Across South East Asia, deal flow in the power sector has not run completely dry yet, but is definitely declining. Significant debreases in demand for new capacity and faltering de-regulation have replaced the bullish sentiment expressed by power financiers two years ago with one of reservation. Activity in markets previously cited as potential hotspots, notably Malaysia, Thailand and Philippines, has practically ground to a halt. Action for international financiers is likely to be thin on the ground in the short-to-medium term and will come from new quarters.

Phu My 2.2 and Phu My 3 in the previously uncharted territory of Vietnam are the only greenfield projects likely to hit the markets this year. According to parties involved, legislation is in place and financing should close successfully by the end of the year but opinion remains divided. Some lenders say they have intentionally steered clear, claiming that large scale IPP financings in a country with no history or legal framework for private concessions is simply a risk too far.

?We have found from experience that trying to finance power projects in risky climates is too difficult,? says a banker at a regional development bank. ?Power is often a very political issue, with too many vested interests involved. The presence of multi-laterals has not always proved sufficient to facilitate a smooth ride.?

Elsewhere, Thailand has only one potential IPP left in the pipeline capable of attracting international debt attention and the recently successful refinancing of Theun Hinboun has accelerated talks of another two hydropower projects in Laos. Any further greenfield activity in South East Asia is a matter of serious speculation.

Incumbent disposal programmes will certainly generate some significant opportunities, but even these seem to be falling by the wayside, with Thailand and Malaysia having largely shelved power privatisation plans. Singapore remains likely to lead the way, lining up gencos to be sold in the first quarter of 2003. The Philippines also continues to demonstrate commitment, unusually aiming to divest transmission assets first.

Anyone for power?

The Thai power market, until recently viewed as an active IPP market, took a significant blow this month following a government announcement that two major coal-fired IPPs have been ?indefinitely postponed'. The 1400MW Union Power Development Corp (UPCD) at Hin Krut in southwestern Thailand and the 734MW Gulf Power Generation Co (GPG) at Bo Nok, 300km south of Bangkok have been dogged with controversy since their inception. UPCD is sponsored by Tomen Corp, Chubu Electric Power, Toyota Tsusho Corp, Hongkong Electric International and Saha Union, while GPG was developed by Gulf Electric Co and Mission Energy.

Both secured licenses and power parchase agreements (PPAs) with Electricity Generating Authority of Thailand (EGAT) in Thailand's first spate of IPP awards in 1994. Loan documents were apparently in place, with lenders poised to sign, in 1997 when the financial crisis put them on hold.

2000 saw a handful of Thai IPPs securing financing, albeit with fairly tight export credit agency (ECA) and political risk insurance (PRI) support, including Bowin Power's 741MW Chonburi plant, and talk turned to market recovery. Thailand was back on the map for power financings, bringing with it UPCD and GPG. These troubled projects, however, have subsequently been confronted with problems closer to home. Local citizens have vocally opposed the projects on grounds ranging from adverse environmental effects of burning coal to accusations that PPAs will increase tarriffs for customers. Political pressure was stepped up following appointment of the Thaksin administration last year and the announcement to postpone that came at the beginning of May 2002 was widely anticipated.

Sponsors could yet consider switching to gas-fueled technology or re-locating in an attempt to get these projects off the ground. However, with power demand still not increasing in line with pre-1997 projections and opportunities to buy cheaply generated hydropower from Laos, movement is unlikely in the near future. Either way, sources suggest that sponsors could seek substantial compensation and, perhaps more worryingly for the Thai government, Thailand's reputation vis a vis foreign investment may have taken a blow.

Lenders will have noticed, however, and a cloud of uncertainty has been cast over Thai power. One significant IPP remains ? the 1400MW BLCP Power project sponsored by Banpu, Loxley, China Light Power and PowerGen. ?No decision has been made with regard to funding yet,? says Eelko Bronkhorst, regional head, integrated energy Asia Pacific at adviser ABN Amro. ?We are currently engaged in discussions. Whatever the route, though, this is likely to be the last IPP in Thailand for a while.? BLCP has so far escaped the domestic problems of UPCD and GPG although rumours suggest that some local resistance to the plant is growing.

Other markets in the region often targeted by project financiers are also showing few signs of life on the greenfield front. The South Korean IPP program never really got off the ground and attention is now focused on the restructuring of state power incumbent KEPCO. The Philippines commissioned significant capacity in the early 1990s following a power crisis, with the result that generation is now in oversupply. The initiative has received subsequent criticism from some quarters, which claim that state utility Napocor has amassed extensive debts as a result of badly negotiated take-or-pay contracts.

Malaysia will not be looking for any more newbuild capacity. 2001 saw a series of power financings culminating in the RM1.5 billion Islamic bond and commercial paper/medium-term note funding program for Malakoff's GB3 project, which signalled the end of an era. Two further greenfield projects, the 2100MW Pulau Bunting sponsored by SKS Ventures and YTL's 1400MW Jimah Power development have been called off for the forseeable future. Taiwan is a similar story. Sunba Power's NT$20 billion ($600 million), Star Energy Power's NT$8.24 billion and Chia Hui's NT$10.8 billion generating plants all closed finance at the end of last year. M&A activity is the only potential for financing in these markets over the next few years.

Local currency

In any event, neither Malaysian nor Taiwanese power markets have needed, or are likely to need, help from the international banking community. Almost all financings to date have been domestic currency denominated. In the case of Taiwan, power projects have been eligible for CEPD loans, low interest rates from the government designed to encourage private sector activity in the sector. Supplementing this, the local New Taiwan Dollar market is highly liquid and the domestic banking system fiercely competitive Since 1999, 65p to 75bp pricing has been the norm for Taiwanese project power projects.

Taiwan has, in fact, remained largely a domestic affair even from a sponsor point of view. State run Taiwan Power controls 80% of the electricity market, which is characterised by unfavourable IPPs and an immature legal foundation. NRG took the plunge last year, purchasing a 60% stake in Taiwanese power company Hsin Yu. However, following the lead of many other US corporates post-Enron, NRG looks as if it is pulling out as soon as possible.

Malaysia has been an exception in the region in that it has relied almost entirely on domestic capital markets rather than local bank lending or international funds to finance its portfolio of power projects. Speculation that draining funds or exposure limits would leave some projects high and dry proved unfounded. The bond pool, driven by historically low interest rates and a developing pensions business, continues to be extremely deep.

Malaysia may be the stalwart of domestic bond financing in Asia, but other countries have maturing capital markets. In many cases this adds to an already sophisticated local banking market. Domestic lenders have proved very active in South Korea's Private Participation in Infrastructure (PPI) scheme recently and the Thai Bhat also has significant liquidity. The acquisition financing for Ratchaburi Electricity Generating Holding Company, EGAT's only significant disposal, in 2000 was raised solely in local currency.

Since exchange loss and currency de-valuation brought on by the Asian financial crisis, local currency financing, as a way to match revenue with liabilities, has become increasingly popular across Asia. US dollar debt is now only one of a number of financing options for many projects. Refinancings coming to the market in coming years, which aren't generally looking for the same level of ECA support as newbuild IPPs, are likely to look towards full domestic currency.

With reference to this general trend across the region, one Singapore banker says, ?The stimulation of increasingly sophisticated local currency financing and its application to long term lending is undoubtedly good news for the countries and their economies. However, it is not fantastic for international lenders.?

Vijay Sethu, director and head of power for Asia, ANZ admits that it is becoming increasingly difficult to compete with domestic funds. ?Domestic lenders want to lend to their incumbent utilities,? points out Vijay Sethu, director and head of power for Asia, ANZ. ?They might rate an incumbent at AAA, whereas international lenders would only perceive the utility as BBB. In these instances, it is very difficult for the latter to compete on pricing.?

Some heavyweight banks have carved a new role for themselves within the field. ?Local currency has to be the way forward,? says Michael Kershaw, HSBC's head of project finance for Asia, ?we are a significant player in a number of local capital markets, particularly the Malaysian Rinngit. I expect to see continued development of such markets in a number of countries.? A number of international lenders are increasing capabilities to lend in local currencies, ABN Amro and Citi both put up Thai Bhat for Ratchaburi.

New ground

Banks who do want to put up long-term limited recourse dollars are thus having to look further afield. Markets that still have rising demand and no local currency capabilities to speak of are bound to be at the riskier end of the spectrum. Firmly in this category, Vietnam is playing host to two projects hoping to reach financial close this year. Lead sponsored by EdF and BP respectively, Phu My 2.2 and Phu My 3 follow closely behind the country's debut into the international debt markets. The $154 million Thu Duc water treatment plant completed financing last year, lead arranged by Fortis, Credit Lyonnais and ANZ.

The Vietnamese government's initiative to open its markets has created rapid economic growth in recent years. This in turn has created a significant power deficit, requiring a level of investment that Electricite de Vietnam (EVN) could not generate independently. The World Bank has been working closely with the government in an attempt to restructure the energy market and promote private power development in a transparent and competitive manner. This culminated in the tender of a 20-year build-operate-transfer (BOT) contract for the $400 million, 715 MW, Phu My 2.2. Duncan Ritchie, director, SG, acting as adviser to the consortium, says that the World Bank was fundamental in getting Phu My 2.2 off the ground, sponsoring the government to develop a framework for the transaction. Progression of the project was a pre-condition of additional multi-lateral funding for the energy sector as a whole.

The $350 million, 720 MW Phu My 3, sponsored by BP, Sembcorp Utilities and Kyuchu Electric Cy, is a slightly different story and, with construction underway, is on track to become the first foreign owned BOT up and running in Vietnam. BP, as part of a consrortium, is also developing the Nam Con Son Basin and the BOT contract was negotiated in a bid to stimulate an end market. Gas from Nam Con Son will feed the whole Phu My complex, which has a targeted capacity of 3600MW. Phu My 1 and 2.1 have been constructed on the back of government and World Bank Funds. ENV has a PPA for the entire output.

Financing projects of this scale in Vietnam is no mean feat. Uncovered debt is not an option and the number of institutions needed to raise funding can lead to lengthy and complex negotiations. But Sethu waves off such concerns. ?We specialise in understanding how to finance large deals in risky climates.? Two AES deals in Bangladesh and one in Sri Lanka as well as Thu Duc, which all closed last year, are testament to this claim.

Phu My 2.2 is well into the financing stage, with financial close targeted for September and a syndication phase to follow. Lead arrangers ANZ, SG and SMBC have already secured ECAs Coface and JBIC as well as a World Bank lending commitment. Phu My 3, despite being first in the construction race, is slightly behind on the financing, although still hoping to close this year. Lead arrangers on this deal are CAI, Fortis, Credit Lyonnais, BOTM and Mizuho and discussions are said to be underway with possible agencies.

Participants say that, so far, the concession agreements broadly meet international standards and that, with tight structures in place, they are comfortable with the associated risks. Moreover, they say that successful closure would be a significant milestone, putting Vietnam on the international project finance map for the first time. They mark a significant progression from Thu Duc, having been promoted by the central rather than a provincial government. This is a reflection of the significance attributed to foreign investment in the energy sector. ?These deals could prove instrumental for the future,? predicts Ritchie. ?If the government can successfully close these, it will provide a platform for other infrastructure concessions.?

Some observing from afar remain less confident. Sentiment from some steering clear of the deals ranged from a degree of reservation to one banker who claimed that, ?If I got on a plane to Vietnam I'd be fired.? The main point of concern is not normal IPP risk but simply the uncharted territory of Vietnam, as a host for BOT concession agreements. ?Explaining these procedures to the Vietnamese government is not easy,? says one. ?There is a risk that they either don't really understand or aren't really interested and the projects could run into trouble further down the line as a result.? Proponents of the projects applaud the introduction of foreign participation in the power sector for the first time. Sceptics, meanwhile, question whether it the impetus really came from within or whether it was simply a gesture to appease the World Bank.

Love them or hate them, however, people will watch with interest as the story of Vietnam's first foreign-sponsored IPPs unfold.

Another site of potential financing activity is Laos. Not traditionally a destination for project financiers, the country saw a successful refinancing of Theun Hinboun hydropower project close in April 2002 (see box). Laos itself has no need for need for more capacity or structure for IPPs. However, it does have huge hydropower generation potential and following the success of Thuen Hinboun is looking to capitalise on this and export. This precedent showed that despite the country having a fairly immature legal environment, well-structured deals can attract long term financing. With EGAT as offtaker, Thai Bhat liquidity can also be tapped.

?When the original financing closed, we said it would pave the way for other projects to follow suit,? says David Michaels, managing director of GMS Power Public Co. Ltd. But none did. ?Now we have closed the refinancing, we'll say it again.?

Action does look more likely this time, with two projects in the pipeline. A consortium comprised of EdF, EGAT, Electricite du Laos and Italian Thai Development secured a contract to develop a 1060MW Nam Theun 2 hydropower project. Negotiations with EGAT over a PPA for a majority of the capacity are believed to be drawing to a conclusion. Further down the line, GMS Power has signed an agreement with the Lao Government to develop Nam Ngum 3.

On considering other greenfield possibilities, one market player raises the question of Indonesia. It is one of the only markets left in the region that still has significant capacity demands. However, for the forseeable future, Indonesia remains a no go area. Too many fingers were burnt in the wake of 1997. Multi-laterals would have to take the initiative and for the moment even they are staying away from the power sector, restricting themselves to dollar-earning oil and gas projects.