, giving management ample time to further explore and come up with ideas to develop the above mentioned fields.

Nam Du and U Minh are small but close to infrastructure gas fields offshore Vietnam. Since the Jadestone management team had extensive experience in Vietnam and that area (the PM3-CAA license is nearby the Nam Du and U Minh fields) there shouldn’t be any major hiccups. The fields will be developed with 2 unmanned well-head platforms and an FPSO for separation and recovery of the condensate, developed in 2 stages, with tie-backs to existing pipelines. The economics are very decent with capex of close to 300 million over a 4 year period and close to 150 million in operating cash-flow per year over a period of 5-6 years. An additional benefit is that these fields will sell their gas at a fixed price, which is nice in a period of very volatile commodity prices. The exact price of these gas sales is still under negotiations.

Here again there is upside possible in a lower channel which they will test when drilling one of the development wells and nearby prospects.

The Tho Chu field is a different story and much more complex. It is also one of the more interesting plays of the company given it’s very large GIIP and 2C resources of a mean trillion cubic feet and 0.25 trillion cubic feet of gas respectively. The field contains up to 55 thin hydrocarbon pay reservoirs over a depth of 1,700 meters and will be a challenge to develop, but the opportunity here could be huge. The development of this field is dependent on the development of the Block B-Ô Môn gas project for the use of the export pipeline.

Valuation

This to me is one of the more puzzling things about Jadestone Energy. After all these deals and the capabilities management has shown (both in the past and at Jadestone) the valuation of this company is among the cheapest in the sector.

At the current enterprise value of 310 million (360 market cap – 50 million net cash), Jadestone is trading at less than 6 dollars per barrel of developed reserves. This number assumes the closing of the Maari deal. If the Nam Du and U Minh reserves are included, which are mostly added upon sanctioning of the development, you get to less than 4 dollars per barrel. Even if you take the current production and assume no growth nor Maari closing, Jadestone is trading at 22,000 dollars per flowing barrel (including Maari it is less than 18,000 dollars per flowing barrel).

Since these production barrels are high margin, the current EV/EBITDA is likely less than 2.

The question about abandonment liabilities has be mentioned here. The thing is, like I have been trying to show above, that the probable economic life of these fields is at least 10 years, and in all likelihood will be closer to 20 or 30 years if you include some of the upside which management is targeting. This is longer than many of the more “conventional” oil companies, and these are not as burdened by their abandonment liabilities in their valuations as Jadestone is.

The negatives

No investment is without negatives, and the one’s here are mostly related to the low amount of insider ownership (the CEO owns 0.65% of the shares outstanding after a very recent share purchase). In total, management and directors own less than 3% of shares outstanding.

Another negative is that some deadlines have been postponed. This is something common to the resource sector, but one has to take this into consideration. 2 clear examples are the planned Montara infill well and the seismic acquisition, which were planned to have been executed in 2019. The same goes for the first Stag infill well and the Nam Du/U Minh sanction dates (both more than one year late, although Nam Du/U Minh sanctioning hasn’t taken place yet but is guided for early 2020). Despite these delays, the performance to date has been more than satisfactory.

Catalyst

* Oil Price

* More deals

* Time

* Management excecuting on the strategy