This article is extracted from PESGB Monthly Newsletter, September 2006 and republished with permission.
Recent Key Developments in SE Asia's Midstream — Indonesia:
A Nation in Transition
By Jeremy Bowden, IHS
Probably the most dramatic developments in Southeast Asia’s midstream energy environment over the past few years have been in Indonesia. These have included the removal of state Pertamina’s monopoly and the introduction of regulating bodies (BPH Migas, LE Migas and BP Migas); the country’s transition from a net oil exporter to a net importer; dramatic refined product subsidy cuts; and the recent adoption of a domestic gas utilization policy - mirroring that of peninsular Malaysia’s, but with a government regulator rather than an intermediate monopoly.
Transparency and legal issues remain, complicated by increased regional autonomy. But a more pragmatic central government, elected in late 2004, is increasingly flexible in dealing with potential investors; recognizing the importance of attracting overseas capital and expertise, particularly in the energy sector.
As domestic oil production declined, and international prices rose over the last few years, Indonesia’s hefty oil product subsidies threatened a financial meltdown last year, and led to refusals by Mid East crude suppliers to issue letters of credit while causing sharp fluctuations between the Rupiah and the U.S. dollar.
So, despite subsidy cuts being a highly controversial issue – they prompted the protests that led to the dictator Suharto’s downfall in 1998 – the government had little choice, and acted decisively last year, cutting subsidies sharply. Surprisingly, protests were very limited and the Rupiah recovered. Inflation has risen, forcing the government to raise interest rates at a time when cheap credit is needed to stimulate economic growth.
The refined product subsidy cuts have made gas a far more attractive fuel for the power and industrial sectors, which had relied extensively on subsidized oil. In addition, domestic use of gas is seen as a way of expanding the economy – which is growing at about 6%; a laggard by Asian standards - with relatively cheap and plentiful energy.
Relative Energy Prices in East Java (Retail), Jan. 2006
With many of Indonesia’s hydrocarbon basins being gas-dominant, the new gas policy is perhaps of most concern to potential and existing investors in the energy sector. Vice-President Joseph Kalla was quoted in a May issue of Singapore’s Straits Times as saying: “Up to now, almost all of our energy products like LNG (liquefied natural gas), coal and oil, are exported. But if, let's say, the Japanese need them…wouldn't it be more efficient if they were to build a factory in Indonesia? In the past, energy followed industries. But now, industries should follow energy.”
There is already plenty of Japanese investment in Indonesia, and this may be considered a naïve (and inaccurate) comment – after all, the industrial revolution began around the coalfields of Great Britain due to social, political and economic factors that encouraged innovation and investment; the location of the energy source was secondary.
Nevertheless, Mr. Kalla’s statement effectively expanded the scope of an earlier announcement by President Susilo Bambang Yudhoyono (known as SBY) to limit Indonesia's LNG exports. This now appears to be official central government policy. Indonesia is already failing dramatically to meet its contractual commitments to export LNG, particularly to Japan. It has cited technical problems, but other sources say the PSC operators are reluctant to further develop the fields due to uncertainties over the future market. IHS Energy’s production figures show sharp production declines in the fields feeding the main LNG plant, Bontang, but there is plenty of gas available nearby, both in developed fields and those yet to be brought onstream.
Pertamina’s president Ari W. Sumarno said in late June that the giant 20 MMt/yr Bontang plant in east Kalimantan will be unable to deliver 70 of the 322 cargoes contracted this year. Plans to add an extra 3 MMt/yr train have been postponed indefinitely. Despite scouring the market for spot cargo replacements, only four have been sourced, all from Qatar.
Ari reportedly also said that Pertamina had been hopeless at marketing Indonesia’s LNG: “We are hopeless. For next year on, we let BP Migas and gas producers to handle the marketing,” referring to upstream oil and gas regulatory body BP Migas, which gave Pertamina the marketing job in 2002.
In the case of the aging (1978), 12.25 MMt/yr Arun facility, the Exxonmobil fields which feed the liquefaction plant are depleting rapidly. Two LNG units totaling 6.15 MMt/yr have already been shut down, but there is still expected to be a 9 cargo shortfall from the remaining units this year. In addition, several companies, led by power supply monopoly PLN are planning three LNG import terminals on Java, but no LNG supply has been arranged for these regasification plants. Sources are skeptical they will be built.
Existing Northeast Asian buyers are unhappy, and considering legal action, but so far none has been taken, despite clear breaches of contract. Instead, the Japanese are turning to more reliable sources of LNG in the region, as many contracts with Indonesia come up for renewal in 2009.
In December it was decided that 25% of production from all future gas-field discoveries should go to the domestic Indonesian market. But reduction in LNG exports will also adversely affect Indonesia’s trade balance. The government is keen to reverse the decline in overseas investment in its electricity, oil and gas sectors, in order to meet domestic power and gas needs, and reestablish the country as net oil exporter, and revalidate its OPEC status.
Unfortunately for Indonesia the two objectives are incompatible – at least for gas - unless domestic gas prices rise substantially to near the level of that of feed gas supplied to LNG plants. In some cases this is happening, particularly for sales to industrial users, but all deals must be approved by mid/downstream domestic regulator BPH Migas. There will be fierce populist resistance to higher prices in areas such as fertilizer production and power generation, where loss-making state monopoly PLN can barely afford fuel at current levels unless electricity prices are raised substantially.
PLN has issued over twenty tenders inviting independent power producers to supply electricity to ensure further power shortages are avoided. But it has set a base power purchase agreement price at a very low 4.5cts/kWh. Field-mouth gas from easily developed fields can compete at this level, but such options are limited. Most tenders are likely to be awarded to China’s low-cost coal-fired power producers, at mine-mouth locations.
The far-from-clear domestic gas utilization policy and its resulting price risk are creating enormous uncertainty in the economics of developing known and to-be-found Indonesian gas fields. In addition, the need to develop an extensive pipeline network to transfer the gas from prospective basins to demand centers in Java, is far from complete and will add additional costs.
The biggest of these pipelines would be to transfer gas from East Kalimantan – near the site of Bontang - to central Java. The tender for the pipeline has been issued, along with tenders for gas pipelines linking east and west Java. Interest has been reported from Chevron and CNOOC, as well as domestic gas distributor and pipeline operator PGN, but the economics are uncertain. The tariff is estimated at around 90cts/Mcf, and with wholesale prices in Java currently near $3/MMbtu, this represents a far less attractive option than LNG sales.
Investers are clearly concerned. Total’s CEO, Thierry Demarest, told a press conference in Europe recently that Indonesia had other options for using the gas Total currently liquefies and transports as LNG from Bontang, primarily in the domestic market: "There are several possibilities with the gas resources existing in Indonesia, so to my knowledge it is a concept at this stage and there is not a clear orientation about from where these additional supplies for the domestic market will come," Demarest said in May, indicating the general confusion over policy.
Total is Indonesia’s biggest gas producer, delivering around 2.6 Bcf/d to the Bontang plant. The other suppliers to Bontang are Chevron Corp (previously Unocal assets) and Vico Indonesia. Vico's shareholders include BP and Eni. Together they supply about 800 MMcf/d of gas. Chevron has already announced its intention to farm out acreage it acquired from Unocal in the area.
West Indonesia's Planned and Existing Pipelines
Chevron also declined an offer of dramatically improved fiscal terms to take a stake in the A1 field offshore Aceh in north Sumatra, although some reports say it is reconsidering that offer. The field could feed gas to the Arun LNG plant, helping to mitigate the declining supply from ExxonMobil-operated fields.
But it is more likely that the government will bow to domestic pressure, and divert the gas to several nearby fertilizer plants at low prices. These plants have been lying practically idle over recent years, due to insufficient gas supply and regional insecurity. Last year Indonesia suffered a shortage in domestically-produced ammonia and urea fertilizer, despite plentiful production capacity, with the required gas feedstock prioritized for LNG production. This led to the need for rice imports, and in this newly democratized country of more than 220 million people – with most living below the poverty line – that, combined with the oil price subsidy removals, created a political hot potato that has forced politicians to prioritize domestic gas use at the expense of LNG exports that had benefited only a few.
Nevertheless, elsewhere midstream gas development is progressing to plan. Dual pipelines running from Pertamina, Medco, PetroChina and ConocoPhillips-operated fields in South Sumatra to West Java are on schedule to supply power plants designed to run on gas, and industrial consumers faced with subsidy removal on liquid fuels.
Development of the Corridor Block fields was anchored around a lucrative 350 MMcf/d deal to supply Singapore, with prices linked to fuel oil. Surplus gas has been committed to the domestic market through a contract with Indonesian distribution and pipeline operator PGN. The pipelines will be run by PGN on an ‘open access’ basis, with the tariff estimated at about 70 cts/Mcf. Medco had a deal to supply Krakatau Steel directly using the pipeline – although this may now be channelled through PGN - while Pertamina and ConocoPhillips’ sales to PGN will either be sold on directly to large end-users (including power plants designed for gas but currently partly running on expensive oil products), or to smaller distribution franchises in West Java.
Examples of Producer to Consumer Gas Contracts in Indonesia
The open pipeline access and direct sales to Indonesian end users is a major step towards market deregulation and competition. State-supply monopolies dominate Asia, and Indonesia is one of the first nations to adopt such practices; and the only developing nation to do so. This could help to counter-balance the legal and policy uncertainties, and the move away from a focus on LNG exports. There is even the possibility of a gas market developing in West Java in 5-10 years time according to BPH Migas’ gas director Nafrizal Sikumbang. Although the partial deregulation is a positive development as far as foreign investors are concerned, the approval of regulator BHP Migas is still required for price and contract conditions, and this continues to leave room for considerable uncertainty.
Other sales are being made to PGN, Indonesia’s old domestic distributor; a highly regarded company that long languished in the shadow of Pertamina’s oil and gas monopoly with its LNG export priorities. PGN has been increasing prices to some customers – and has considerably leeway to do so – which could improve the economics of selling to this primary distributor. It gains revenue from pipeline tariffs and mark-ups on gas sales to industrial and other smaller consumers.
PGN has formed joint ventures with many provincial governments (given the new autonomy laws) to expand pipeline distribution networks, as well as issuing franchises to local companies to develop networks in particular areas (some with only three or four customers so far). Political connections appear to be invaluable.
Again on the plus side, Indonesia appears to be becoming more flexible over PSC terms, offering a lower government take for deepwater, technically difficult, gas-prone and/or remote acreage. In some cases this is because gas from such fields will be earmarked for fertilizer or power plants at low prices, although there appears to be a growing air of compromise and flexibility, and producers may be allowed to sell to multiple customers, diluting the effect of low fertilizer feedstock prices – or offered other incentives.
What’s more, the gas-fields in eastern Indonesia earmarked for LNG are unlikely to be affected owing to their distance from the Javanese industrial heartland. Australia’s LNG Ltd has secured supply from PT Medco for its planned mini (1.68 MMt/yr) Padang LNG plant – near the site of the cancelled Donggi-Senoro plant - which it plans to have onstream by 2008. And the BP operated 13.6 MMt/yr Tangguh LNG plant is reportedly progressing smoothly, although disagreements over the price of sales to CNOOC have only partially been resolved.
Japan’s Inpex also plans to develop its Masela find in the Arafura Sea as a 7 MMt/yr LNG plant, although it may be linked to Australia’s Darwin plant if Indonesian government objections are overcome.
Turning to liquids, as Indonesia’s domestic demand grows, there is an increasing shortfall in refining capacity, and import now account for third of needs. Refining capacity currently stands at about 1 MMb/day, and there are plans to almost double this. One obstacle is some subsidies remain on most domestic products, and Indonesia itself does not have the money to build the proposed plants. In order to attract investors, the plan is that the new refineries would be export-orientated – with the Chinese market high on the agenda. So far, Middle Eastern national oil companies, including Saudi Aramco, the National Iranian Oil Company and Kuwait Oil Company, have signed preliminary deals. The plants are likely to be designed to process sour Middle Eastern crude, rather than the sweet crude currently produced in Indonesia.
Refineries and Fertilizer Plants (Operating and Planned)
