Subject: 2 Upstream Reports: Regime Shift For East Timor's Oil
also: Upstream: Mixed bag in quest to tap into resources
June 29, 2007
Regime shift for East Timor's oil
By Russell Searancke
Two upstream bodies to come under umbrella of new agency
Timor Leste (East Timor) is full swing into the streamlining of its petroleum regulatory regime and the establishment of a national oil company.
The main feature of the regime shift is that there will be a single regulator serving the country's upstream and downstream interests.
East Timor currently has two upstream regulators and no downstream body.
The country's exclusive onshore and offshore oil and gas business is administered by the National Directorate of Oil & Gas (DNPG), which is a division of the Ministry of Natural Resources and is led by Amandio Soares.
The second regulator is the much-larger Timor Sea Designated Authority (TSDA), which administers all oil and gas activity in the offshore zone shared by East Timor and Australia.
Both upstream agencies will disappear, in name, to form the new National Petroleum Regulatory Authority (NPRA), which is scheduled to be operational by the end of 2007.
The transition is designed to be smooth and there will be no job losses, said sources. All the existing workers in both organisations will be employed in the NPRA.
As many Timorese as possible will be employed, with some expatriates likely to be involved in advisory roles.
The TSDA has developed a lot of expertise since it was established four years ago. The executive director of the TSDA, Jose Lobato, said previously: "The TSDA has made it a policy to employ and train Timor-Leste nationals for all positions."
As at February 2007, it employed 43 people of whom 31 were from East Timor. The TSDA was initially based in Darwin, Northern Territory, and had more expatriates than Timorese staff. In December 2006, the TSDA shifted all operations to the Timoprese capital Dili.
The change of office location, and the regulatory transformation were stipulated in the Timor Sea Treaty, which was signed by the two countries in 2002.
Under the treaty, East Timor receives 90% of the petroleum taxation revenue from any oil and gas production in the shared joint petroleum development area.
There are two producing projects in the area - ConocoPhillips' Bayu-Undan and Elang-Kakatua.
The TSDA also sharpened its skills by establishing a new financial and legal framework for the joint petroleum development area, and in a 2006 licensing round awarded exploration blocks to a Petronas-led consortium including Korea Gas Corporation, Samsung Corporation, and LG International; an Oilex-led group including Bharat Petroleum Corporation, Videocon Industries and Gujarat State Petroleum Corporation; and blocks to Zetex and Minza Oil.
The other upstream body, DNPG, has about 10 staff, said sources, but its workload and capability have increased in line with last year's inaugural licensing round in its exclusive offshore areas and subsequent awards to Eni and Reliance.
The new regulator was originally due to be operational on 2 April 2006, but there were in-country delays including last year's civil unrest and this year's presidential and national elections.
The TSDA's mandate will be extended imminently to 2 January 2008, at which time the new body will be ready, said sources.
Meanwhile, planning for a national oil company called PetroTil is still in its infancy, said sources. Initially, the state-owned company will participate in upstream and downstream joint ventures, and will hold the state's equity in these projects. In the longer term, it will develop operational abilities.
Upstream (Norway) June 29, 2007
Mixed bag in quest to tap into resources
Some of the Timor Sea's marginal oilfields are finally being developed after years of hibernation, but the area's large undeveloped gas fields are years from production, writes Russell Searancke.
The Bonaparte basin hosts all the Timor Sea's known discoveries. In the west of the basin is the geologically-complex Vulcan sub-basin that contains the producing Jabiru-Challis fields and many small discoveries.
Different operators have tried without success in the past to develop small oilfields in the Vulcan such as Audacious-Tenacious, Montara, Puffin and Talbot.
Thanks to higher oil prices, those fields have become more viable, and AED and Coogee are developing the Puffin and Montara oil projects, respectively.
Both companies are building new floating production, storage and offloading vessels in Singapore, with first oil expected from Puffin later this year, and from Montara in the third quarter of 2008.
AED and Coogee are, not surprisingly, bullish about their expansion potential in the Vulcan.
AED's only asset was Puffin until it bought the Talbot oilfield from Apache last month. AED said Talbot was identified as an opportunity "to expand its regional operations".
Coogee is the biggest player in the Vulcan. It already operates Jabiru-Challis, and has interesting plans for its gas reserves in the Vulcan. Coogee intends to put the world's first methanol FPSO into operation in 2013 with methanol output capacity of 1.3 million tonnes per annum.
The company has 800 billion cubic feet of contingent gas reserves at the Montara, Biliara, Tahbilk, Pathaway and Cash-Maple gas fields in the Vulcan, and would use the FPSO to commercialise this gas.
For Coogee, this is not pie-in-the-sky thinking. The company's parent Coogee Chemicals owns an onshore methanol plant in Laverton, Victoria.
Coogee says its methanol heritage, and all the design work it has done, makes it very optimistic about the methanol FPSO project.
Pre-front-end engineering and design is planned to start in late 2007.
Other operators in the Vulcan include Eni, which owns the Vesta oilfield, and OMV, which owns the Katandra, Audacious and Tenacious oilfields. Both companies are still firming up their reserves, but there is optimism that one or both operators will commit to a commercial project.
Just south of the Vulcan is the large Crux wet gas field where the operator Nexus Energy is moving forward with a FPSO project to develop the field's condensate. Shell has bought the Crux gas reserves and will develop that after Nexus completes its liquids scheme, which is expected to start-up in the second quarter of 2010.
BHP Billiton discovered the Argus gas field in 2000. The find has an estimated resource of 1.5 trillion cubic feet of gas, and BHP is required to drill an appraisal well in 2009.
In the central part of the Timor Sea is the East Timor-Australia joint petroleum development area, which contains the Bayu-Undan wet gas field and the huge Greater Sunrise discoveries.
Despite the breakthrough political agreements in early 2007 by East Timor and Australia on the Sunrise project, there are major challenges still to be met for the Woodside-led joint venture, not least of which is East Timor's claim to in-country gas processing.
Moving south-east of the Joint Petroleum Development Area are ConocoPhillips' big Caldita and Barossa gas finds and Santos' Evans Shoal gas field, but high levels of carbon dioxide in the reservoirs provide questions rather than answers.
A publicly-listed company called MEO Australia has peddled a scheme to use high CO2 gas as feedstock for its proposed Tassie Shoal methanol project.
MEO has been unable to secure feedstock gas so it is drilling its own wells this year with the jack-up West Atlas near the Evans Shoal field.
MEO says its methanol plant will target poorer- quality CO2 gas that is often found in the Bonaparte basin, and requires 1.3 Tcf of gas to operate for 20 years.
ConocoPhillips is eager to proceed with an expansion of its Darwin LNG plant, and is looking at Caldita and Barossa as possible feedstock.
Meanwhile, momentum is building in the shallow-water areas near the coast of Northern Territory, where Eni is developing the Blacktip gas field to supply into the domestic gas market from 1 January 2009.
------------------------------------------ Joyo Indonesia News Service