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A record high premium of more than $16 to dated Brent paid for the latest sale of a cargo of Australian Pyrenees heavy sweet crude!

As alluded to previously, spot premiums of Australian heavy sweet crude are being strongly bid by Asian buyers as they compete to secure cargoes of short-haul Australian production, following the huge spike in vessel charter rates adversely impacting the attraction/pricing of long haul West African production.

Australia's BHP sells December Pyrenees crude at record high premium - Reuters

'SINGAPORE, Nov 1

* Australia’s BHP Group Plc has sold a cargo of December-loading Pyrenees crude at a record-high premium of above $16 a barrel to dated Brent via a spot tender, two trade sources said on Friday

* The loading date for the 550,000-barrel cargo is Dec. 17-21

* The buyer of the cargo was not immediately known

* 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

* Spot premiums for December-loading regional crude cargoes have shot up as Asian buyers snapped up short-haul supplies after freight rates jumped

* Prior to this, Pyrenees crude traded at premiums of about $13-$14 a barrel to dated Brent, traders said. '

What a difference a year and the build up to the IMO 2020 Marine fuel sulphur-content regulation change has made for Australian Heavy Sweet Oil Producers.

Australian heavy sweet crude grades, such as Pyrenees, Van Gogh, Stag and Wandoo, have been snapped up by the market ahead of IMO 2020; reflected in the record high premiums they're currently attracting.

These grades have been actively flowing into the floating storage VLCCs off Singapore, as well as into regional onshore storage terminals, in volumes more than 15 times greater than observed in previous years - (85% of all Australian heavy sweet crude production has gone into floating or land based storage in SE Asia/Middle East).

Close to 4.4 million bbls of Australian heavy sweet crude (Pyrenees, Van Gogh, Wandoo and Stag grades) were observed by Vortexa delivered into floating storage vessels anchored off Singapore between January to July this year, representing some 60% of Australia’s heavy sweet crude exports.

Another 2.0 million bbls of these grades (or 25% of heavy sweet exports) were discharged into land based storage terminals in key bunkering hubs in Singapore, Malaysia and Fujairah over the same period.

This contrasts with only 0.42 million bbls of similar grades observed being delivered into floating storage, and none into land storage terminals, in the same period last year.

Asia-Pacific refineries with secondary upgrading units had previously been the primary buyers of Australian heavy sweet crude, but have shied away this year as a result of the high price premiums.

Other crude grades considered by Singaporean and Asian processors for LSFO blending include West African grades? Doba? and ?Yombo.

Just over a year ago, Australian heavy sweet grades were sold at between parity to around a $1.50/bbl premium over Dated Brent. Overwhelming demand for these grades - whose availability is strictly limited - has seen the prices surge materially this year, to currently trade at a record high of $10-14/bl premiums over the Brent benchmark.

With an average of 0.23% sulphur and more than 50% residue content, Australian heavy sweet crude grades are ideal for blending with high sulphur fuel oil (HSFO) to produce 0.5% low sulphur fuel oil (LSFO).

Until the recent 10 fold spike in VLCC charter rates as a result of the US embargo on the Chinese Costco VLCC fleet for oil smuggling on behalf of Iranian interests, expectations of higher LSFO prices in 2020 were encouraging Singaporean and Asian refiners and traders to buy and store increasing volumes(at considerable cost in expensive VLCC's) off Singapore, ahead of January 2020.

Data from Lloyd's List and Vortex Energy Market Intelligence.

IMO 2020 - Container ship giant Maersk has provisionally set their BAF(Bunker Adjustment Factor) price based on a LSFO price set at a $50 discount to Marine Gas Oil(MGO) pricing, until the new market for LSFO stabilises during 2020.

At the largest 20 global ports, MGO has an average price of $643/tonne which currently is a $274/tonne premium( $37.5/bbl) to HSFO pricing.

So, Maersk's BAF today will be based on LSFO priced at a $224/tonne($31/bbl) premium to HSFO.

There does appear to be some confusion/misunderstanding among a surprising number of the analysts and commentators discussing the impact of the IMO 2020 Fuel Regs, with respect to the terms LSFO and VLSFO. The former is the new marine fuel oil grade(0.5% Sulphur Content) that the overwhelming majority of the global shipping fleet will soon operate on under the IMO 2020 Low Sulphur Fuel Regulations, while VLSFO is the fuel oil(0.1% Sulphur Content) that has been widely used by the Cruise Ship and Ferry Industry for many years.

Montara's production has a sulphur content of just 0.05%, while Stag's 0.17% sulphur content is the lowest by some margin of the Australian heavy sweet crude oil producers.

Of the very small number of global producers of heavy sweet crude (collective production of circa 1 million bpd - with circa 0.75 million bpd produced in West Africa), Stag's production has the lowest sulphur content I have come across and is 7,000 miles closer to the World's largest ship bunkering terminals than at least 75% of the global production of heavy sweet crude oil.

IMO 2020 - in a new report S&P Global Platts looks at the impact of IMO 2020 low sulphur fuel regs on the global oil refinery industry and crude oil pricing:

IMO 2020 - Disruptive changes to the global oil and refining industry beckon - S&P Global Platts

'Global ship bunker specification changes in 2020 require a large scale shift in refinery operations and will be very disruptive, both within the industry and more widely.

From a refinery standpoint, there will be a major switch in the blendstocks used for bunker fuels, creating a demand shift of 3.0 million bpd from HSFO to LSFO/MGO.

Prices for MGO and the new blended LSFO are expected to rise sharply while the price of HSFO will fall.

Relatively expensive steps will be required throughout the refining circuit to rebalance products, resulting in much wider spreads for all middle distillates compared with HSFO.

At times in 2020, the refining circuit may need to run additional crude to make sufficient compliant marine fuel. Diesel and jet cracks will soar. Gasoline cracks may also see support, as yields shift towards middle distillates.

The price of the new LSFO will initially be close to MGO.

Refinery operations, crude oil and product trade flows will change dramatically.

Key refining implications:

* High crude runs in 2020 and a broader set of refineries seeking light sweet crude.

* Bullish market sentiment for light sweet crude is likely to drive overall prices higher for key sweet benchmarks, such as Brent and WTI, with price rises of as much as $7.0/bbl in 2020.

* Middle distillate cracks will increase sharply in 2020 before gently easing during 2021-2023.'

Late October Update:

'Jadestone’s net debt turned net cash positive in Q2 2019, one quarter earlier than expected'

Stag
* Crude premium on Q3/Aug lifting: Brent + US$10.60/bbl
* 37H and 44H pump change-out and 43H casing repair and pump change-out completed in Q3 2019
* 49H Infill Well - results met or exceeded pre-drill expectations - 2P reserves expected to be 1.2mm barrels, per the pre-drill expectation.

Montara
On track to deliver value up to 3 times the $195 million acquisition cost, which was:
* Less than $7.0 per bbl 2P reserves / $19,000 per flowing bbl
(On completion this was $3.2 per bbl 2P reserves / $8,200 per flowing bbl, after cash adjustments for Jan-Sept 2018 oil sales and field shutdown compensation)

Nam Du/U Minh — 'high-margin Vietnam gas resource' - Project progress:
On schedule for development sanction this year with first gas in 2021
FPSO - Vessel to be leased (avoids huge additional pre-production Capex)
GSA - structure of gas sales price formula agreed - Long term, fixed price, fixed escalation, and high take-or-pay volume, offsetting oil price volatility

Well-head gas pricing in Vietnam($/mmbtu) v Imported LNG
$7-8 - Recently executed GSA's (circa 3 times US spot rate over past 24 months)
$9 - Proposed Developments presently under HOA
$10-$12 - Imported LNG (requires a circa $2bn Import Terminal, Storage and Re-gasification Facility)

2019 - Free Cash Flow Forecast - some thoughts on the impact of the August advised adjustments to production guidance, oil sales premium and Capex.

Management commenced the year offering the following guidance -
14,500 bopd - Mid range production guidance
$21-24 /bbl - OPEX
$2 /bbl - average oil sales premium to Brent
$72/bbl hedge on circa 5,250 bbl of Montara production
$130 million - Capital Expenditure
Generating: circa $100 million Free Cash Flow @ $65 Brent

Revised Forecast after mid year advised adjustment to production guidance, oil sales premium and Capex
14,000 bopd - revised Mid range production guidance (from 14,500 bopd)
$21-24 bbl - OPEX
$5 /bbl - average oil sale premium to Brent (range of $4-6 /bbl)
$72/bbl hedge on 5,250 bbl of Montara production
$80 million - Capital Expenditure (first Montara Infill well moved to H1/2020)
Generating: circa $161 million Free Cash Flow @ $65 Brent (average to date $68.0)

$50m raised at 56p / 131m shares in issue.
$36m at 38p / 175m shares in issue.
$40m at 38p / 273m shares in issue.
$125m at 35p / 817m shares in issue.
$23m at 28p / 879m shares in issue.

Savannah has raised a total of $274 million overwhelmingly from a broad range of high quality institutional investors.

It's important to bear in mind that the average price of their combined holdings acquired from these placings is 39.07p - from today the s/p would have to increase by 70% JUST to get to their collective BREAK EVEN!

Jadestone's Vietnam assets are in the undisputed waters of the Gulf of Thailand NOT the waters of Vietnam's Exclusive Economic Zone extending 200 nautical miles out into the South China Sea that is currently disputed by the Chinese.

Major shareholder the high performing hedge fund Livermore Partners reported outstanding Q2/2019 and YTD Results this week: +40.4% Q2 / +78.46% YTD
JSE mentioned in the results report:

'Jadestone Energy - a large holding of the fund and one that we continue to watch grow and mature. The equity has been on a tear since its 2018 IPO (up more than 50%) in London and has continued into Q2.

Jadestone is unique and well-positioned given its strong free-cash flows, FCF yield, and management team. The newly acquired Montara asset has already shown strong signs of asset rationalisation with major upside to boot.

JSE management, led by Paul Blakeley, recently provided guidance of 13-15,000 BPD of production for Jadestone in 2019, with the potential for further bolt-on acquisitions to further strengthen the asset mix and leverage cash flows.

We continue to be supportive and feel Jadestone can become a solid $1B company oil producer with scale.'

Aside from Jadestone the Livermore Fund has major positions in pharma firm Akorn, Torex Gold and FerrExpo and a short in Tesla.

IMO 2020 - the new Shipping Low Sulphur Fuel Regulations will be the most pronounced regulatory change to hit the shipping and oil refining industry in decades.

The US Energy Information Administration said in report in March that the shift in petroleum product pricing may begin as early as mid-to-late 2019, with the effects on pricing to be most acute in 2020.

The average spot price for LSFO could rise circa 20% in the second half of this year and above that level in 2020, according to IHS Market's base forecast.

In the run up to and following the implementation of the IMO low sulphur fuel regs in Jan 2020, low sulphur crude oil such as Jadestone's Stag and Montara production, is likely to command a material long term premium over other crude grades, in ADDITION to the regional SE Asian market premium.

https://www.visualcapitalist.com/imo-2020-the-big-shipping-shake-up/

* Skua 11 Intervention - opening up the heel to target oil from a crestal location

(Jadestone ran a simulation case with and without Infill Well Skua-12 to estimate the incremental recovery from the well. For the no infill well case, the recovery of Wells Skua-10ST2 and Skua-11 in the simulation model (6.9 MMstb) was higher than remaining recoverable oil estimated using DCA by 1.7 MMstb. Jadestone interpreted this higher oil production as the model optimistically producing more oil from the crestal location of Well Skua-12. 'Therefore, the case including Skua-12 infill is likely conservative')

* Swift and Swallow - have 3 production wells - due to technical issues two have been shut-in since 2016(the oil cycle low)

(Both require well interventions before re-commencing production. Since these are subsea wells, this will require an intervention vessel to be mobilised for the well activities - recoverable volumes associated with these wells have been classified as Developed Non- Producing. June 2019 LWI programme is targeting the high performing Skua 2).

* Montara and the birds had 2018 budgeted op expenses of $109.5m - the field averaged circa 7,500 bopd at "much, much less than the historic 72% uptime" - suggesting circa $40.1/bbl.

(Jadestone is forecasting average op expenses of circa $20/bbl for Montara and the birds in 2019 - achieved through increasing field uptime to 83%, production/well optimisation, the riserless subsea light well intervention and direct influence over field operations with the move toward transfer of operatorship in Q2/2019.)

Some data/information on the Montara and the Bird Fields from my research notes - source: mainly the July 2018 CPR carried out by ERCE - and the ongoing impact since of the production/well optimisation work programme and, Field and FPSO shutdown maintenance work.

* The combined current (July 2018) oil production rate for the Montara Assets is approximately 13,750 stb/d - 7,100 bopd from Montara and 6,650 bops from the birds.

* Each Montara well drilled initially produced at rates between 3,000 and 4,000 bopd

* Peak oil production of 15,030 bopd was achieved in December 2014.

* Montara H5 - came on at 3,500 bopd in October 2017

* The Montara Field(minus the birds) produced 12.57 million bbls by end 2017 - an average production rate since first oil in June 2013 of 7,652 bopd. During this period the Montara field uptime averaged 72%.

(Interestingly, some 5 years after first production the Montara field is still producing at a rate similar to the average production figure for the field since first oil of 7,652 bopd)

* The Montara H5 came on production in October 2017 and by July 2018 production is yet to show evidence of any decline. Therefore, Jadestone has used a full-field simulation model to guide oil recovery and the production forecast for this well.

(Recovery from Well H5 in the simulation model (8.0 MMstb) was higher than the Estimated Ultimate Recovery of the other wells in the field. This is supported by Well H5 being located in a flatter area of the field with less exposure to the aquifer. In addition, the location of Well H5 is a “step-out” into an un-drained area of the field, rather than an infill well.

However, Jadestone elected to conservatively consider the higher recovery from this well compared to the EUR of the other wells in the field as an uncertainty, and has discounted the production forecast so that Well H5 recovers similar oil volumes to the other producing wells (6.8 MMstb).)

* Historical downtime on the Montara project has been variable, with an average of 28% over the past five years. This has been due to the downhole well problems on Wells Swift-2 and Skua-11. Additionally, there have been topsides issues with gas compressor reliability, process trips and slugging.

(Jadestone is currently resolving the downhole well issue using an intervention vessel. A compressor review has been carried out and stocking of critical spares increased, while topsides process parameters have been adjusted to reduce the number of trips, together with the installation of a slug control system.

PTTEP previously had a 21-day annual shutdown, mainly for FPSO inspection. Jadestone plans to change this to a 14-day shutdown every two years. Jadestone has assumed downtime of 10% for the Montara platform wells, and a higher 20% for the subsea tie-back wells. This combined with the bi-annual shutdown is equivalent to a long-term average annual downtime of 17%(83% uptime) - Montara and the Birds are currently averagi

......we’ve made some clever changes at the facility which have allowed these wells to keep producing. So it’s not quite right to see all 3,200 as truly incremental. Rather, about 2,000 bbls/d would be in service of protecting existing production, and the remainder being the true incremental portion. A good problem to have!'

Skua 11 Heel - did the Thai’s give a reason as to why they inexplicably elected to just produce from the toe and leave the heel effectively shut-in for over a decade, following the failure of the Inflow Control Valve in 2008?

'Skua-11 heel - I can’t speak for PTTEP, but this sort of opportunity is exactly the sort of thing we look for in acquisitions - re-investment projects that are either not recognised, or not seen as material or feasible by the seller. We see it as a material, obvious, and relatively straight-forward from a technical standpoint. I can only surmise that they didn’t see it the same way. '

Ref the RLWI - Montara averaged circa 12,538 bopd after coming back on production during Q1/2019.

From the above answer: if we assume 2,000 bopd came from Skua-11 and Swift-2 due to the 'clever changes'(as suggested and subsequently identified by Spangle) - this suggests the production figure would otherwise have been circa 10,538 bopd in Q1/2019.

H2/2019 Production - the 3,500 bopd of incremental production attributed to the RLWI would suggest Jadestone is targeting circa 14,000 bopd from Montara post completion of the work. With H2 production from stag targeting circa 3,500 - 3,750 bopd range. (And the target of a further 3,000+ bopd from the first Montara Infill well in late Q4/2019)

Successful execution of the RLWI suggests a full year production figure towards the top end of the 13,500 - 15,500 bopd guidance is a realistic and achievable goal.

AIMHO/DYOR

Due to other commitments I was unable to listen live and participate in the Q&A section of the company webcast of the Q1/2019 presentation, and so forwarded some general questions to the company, which received a prompt reply:

I understand the Montara FPSO has an actual oil storage capacity of 900,000 bbls - why is the full storage capacity not being utilised and the average oil liftings from the FPSO a maximum of 500,000-550,000 bbls?

'Montara FPSO - It’s a big one! 900,000 bbls is a lot, and means not every offload tanker has capacity for it all, so depending on marketing arrangements, it has made sense (in our brief experience with Montara) to lift earlier. From a revenue recognition perspective, that’s probably not terrible, as it helps to smooth out some of the lumps in revenue recognition.'

Replacing end-of-life existing umbilical from subsea wells to FPSO:
* when is this scheduled to proceed ?
* how long will it take ?
* will it mean a total shutdown of production to carry out the work ?

'Umbilical replacement - We’re targeting end of June, but it could be into Q3. The work itself will take approximately 14 days, during which there’ll be about 4 days of downtime, definitely affecting the subsea wells and potentially the wellhead platform.'

Operatorship of Montara - the company submitted the application for the Transfer of Operator in late Q4/2018 and according to the authorising body, submissions usually take 3 months to process. Is the company still confident they will achieve the transfer during Q2/2019?

'Montara operatorship - Still targeting Q2 for this and no indications of major hiccups around getting it done, but timing is in the regulator’s court. '

Low Sulphur Crude Premium to Brent - ref: IMO 2020 latest premium to dated Brent of Pyrenees/Van Gogh blends reached the astonishing level of circa $15 this week - Jadestone’s last liftings achieved circa $4 - any insight on where you think the premia is currently for Jadestone’s production?

'Crude premiums - There’s been upward pressure on premiums for our type of crude; the new IMO regulations are having a ripple effect through the refining industry and stimulating more demand than we’ve previously seen. Realistically, I think the $4/bbl premium we’d previously offered as guidance can now probably be seen as a reasonable floor, but that’s about all we can say at this stage.'

Montara/ Satellite Field Light Well Intervention - in light of the slightly later commencement date pushing some of the work into Q3/2019, is the company still confident of delivering 3,200 bbls of incremental production in H2/2019?

'RLWI - There’s been no change to the scope of the project, and I still expect it will provide 3,200 bbls/d. That said, some of the bbls in that 3,200 were predicated on a couple key wells stopping production by now. I.e. we had assumed Skua-11 and Swift-2 would stop production without having gaslift available. As it happens, since the shutdown we’ve

For improved investment returns Jadestone is proving a good example of why its important to never be afraid to be ruthless, and cut loose previously high performing management unable to replicate earlier success.

The management of Talisman Energy and Venture Production developed their respective businesses to become two of the leading second phase operators in the North Sea during the recovery/boom stage (2000-2008) of the last oil market cycle.

Whereas the Management of Talisman Energy (North Sea) then went on to demonstrate this success was no fluke by starting Talisman Energy (SE Asia) and remarkably building that company from scratch into a $6bn turnover second phase oil field specialist operating in the SE Asia region during the far more challenging oil market decline/recession stage(2009-2016) - the Venture Management started Trinity E&P and by 2016 had almost took them under - only surviving by virtue of a fortuitous huge cash raise/massive shareholder dilution.

At the start of the new oil market cycle in 2016, two high performing activist US Hedge fund managers were so impressed with the incredible performance of Paul Blakely and his team at Talisman Energy in the North Sea and SE Asia over the previous 15 years; that when Repsol acquired Talisman Energy during 2016, as major shareholders/Board Members in Mitra Energy(Jadestone Energy) they removed the existing executive Board and headhunted Blakeley and his team to run the company - promising them the investment funds to replicate their Talisman business growth performance with Jadestone.

Considering the outstanding early progress Blakely and his team has made to date, it would take a brave investor to bet against them making it a three timer.

After putting investment funds to work with Trinity E&P in this new oil market cycle recovery stage it was disappointing to find that after nearly 2 years the investment was still at breakeven. Electing to move 75% of the TRIN investment into Jadestone last summer/autumn has seen it increase in value to 25p in Trinity s/p terms - a 100% return compared to leaving it in TRIN - and a similar return to that generated from another major portfolio holding in Touchstone (TXP) since summer 2017, also managed by a high performing CEO who generated similar investment returns to that achieved by Talisman and Venture during the previous market cycle recovery stage.

AIMHO/DYOR

Further to an earlier post which explored the potential downside protection to cash flow that the Montara oil price hedge provides at prices from the current circa $70.50 Brent(+ regional premium) down to $50.00 on mid guidance average production 14,500 bopd - a look at the cash flow upside potential at an average of $80 Brent(average price over the last 11 years) and $90 Brent. And what it could potentially generate should production hit 20,000 bopd during H1/2020 from the fully funded organic production development programme.

At 14,500 bopd 2019 production guidance, i estimate Jadestone's annual cash flow generation at $24/bbl opex(top of the 2019 guidance range) as:

At an average of:

$80.00 Brent - $302 million

$90.00 Brent - $361 million

2020 Cash Flow Potential @ an average 20,000 bopd and average opex of $17.5/bbl

At an average of

$70.50 Brent - $420 million

$80.00 Brent - $467 million

$90.00 Brent - $541 million

Increasing production through a largely fixed price operating infrastructure in a rising/higher oil price environment produces a double whammy effect - pushing up cash flow exponentially. Of course the same effect occurs in reverse should production fall in a rapidly falling oil price environment, as occurred to PTTEP when they were very inefficiently operating Montara during 2014-2017, to Jadestone's and its shareholders good fortune!

From the beginning of 2015 through to early 2018 Brent averaged circa $52; on what we know about Montara's historic production, opex and field uptime performance under PTTEP, the field almost certainly was cash flow negative for most of that time. In such circumstances its usually planned maintenance that becomes a casualty with a predictable knock on effect to field uptime performance, as evidenced by the H1/2018 performance when it fell to a figure "much, much lower than the 72% average figure(itself appallingly low) achieved between 2013 and 2017".

AIMHO/DYOR

Jadestone Energy's Stag Field oil grade is very similar to the premium price NW Australian Pyrenees heavy, sweet, low sulphur grade, while production from their Montara Field is a lighter grade than Stag, but very low sulphur - both commanded sales prices between circa $3.50 and $4.10 above Brent for the last liftings from the fields, as they are in high demand for blending with other grades of crude oil to produce low sulphur fuels compliant with the new IMO 2020 Shipping Rules.

Considering how pricing has increased for the two principle heavy NW Australian crude grades (recently up to a $9 premium to Brent) - it would not be surprising if the next Stag and Montara oil liftings generated a further increase in the sales price premium relative to Brent.

Shipping industry sites are now regularly carrying news on NW Australian oil price premiums/liftings - as a result of Australian low sulphur oil grades being in great demand in the run up to the introduction of the new IMO 2020 Shipping Rules - the Australian Pyrenees and Van Gogh oil grades are currently among the most expensive crude oils in the world.

Below are a couple of shipping sites that publish data on Australia crude oil liftings and pricing:

https://gcaptain.com/imo-2020-australia-crude-oil/

and

https://www.hellenicshippingnews.com/australias-santos-sells-june-van-gogh-crude-at-high-premium-sources/

Some thoughts on the impact to future gross revenue and cash flow generation of Jadestone's prescient October 2018 Oil Price Hedge and acquisition of the Montara Oil Field.

As CEO Paul Blakeley made reference to in a recent company presentation to investors, the timing and exceptional quality of the Montara deal and its associated 2 year oil price hedge arrangement written into the contract to part finance the acquisition, is proving to be hugely "fortuitous" to the company and its shareholders.

Today, with Brent at circa $70.5/bbl - Jadestone will be getting around $76/bbl with the regional premium to Brent for its hedged volume(5,500 bpd), and circa $74.00 for the remainder of the Montara production - giving an average of circa $75.00/bbl for all Montara's production.

Stag will be generating around $74.50/bbl inclusive of the regional premium to Brent.

Giving an overall sales price average of around $74.80/bbl - suggesting current cash flow generation is likely to be circa $50/bbl.

At the mid 14,500 bopd 2019 production guidance level and an average of today's $70.5 Brent price, Jadestone would see additional gross sales revenue of circa $25 million and $75 million annually, compared to North Sea and Trinidad and Tobago producers respectively.

At an average of $60 Brent the additional annual gross sales revenue would be $47 million and $88 million respectively.

At an average of $50 Brent the additional annual gross sale revenue against North Sea and T&T producers would be $78 million and $114 million respectively.

At 14,500 bopd 2019 guidance, together with the regional oil price premium and oil price hedge i would estimate Jadestone's annual cash flow generation at an estimated top end of the range $24/bbl operating expenses as:

At an average of:

$70.5 Brent - $270 million

$60.0 Brent - $239 million

$50.0 Brent - $217 million

The Montara oil price hedge deal over the next 18 months will clearly provide huge downside protection to cash flow generation should oil prices fall significantly during the remaining 17 months of the 2 year deal.

Any material increase in production above the 14,500 bopd mid guidance case would especially if the double whammy effect of an increase in the average price of Brent occurred - have the potential to deliver an exponential increase in cash flow generation above today's current estimate, since it would be going through a largely fixed price production operation, thereby lowering the opex and increasing the cash flow /bbl.

Against this backdrop, from an investment risk persecutive, it makes extremely good reading to know that Jadestone's 2019-2023 organic, self funding production development plan to 30,000 boepd is based on $50 Brent.

For us, the net $82 million price for the Montara oil field acquisition was an incredible deal when measured against virtually any asset value metric but, to find it included a young $108 million converted cost FPSO with up to 900,000 b

Jadestone does not need ramping - its Montara acquisition cash flow generation will do its talking.

Post the likely commencement of a dividend in H2/2019, I would still expect the overwhelming majority of the cash flow (90% plus) to continue funding more low development and operating cost organic production development and modestly managed acquisitions with existing cash flow and low cost production development potential.

Once of the huge attractions of operating in the SE Asian/NW Australia/Pacific Rim oil and gas basins as a second phase operator, is the region has generated all the global growth in oil(34 million bopd) and gas demand over the last 40 years and, this is forecast to continue over the decades ahead. Also, demand for the type of crude oil favoured by the refiners for blending purposes to meet the demands of the new IMO shipping regulations is expected to increase by an estimated 2.5-3.0 million bopd from Jan 2020 - consequently, a premium pricing to Brent (currently between $4 and $9) for the NW Australian offshore oil grades is likely to be with us for the foreseeable future.

The Trinidad and Tobago oil industry produces high quality light sweet grades that currently sell at a circa 14% sales discount to Brent ex the well head - or circa $15/bbl less than Jadestone currently generates for its NW Australian oil sales, which on our existing production is worth an extra circa $80 million a year in cash flow compared to T&T oil sales pricing.

Jadestone is not operating by chance in a premium price oil and gas region that generates all the global growth in demand, has limited competition for second phase high quality assets, and generally very benign offshore sea and weather conditions. The Jadestone management having operated highly successful businesses as second phase operators in both the North Sea and SE Asia during the last 20 years, chose NW Australia and SE Asia via Jadestone for their new business venture post the Talisman Energy buyout by Repsol - it would be fairly safe to assume its not because the climate there is much better.

It also comforting to have two very high performing activist US Hedge Funds now holding a combined third of the stock.