Member Info for MountTeide

Petrotal has blasted through October's record 194k bbls of production after just 24 days in November.

The company is now the third largest oil producer in Peru, currently responsible for 13.8% of the Nation's oil production, up from 11.1% in October.

Post the commencement of production from well 4H in mid October, Q4 average production has increased by 88.3% from 3,771 bopd to 7,101 bopd, and is currently averaging 8,151 bopd in November, up a staggering 1,011% since January 2019.

2019 - Monthly Production Growth - Month on Month % Growth in brackets

8,151 bopd (+29.6%) - November
6,288 bopd (+27.1%) - October
4,948 bopd (-3.5%) - September
5,132 bopd (+16.9%) - August
4,387 bopd (+1.5%) - July
4,320 bopd (+51.6%) - June
2,848 bopd (+66.4%) - May
1,711 bopd (+76.9%) - April
967 bopd - (+15.3%) - March
838 bopd - (+4.0%) - Feb
806 bopd - Jan

Very pleasing quarterly performance after taking into consideration the impact of the Montara Capex programme on field uptime together with the timing of oil liftings on revenue recognition.

Operating/production performance:

Q3 Montara production a little lower than I expected at 9,235 bopd - I suspect the result of the LWI and umbilical replacement programme taking around 10-12 days longer than planned, although it still came in on budget.

Average production to the end of Q3: 13,135 bopd
Entered Q4 averaging circa 15,850+ bopd

Suggesting if maintained during Q4 an average of circa 13,500 bopd to 13,813 bopd for 2019 is potentially achievable.

Q3 OPEX by Field - (by calculation)
$19.42/bbl - Montara
$23.00/bbl - Stag

Q3 OPEX reduced to $20.43/bbl from $21.74 in Q2 - Stag declined by $5/bbl(18%)to $23/bbl, mostly due to the first full quarter impact of the increase in production delivered by the 49H infill well completed in Q2.

Montara's Q3 OPEX dropped to under $20/bbl for the first time, despite average production during the quarter reducing from circa 11,000 bopd in Q2 to 9,235, to effect planned CAPEX and maintenance projects, which reduced the field uptime from 84% to 72%. In addition, Q3 will have contained the last of the hefty Montara operatorship payments to PTTEP under the Transitional operating agreement.

Combined Stag and Montara field uptime on target to meet or exceed the 84% annual target. This would be an increase for Montara of well over 20% compared to 2018. Medium term overall field uptime target 90%+ - current North Sea basin average is 82%)

With Montara production entering Q4 at over 12,000 bopd(up over 30% from Q3 average), and no further operatorship service payments - it suggests Q4 has the potential to show a material reduction in both the Montara and the overall OPEX.

Average Q3 realised oil sales price after adjustment for Montara hedge was over $70 bbl against a Brent average price of $62/bbl down from $68.86 in Q2.

Uneven revenue recognition due to the timing of oil liftings together with the impact of major Capex and planned maintenance expenditure to increase production, improve field uptime and reduce maintenance will see 2019 as a year where Q2 and Q4 deliver a materially higher performance than the 2019 guidance average, and Q1 and Q3 materially lower.

AIMHO/DYOR

The impact of Jadestone's management on the OPEX of the Montara and Stag fields is well worth some research.

Q3 OPEX by Field - (Montara by calculation)
$19.42/bbl - Montara
$23.00/bbl - Stag
$20.43/bbl - Overall

The scale of the OPEX reductions achieved by the Jadestone management from these two assets in the run up to and following completion of the deals to date is astonishing.

Both Montara and Stag had OPEX well above $50/bbl in the period preceding completion of the two deals.

The OPEX results to date suggest either the Jadestone management are outstandingly good or the previous owners completely inept - I suspect its more a case of horses for courses - larger companies specialise in bringing into production and operating large new fields while companies like Jadestone are second phase experts.

Presumably the primary reason why a bombed out Santos Oil(who were haemorrhaging cash) dropped their price for the Stag field from the $50m asking price to Blakeley's exquisitely timed $10m offer, was its $50+ OPEX and the fact that at the time of the negotiations Brent was in free fall at circa $30/bbl and heavy sweet crude at that time attracting a $3-5 discount to dated Brent.

It's a testament to the skill of the Jadestone team that even after the huge reduction in OPEX at both fields achieved to date, they have identified measures to achieve further reductions in OPEX - which may well see overall OPEX drop below $20/bbl for the first time in Q4 2019.

The OPEX reductions achieved to date when combined with oil sales prices for Jadestone's production mix now achieving a more than $8 premium(17%) to dated Brent after adjustment for the oil hedge is delivering a tremendous operating cash flow result even at $62 Brent.

Jadestone has delivered at least a $27/bbl(54%) reduction in OPEX since taking over the Stag asset - and an astonishing circa $74/bbl improvement in operating cash flow at circa $62 Brent from around the effective acquisition date of 1/1/2016

Broken down as:
$32/bbl - Improvement in Brent Price
$15/bbl - IMO 2020 impact on Sales Pricing - $4 discount to Brent to $11 premium
$27/bbl - OPEX Reduction under Jadestone management.

AIMHO/DYOR

Latest tender of Australian Pyrenees for late Jan 2020 loading generates an astonishing $17 premium to dated Brent!

Singapore, Nov 22 (Reuters)

* Australia’s BHP Group Plc is said to have sold a cargo of January-loading Pyrenees crude at a high premium of around $17 a barrel to dated Brent via a spot tender, three traders said on Friday

* The loading dates for the 550,000-barrel cargo are Jan. 27-31

* The buyer of the cargo was not immediately known

* Prior to this, a December-loading Pyrenees crude cargo was traded at a premium of above $16 a barrel to dated Brent, likely to Gunvor

* Pyrenees is a low-sulphur, or sweet, heavy Australian crude. It is being sold at high premiums because of strong demand from traders who are buying the grade for blending into marine fuels that meet new low-sulphur ship fuel rules starting in January 2020

Crude Oil, Fuel Oil(Global Ave) and Marine Gas Oil(Global Ave) Prices Per bbl

$95 - MGO
$89 - LSFO
$75 - Stag (assuming $12 premium to Brent - last lifting was $10.2 in August)
$72 - Jadestone's average 2019 hedged price on 50% of Montara's 2019 Production
$69 - Montara (assuming $6 premium to Brent - last lifting was $4.6 in August)
$63 - Brent
$58 - WTI
$51 - HSFO
$38 - Differential between high and low sulphur fuel oil

Maari Field - Operating Cash Flow attributable to Jadestone (69%)

Horizon Oil (26%) has some very useful information on its website with which to get an understanding as to the Maari Fields operating cash flow generation over the last 6 months.

1,772 bopd - average net production during period to Horizon
4,702 bopd - average net production during period to Jadestone

$25.0/bbl - average OPEX - (actually reported as sub $25)
$65.5/bbl - ave Brent price plus $2 regional sales premium

$40.5/bbl - Maari / Operating Cash Flow

Extrapolating this performance to an annual basis - suggests at 4,702 bopd average production, Jadestone's 69% ownership would generate annual operating cash flow of circa $70 million.

A look at what Jadestone's average realised oil price may be on current Australian production of circa 15,000 bopd at today's $63.5 Brent price, after adjustment for the circa $72 ave oil price hedge on 50% of Montara's 2019 production(hedge drops to circa $69.0 in 2020):

$75.0 - Stag - 4,000 bopd at an est $11.5 premium to Brent
$73.0 - Montara - 11,000 bopd at an est $5.25 premium to Brent + $72(50% oil hedge)

$73.50 - Est ave Realised Price on circa 15,000 bopd including Montara 50% hedge
$63.50 - Brent

This suggests Jadestone's current 15,000 bopd of Australian production is likely generating an average realised price of a circa $10 premium to Brent.

I estimate that the International Maritime Organisation's decision to transition the global shipping fleet into operating on low sulphur fuel oil from Jan 2020, is currently responsible for delivering to Jadestone's ultra low sulphur production mix, a circa $9.5/bbl sales price increase compared to when the global shipping fleet operated on high polluting HSFO(without any Montara oil price hedge contribution).

AIMHO/DYOR

Paul Blakeley has mentioned previously that Jadestone's perfect mid/late life acquisition would ideally have re-investment potential greater than the acquisition purchase price.

That was never going to be much of a challenge with the Stag asset - the first Stag infill well cost around 3 times the purchase price of the entire field !

The oil sector was first made aware of the likely impact on the industry of the IMO 2020 low sulphur fuel regs as far back as 2008, when the IMO first informed the shipping industry of its intention to move the global fleet away from the use of cheap heavy, high sulphur fuel oil by Jan 2020.

The IMO's 2016 confirmation that the implementation of the 2020 regs would definitely proceed in Jan 2020, should have been the signal that alerted the sharper eyed individuals in the oil industry to the fact that by 2020 heavy sweet crude oil, would likely transition from large price discounts to Brent to large premiums - and so it should not have been a complete surprise to the industry to now see heavy sweet crudes like Pyrenees, Stag, Van Gogh etc move from decades long circa $3-8 discounts to Brent to circa $16+ premiums in the run up to Jan 2020 .

A circa $20 turnaround on the sales price of a commodity with an average price of $60 without it costing a penny more to produce is the stuff of investment dreams.

That the $10m purchase of the Stag Oil field from a bombed out Santos was wily old Blakeley's first Jadestone acquisition at the end of 2016 i strongly suspect was no coincidence.

Maari Oil Field - the NZ Government's O&G production statistics are helpfully reported by field - the Maari Field is by some margin the largest producing oil field in NZ.

For Jadestone to develop their NZ business to 15,000 to 20,000 boepd, it suggests the management must be quietly confident of the re-investment potential of the Maari field as it is likely to involve a substantial additional contribution from this asset - exploring the potential to competitively acquire the other 31% of the field may be a good place to start, by sounding out how attracted the two partners are to funding their share of what will likely be (for them) a significant future re-investment programme.

The NZ O&G statistics also points to Nat Gas assets rather than oil as future acquisition targets, as there appears to be far more potential to buy significant production by going down that avenue.

Its worth bearing in mind that FPSO's are highly specialised vessels designed for the unique technical characteristics, location, sea and weather conditions of the oil field they've been built to operate on - and so are rarely available in the charter market following the end of a major contract without highly costly and time consuming modification.

From commencing construction of a new FPSO or conversion of a second hand VLCC into a FPSO, routinely takes a shipyard 2-2.5 years to complete.

The Montara Venture is the only means through which the numerous stranded discoveries and multiple suspended fields in the blocks immediately neighbouring Montara can be developed, since they're not of a size that can economically justify a standalone development with FPSO.

Putting another circa 7,500 bopd of production through Montara Venture from the adjacent blocks and hitting the medium term 92% field uptime target, could potentially lower Montara's OPEX/bbl into the $10 - $15 range.

Premier Oil has the FPSO Catcher on a ten year charter at $200 million a year (inclusive of operating cost) - thrown in as part of the Montara deal, FPSO Montara is now only incurring operating expenses and insurance etc, which will be a tiny fraction of Premier's $200 million annual FPSO charter cost - initially a $2.0bn liability over the fixed period of charter.

As a consequence, attracting additional production from the neighbouring blocks to handle through Montara Venture by acquisition, farm-in or third party tariff arrangements were never a serious consideration when PTTEP were operating Montara as the circa 70% average field uptime and sky high operating costs(circa $45/bbl in 2017/18) made that a commercial non starter.

However, the situation will have changed completely with Jadestone's team now running the field infrastructure and FPSO and achieving circa $20/bbl OPEX and 85% field uptime at a circa 11,000 bopd production level.

So, it was no surprise that Jadestone were able to get third parties with interests in the adjacent blocks to share the cost of the new seismic scheduled to be shot over Montara and the adjacent blocks during Q4/2019.

AIMHO/DYOR

Premier Oil are paying a charter rate of circa $200m a year for FPSO Catcher, the new purpose built FPSO on their North Sea Catcher field that has less oil storage capacity and only 50% greater oil, gas and water handling/processing capacity than Jadestone's FPSO Montara Venture.

Montara Venture - a VLCC bought and converted into a FPSO at the Jurong shipyard, Singapore for a total investment cost of circa $107 million, and thrown in for free as part of the $195 million Montara asset deal - circa $82 million net on completion (after adjustment for oil sales and field shutdown compensation).

Montara Venture is not due statutory dry docking before circa 2030 at the earliest - as a result of holding a Class approved dispensation to conduct in water surveys in lieu of dockings.

Most Hedge Funds are medium distance and marathon runners while PI's are largely sprinters.

Many PI's will have stampeded in here on expectation of a mark up on notification of completion of the 7E deal - the hedge funds of course know this and so crafted a ruse to use the liquidity generated by the completion RNS, to work with any larger holders lightening up, to push the price down to frustrate the PI's into selling cheaply to them by knocking out their trailing stops - like taking sweets off a child.

20% off the 27p recent top is circa 21.5p - I suspect we're close to the bottom now.

AIMHO/DYOR

Paul Blakeley considers the Montara asset one of the best opportunities he has seen in 25 years - many might suggest his Stag Field acquisition does not look too shabby either.

Acquisition Costs per bbl of 2P Reserves and per flowing barrel:

MONTARA: P2 - 26.6 mm bbls
$195m (Gross Acquisition Cost - circa $82m Net)
$7.0 per bbl 2P reserves / $19,000 per flowing bbl
(Reduced to $3.20 per bbl 2P reserves / $8,200 per flowing bbl on completion, after cash adjustments for Jan-Sept 2018 oil sales and field shutdown compensation)
$50m - Estimated current Quarterly operating cash flow

STAG: P2 - 16.2 mm bbls
$10m - Acquisition Cost
$0.60 per bbl 2P reserves / $3,300 per flowing barrel
$16-18m - Estimated current Quarterly operating cash flow

At the time of the early 2016 acquisition, Brent was in freefall at circa $30/bbl, owner Santos Oil were in serious trouble having seen their market cap collapse 80% in the preceding 16 months; while in H2/2015 Santos had seen a $50m deal for Stag with SONA Petroleum fall through(even after offering to reduce the purchase price to $25m), while STAG's OPEX were estimated by JSE in the range $50-$70/bbl.

Following JSE's purchase of the asset they took over operatorship in H2/2017 - OPEX has since been reduced to $28/bbl and remains on a declining trend, while the current market price of Stag's heavy sweet production is in the range of $75-$80 at $63.5 Brent.

'Owning yachts is a mugs game.' As a small boat owner for over 45 years i can speak with some experience and would offer the following the hard earned advice - anyone considering buying a boat for use in UK waters should stand under a cold shower and rip up 500 Euro notes until the idea goes away - as it is certain to work out much cheaper.

Very interesting - potential acquisition on an altogether different scale to Montara - little wonder the dividend and first Montara Infill well has been pushed back into 2020!

Jadestone Energy Tipped As Suitor For Inpex - The Australian today

'Jadestone Energy is tipped as a strong candidate to purchase the West Australian assets up for sale by Japanese oil company Inpex.'

Inpex - Western Australian Assets

Van Gogh Asset - Heavy Sweet Crude
'Production commenced in 2010 at the offshore Van Gogh oil field, 53 kilometres northwest of Exmouth, Western Australia.

The average production rate for Van Gogh is projected to be 40,000 barrels of oil per day. Quadrant is the operator of the Project with INPEX holding a 47.499 per cent participating interest.'

The Conistan Asset - Heavy Sweet Crude
'The Coniston Project is a new subsea oil field development operated by Apache Corporation and located offshore Exmouth, Western Australia.

The project involves development of the Coniston and Novara oil fields using existing subsea infrastructure for the Quadrant-operated Van Gogh Field development. INPEX holds a 47.499 per cent interest in the Coniston Project.

First year production from the Coniston Field is projected to be around 21,500 barrels of oil per day. First production is planned for 2014.'

The Ravensworth Asset - Pyrenees Project - Heavy Sweet Crude
'Crude oil production from the Ravensworth field, about 45 kilometres off the coast of Exmouth, Western Australia, commenced in 2010.

INPEX holds a 28.5 per cent participating interest in the BHP Billiton-operated development.

The three Pyrenees fields, namely Crosby, Ravensworth and Stickle, were discovered in permit area WA-12-R in July 2003. The fields are estimated to have recoverable reserves between 80MMbbl and 120MMbbl of oil. Long horizontal wells have been drilled to develop the fields, which are tied to the Pyrenees FPSO by an extensive gathering system.'

hTTps://www.inpex.co.jp/english/news/pdf/2015/e20150511.pdf

Edit - Current combined oil production attributable to Inpex from these assets is circa 15,000 bopd according to latest Impex Corporate Brochure

IMO 2020 low sulphur fuel regulations: In addition to the huge price premiums its generating to dated Brent for heavy sweet crude, this week the Saudi's provided the oil market with further evidence that the imminent introduction of these new shipping regulations to reduce air pollution, is now pushing up the price of light sweet(low sulphur) crude oil grades too.

Saudi Aramco raised December pricing for sales of its light oil grades to Asia to their highest level since 2014 on Monday, just a day after they announced they would go ahead with their long-awaited initial public offering. The shipments will arrive in the region just as the IMO 2020 rules take effect.

“The transition to the world of low-sulphur fuels is already underway,” said Senthil Kumaran, a senior oil analyst at FGE in Singapore. “Saudi Arabia’s pricing is a reflection of the estimated uptake in consumption of these lighter crudes.”

Arab Extra Light’s premium over Arab Heavy ballooned to $4.65 a barrel for December sales to Asia - a more than $3 premium to dated Brent according to data compiled by Bloomberg. That’s $2 more than November sales and $3.65 more than September sales pricing.

Average sea passage times for oil cargoes bought and loaded FOB from Saudi Arabia to the ship bunkering hubs at Singapore and Shanghai is 16 and 21 days respectively. Saudi oil purchases will generate at least 10 days more ship charter/fuel costs for the buyers compared to much lower sulphur content NW Australian sourced light sweet crude production like Montara.

Montara: 0.05% Sulphur content and 34.9 API
Arab Extra Light - 1.09% Sulphur content and 39.9 API

Ship Bunker Pricing - Marine Gas Oil(MGO) and LSFO has been trading at average premium of circa $250/tonne($41.6 a bbl) and circa $200/tonne ($33.3/bbl) respectively to HSFO and Brent over the last month.

Global average pricing according to Ship & Bunker website data is currently:

$691/tonne - $115/bbl - MGO
$641/tonne - $107/bbl - LSFO
$395/tonne - $63/bbl - HSFO
$395/tonne - $63/bbl - Brent

So, it would appear that even when paying a premium to Brent of more than $16 a bbl for Australian Heavy Sweet Crude, the potential operating margin for Asian oil industry processors supplying the shipping industry with LSFO is highly material, considering LSFO is currently trading at a $44/bbl premium to Brent/HSFO, and Australian heavy sweet crude requires only blending with other feedstocks to create the most profitable LSFO specification for IMO 2020 purposes, rather than expensive refining.

Nine large buys totalling 2.25 million shares (circa £0.5 million) from yesterday morning just printed

"We are known in Peru as PetroTal, the company lead and operated by Peruvians - the message carries a lot of weight among the politicians and the people" - PetroTal CEO
With Resource Nationalism on the rise globally, this is a superb piece of public relations !

Where the heavy, sweet crude oil market is concerned - the IMO 2020 low sulphur fuel regs has flipped the oil market on its head, turning the former ugly duckling into a swan.

And as with the property business, price is determined by Location, Location, Location.

With the expected covert introduction of slow steaming by the global shipping fleet post the introduction of the IMO 2020 fuel regs, to materially offset some of the increased fuel cost(while cynically getting the shippers/consumers to pay the full increase via the BAF/Bunker Adjustment Factor surcharge - never underestimate ship owners propensity for using a major industry change to profiteer!), Jadestone Energy could sell and load an oil cargo from its Australian Stag Field FPSO into a shuttle tanker nearly a month AFTER a West African heavy sweet cargo was bought, loaded into a VLCC and departed for Singapore, and still have the Jadestone cargo arrive at Singapore and unloaded into storage BEFORE the ship carrying the West African cargo had even arrived at the anchorage off Singapore.