catching up, page-21

Happy New Year MEOmites.

Let's hope it fulfils the promise for which we have long awaited.

You have had a couple of questions greymatter which I can address with my observations.

Heron

Regarding the drilling of Heron 3, which may be the first this year, I have put my ideas forward and cross referenced to take advantage of Ya's expertise. There is no point repeating it again because my thoughts have not changed but, of course, Eni may have different ideas. My conclusions are from previous data published by MEO.

* The thread is here *

Tassie Shoal

Regarding the value TS to MEO and the potential break up I think it is quite a complex matter and warrants further discussion in these threads.

Whilst I have been away from the HC threads I have been thinking about the future of TS and the events that have taken place over the last few months.

It has always been about the stranded gas in the Timor Sea, which is generally high in CO2, and where to process it.

I have always followed the commentary published by MEO that gas fields high in CO2 are only suitable for Methanol production. Perhaps this has led to my tunnel vision which is not true to character. The economics involved in processing the stripped CO2 through venting (Carbon Tax?) or geosequestration is prohibitive. The cost of the latter is discussed in an environmental paper published back in 2001/2:

* It can be found here *

It is an interesting read but pages 6 & 7 covers:

'section 5 - The technical fix? – carbon dioxide sequestration'

At the time Statoil was the only company re-injecting oil back into an aquifer as noted:

'Currently, only one company, Norwegian-owned Statoil, stores supercompressed CO2 from its natural gas operations underground in the North Sea. Statoil spent $80 million on the separation and disposal facility and has been re-injecting 1 MT of CO2 per year into an aquifer 1km below the seafloor (Monastersky 1999). The International Energy Agency has estimated that aquifers worldwide could accommodate 350 years worth of emissions at present rates (Monastersky 1999).'

At the time Methanol Australia's input (now MEO Australia) and ConocoPhillip (Darwin LNG plant solution for the Bayu Undan field) was to say:

Phillips argued that no suitable structures for CO2 re-injection were found in the vicinity of its potential platform sites in the Timor Sea. The closest would be 10km away and there was a risk that this would not seal properly. Moreover, the ocean was too shallow to prevent re-emergence and biological impacts. It also cited prohibitive costs as a reason for not pursuing this option. Current cost predictions by the APCRC are in the range of $10 to $25 for each tonne of CO2 disposed of (The Parliament of the Commonwealth of Australia 2001). Similarly, Methanol Australia’s EIS Consultant explained that this option would make the Tassie Shoal plant uncompetitive relative to developing country producers. He estimated that the disposal facility would cost $100 million to construct and $10 million a year to operate (presentation to NT Chamber of Industry & Commerce, Darwin 17/8/01). Woodside, in its PER for the NW Shelf LNG facility expansion also rejected the ocean disposal option for CO2 separated off during the liquefaction process (Woodside 1998). It acknowledged that this was technically feasible but said it would add an economically prohibitive 10-20% extra onto the total project cost. However, the company has incorporated some gas re-injection technology on a couple of its offshore oil and gas sites and claims that this will save an overall amount of 12 MT of CO2-e(www.woodside.com.au).

Since this, out of all the planned LNG and Methanol projects listed on P1, only COP's Wickham Point 3.24MTPA LNG plant has gone ahead.

Woodside's processing of Greater Sunrise gas at the proposed Glyde Point plant is in limbo. Methanex (x2) and GTL's proposal for a shore based Methanol plant have fallen through. Santos' solution for the Barossa/Caldita field is to pipe the gas to Darwin to feed a possible increased capacity Wickham Plant. This contradicts COP's desire to sell its share of the same field, even though they have put restrictions on the sale:

* See this article here*

In the mean time, along comes Eni with big ambitions for gas in the area. The first play was for Barossa/Caldita but the restrictions put on the requirement by Conoco for the gas to be processed at Wickham did not suit them.

Next was Magellan's failed aspirations to buy STO's share of Evan's Shoal which left the way open for Eni. At the same time they farmed in to MEO's NT/P68. MEO originally wanted to keep Heron and Blackwood separate but Eni insisted on an option for both fields.

So it is obvious that Eni is gathering as much gas in the area as they can but apart from Heron (potentially) all are high CO2.

So to get to the point I am making. Tassie Shoal, as we understand it, is:

TSLNG - 3.0 Mtpa LNG plant [Granted 2004]; and
TSMP - 2 x 1.75 Mtpa Methanol trains [Granted 2002]

* ref. MEO website - Tassie Shoal projects*

Perhaps Eni are not concerned about the high CO2 and that the whole concept of Tassie Shoal could change from a combination of LNG and Methanol processing to a majority LNG processing and methanol may even be put on the backburner. Enis seismic activity around Blackwood East may be not only to determine the extent of Blackwood but identify areas suitable for geosequestration as they would have a lot of CO2 to bury or vent.

This would explain the dispatch of Air Products to create a clean slate for open negotiation. The Tassie Shoal hub could make unitisation more attractive. Also, with the TS LNG hub in place it would give another option for other permit holders in the area (Sunrise/Barossa etc) who may even be brought to the negotiating table by choice or through the use it or lose it policy.

On the MEO TS project page we can see that:

'MEO received Major Project Facilitation status from the Commonwealth Government in 2007 and refreshed in 2009 for TSMP and TSLNG

From this we can assume that the MPF needs to be renewed on a two year basis so it is probably in the process of renewal. Also, if there are adjustments to the configuration of TS then this will need to be lodged for Environment approvals.

Also a clue to a shift in concept may be included in the statement:

'TSLNG enables LNG production from low CO2 or stripped CO2 source gas, in a region where significant LNG size resources exist.

But first things first. We need to look at H3 and B2 to see if Eni will act on their P68 options. If successful, from there we will be taken to FID with a one off payment of $75m.

MEO will still have 25% of the gas which will, no doubt, be processed at TS. How much TS is worth to MEO is problematic and a little beyond me until it is know what exactly will happen there and who will be involved in the final setup. MEO hold 100% and are in the box seat. Perhaps they will be left with 25% share in that also but they have shown in the past that they are able to negotiate deals with little cost to SHs whilst adding value.

Majors only seem to look at LNG as a viable export whilst Methanol is a distant poor cousin. Maybe ENI has put an alternative scenario to its new P48 partners who have always shied away from the Methanol solution. This may also rub off onto Woodside (Sunrise) and Santos (Caldita/Barossa).

If H3 and B3 have recoverable gas in the expected quantities, regardless of quality, third party gas may not be needed for TS.

Seruway PSC

The other major interest this year will be the 2H well in Seruway.

* ref. MEO website - North Sumatra Exploration *

I have been keeping an eye on the Arun LNG plant which is presently operated by ExxonMobil (30%) with PT Pertamina 55% and a Japanese group owning 15 percent.

XOM are currently in the process of selling their share:

* ref. Jakarta Post article *

Whilst Pertina are looking to convert the plant to a: 'receiving-and-re-gasification terminal'. It appears that this plan is in limbo:

* ref. another Jakarta Post article *

The conversion will depend on the aspirations of the buyer and new operator, if XOM can find one.

MEO has just completed 708km2 3D seismic prior to selecting a site and drilling. It will be interesting to see if MEO can follow the usual path of attracting a major farmin partner and if that partner is interested in the XOMs Arun share.

Whichever way it goes it will be a win, win situation for MEO. To continue as an export facility the LNG plant will be useful to MEO. As an import facility the gas price to the local producers will rise and the Seruway gas will compete favourably in the local market against expensive LNG imports.

I think MEO management have continued to strengthen the foundation blocks and it will be interesting to see what is built from here.

As far as the SP goes, once the herd realise the potential of the company then it will be back to the rollercoaster and it will be up to each investor/trader to decide how to ride it.

IMO

Please DYOR

#:>))