The closings of several key IPP deals mark significant progress in the development of the Indonesia and Philippines power markets, though the two countries have taken very different paths. International banks have signed into Philippines deals with merchant risk, as the government hives off formerly state-owned assets and the wholesale power pool entrenches itself. Chinese financing is now flowing in, supplementing the regionally important Japanese and, to some extent, Korean funding. In Indonesia, international groups are circling the Central Java project, set to be the guinea pig for a new guarantee fund, which could allay offtaker concerns in this state-dominated market.

Deregulation takes hold in the Philippines

The two power deals closed in the first quarter of this year highlight real development in the Philippines. The 200MW Naga coal-fired power project, sponsored by Korea Electric Power Corporation (KEPCO) and Salcon Power Corp, showed that greenfield power projects with a merchant element could be funded by international lenders. GNPower group’s 600MW Mariveles coal plant project was the first non-recourse overseas power project financing from China Development Bank.

It has been almost 10 years since the Philippines instigated the liberalisation of its power sector through its Electric Power Industry Reform Act of 2001. The liberalisation has made the country a popular destination for foreign sponsors, though they have not always responded quickly to the price signals from deregulated markets. There remains a real need for new power capacity to curb prices and improve supply reliability.

The WESM wholesale power market was started up in 2006, the state-owned transmission company, Transco, has been privatised, and the government has now sold off many of the power plants and power-purchase agreements that it signed when it was the monopoly supplier, which means the implementation of open access rules for the wholesale market could take place as early as this year.

Naga scratches a regional itch

Within this context came the close in March of the 200MW Naga coal-fired project. The plant will be situated in Cebu and is scheduled to come online in the middle of 2011. It will bring a welcome boost to power capacity in the Visayas island group, where plant availability fluctuates around peak demand levels of close to 1,100MW.

The project is estimated to cost $490 million, of which debt accounts for $270 million, with the Asian Development Bank and the Export-Import Bank of Korea (Kexim) each providing direct loans of $100 million and commercial lenders together supplying $70 million.

Sumitomo Mitsui Banking Corp led the syndicate of three commercial banks, which also included ING and Calyon. The three banks each provided an equal share of the commercial tranche, which benefited from comprehensive political and commercial risk cover from Kexim.

The engineering, procurement and construction contractor is the Korean firm Doosan Heavy Industries and Construction. Kepco provided limited support to the lenders during construction, and when the plant is operational, this support switches to a capped contingency based on tests that include a robust debt service coverage ratio and coal supply viability.

When the WESM market is fully opened to competition, the project could use this as an option for a power sale. But for now the project has signed offtake contracts with around 15 small electricity cooperatives, with no single offtaker accounting for more than 25MW. A fraction of the capacity was left uncontracted at time of close.

The government might once have guaranteed these PPAs, but these are now solely with less creditworthy local entities, making the risk of offtaker default a big concern for lenders. The lenders’ ability to test performance during operations before guarantees were loosened was key to getting the deal done, says Andrew Ruff, a partner at Shearman & Sterling, legal adviser to the sponsors. “Without that there would have been a lot of reluctance on the part of the banks to lend,” he says.

The prospect of the emergence of the wholesale power pool has been factored into the structure. Under the take-or-pay contracts, the pay option covers around 75% of the PPA price, which is set at around Ps4.25 ($0.094) per kWh. The pay option on the PPAs at a minimum covers the fixed and operating costs of the plant. The PPAs also stipulate that if the offtaker does not take the power and the pool is operational, then it pays the difference between the pool price and the PPA price.

GNPower gets cross-border firsts

While the Naga project is set to boost plant availability in the Visayas region from next year, lender appetite for power project finance stepped up a gear with the closure of GNPower’s $1 billion Mariveles coal plant project. It is the largest greenfield power project financing in the Philippines for over a decade and the first non-recourse overseas power project financing from China Development Bank (CDB) and Sinosure.

The 600MW coal-fired plant would be the first step of a multi-fuel electricity generation and fuel handling complex in Bataan province, which is expected to include an integrated LNG storage and gas-fired facility, a hydroelectric plant, and a wind farm. Equity providers are Power Partners Ltd, PMR Holding Corporation, Denham Capital Management and Sithe Global Power.

The China Development Bank (CDB) is to provide $493 million to the project, with a group of five commercial lenders together providing $227 million. The commercial banks are four Philippines banks, Banco de Orro, Bank of the Philippines Islands, China Banking Corporation and Security Bank Corp, with Standard Chartered making up the group of five.

Banco de Oro is the largest commercial lender, supplying over half of the commercial debt portion.

Pricing on the CDB debt is 300bp over Libor for the first eight years, rising to 350bp to term – this includes CDB’s swap costs. Pricing on the $227 million onshore debt, is 300-400bp over Libor.

The project was closed without support or guarantees from the Philippines government, and has over 20 long-term PPAs in place with industrial companies and distribution utilities, looking to lock-in capacity and hedge their exposure to the wholesale market.

Originally planned as a vendor-financed project, the developers switched to a project finance model last year. China National Electric Equipment Corporation is the EPC contractor and the export financing from CDB’s Guangdong Branch was provided under a buyer’s credit structure. The developers held negotiations with CDB and commercial lenders culminating in an agreement between sponsors and lenders late last year. After sign-off from the Chinese Ministry of Finance, and the higher-level State Council, the deal eventually closed in January.

Although this was CDB’s first international project financing transaction, it was still able to move from approval to close within six months. The debt from the China Development Bank is insured by Sinosure, and has a tenor of construction plus 11.5 years and is paid at 300bp over Libor, not including swap costs. The commercial debt portion has a tenor of 12 years from close, equivalent to construction plus 8.5 years.

The loans are US dollar denominated, as are the EPC, coal supply and power purchase contracts. The primary coal supplier to the project is Indonesia’s Arutmin.

The commercial debt was priced over Libor, and Standard Chartered provided interest rate swaps. While the offshore loan has a longer tenor, the insurance from Sinosure meant that the pricing on that tranche was “quite comparable” to the onshore facility, says one source close to the deal.

The commissioning date for the plant is early 2013 and there is a strong expectation that the open access rules for the wholesale market will be fully in place by then. At close, around two thirds of the plant’s 600MW capacity is contracted. There are covenants that encourage sponsors to increase that amount by the time of commercial operations. The Energy Regulatory Commission approved the offtake agreements with the regulated distribution utilities, which formed the bulk of the contracted capacity, but did not need to do so for the private contracts with industrial customers.

The documentation for the deal includes ratings triggers for the distribution utilities, under which if their performance falls below a certain level, the project must replace them to meet a minimum credit threshold. The ratings, provided by the National Electrification Administration, factor in several criteria, including the distribution utility’s history of debt service to NEA, performance with respect to avoiding system losses, collection efficiency and fiscal management. “The challenge for new IPPs in the Philippines following deregulation is to assemble a collection of bankable offtake contracts to support external financing. Certainly, the better-rated offtake entities are being snapped up,” says one source close to the deal.

To comply with law that says Philippines land must be held by Philippines-controlled entities, an employee pension fund of an affiliate of the developer bought the land. Through a land loan, Banco de Oro financed the acquisition of the site by the developers’ affiliate, which leases the land to GNPower.

Indonesia: Greater needs, slower evolution

The scale of expansion in Indonesia is far greater than nearby Philippines, but persistent offtake concerns explain sluggish growth in the IPP sector. Unlike the Philippines, where local and industrial users have managed to supplant a large national electricity distribution company, the Indonesian market still revolves around the state electricity company, PLN. Lenders with long memories still recall PLN’s efforts to throw off power purchase agreements in the aftermath of the 90s Asian crisis.

Power cuts highlighted a dearth of supply, and under its 2006 CRASH power programme the country’s government targeted 10,000MW of new capacity, mainly coal-fired, aiming to entice in international developers and lenders. It is pushing ahead this year with a second 10,000MW CRASH programme, and expects that 80% of this capacity will be from IPPs, although only around a quarter is to come from coal-fired plants, with new geothermal plants set to make up almost half of the capacity.

PLN still supplies its customers at fixed-rate tariffs and there has been real concern at banks over how PLN will honour its offtake agreements, and how and whether the government will support them. This follows PLN’s reluctance to meet dollar-based offtake contracts with early IPP projects when the Rupiah collapsed during the late 90s crisis.

One of the biggest lenders to IPP projects in Indonesia has been the Japan Bank for International Cooperation (JBIC). There has been a long economic relationship between Indonesia and Japan, and JBIC entered into an umbrella memorandum of understanding with Indonesia’s Ministry of Finance. The MoU which stipulates that, for any proposed project, the regulations covering a public service agreement between MoF and PLN relating to off-take contracts, apply. The Mou seems to satisfy JBIC that it enjoys some kind of sovereign support for PPAs, though few other lenders are as generous in their interpretation.

This MoU was used by JBIC for its funding of the recently sealed Paiton-3 and Cirebon power projects, but the lack of guarantees for PLN’s offtake contracts has kept many other banks away from similar deals. In practice, JBIC’s MoU gives sponsors with Japanese content, or, more often, Japanese equity, a considerable advantage.

Paiton-3 comprises a single 815MW coal-fired unit located at the existing Paiton plant site, and is expected to be fully operational by the end of 2012. The project’s sponsors are International Power, Mitsui, Tokyo Electric Power Company, and PT Batu Hitam Perkasa. The financing package includes 17-year non-recourse loans, with $729 million provided by JBIC, and a $486 million loan from a group of international commercial banks.

The 660MW Cirebon coal-fired plant, a greenfield project, also closed recently, with JBIC again a key lender. The sponsors include Marubeni Corporation, Korea Midland Power Co, Tripatra Engineering and Samtan. Its debt comes from JBIC, Kexim, and a group of commercial banks made up of Bank of Tokyo-Mitsubishi UFJ, Mizuho Corporate Bank, Sumitomo Mitsui Banking Corporation and ING.
Is Central Java a new opening?

JBIC’s grip over Indonesian IPP finance could be loosened, however, with a new mechanism set to replace the much-questioned MoU. The test case for this new mechanism, the Indonesia Infrastructure Guarantee Fund, is set to be the Central Java IPP project. Seven bidders have prequalified for the $3 billion project to build a 2GW coal-fired power plant running on supercritical boiler technology on a build-own-operate or build-operate-transfer basis, at Pemalang. The project includes the construction of an associated transmission line, and the plant would enter into a 25-year PPA with PLN. Bids are due by August.

There is much Japanese interest, which indicates that JBIC could still have a role in any eventual financing, but there are other international players looking at the deal, including Chinese and Korean sponsors. The candidates are China’s Shenhua Energy, a consortium of CNTIC and Guangdong Yudean, Korea’s Kepco, Japan’s Marubeni, Japan’s Mitsubishi, and part-Japanese consortiums International Power-Mitsui and GDF Suez-J Power.

According to sources close to the bidding, there is no MoU with the MoF on the table for JBIC, and instead the government wants to put in place the IIGF, which is meant to be more in line with other international banks’ expectations. Details of the IIGF are still being ironed out, but it will cover PLN’s financial obligations under PPAs. Sources say there has been in the region of $300 million committed to the fund, far less than would be required for a project the size of Central Java.

The IIGF would replace the MoU with a single point of responsibility and the adviser to the fund is the International Finance Corporation. The risks covered under the guarantee package will be tailored to the specific risks requested by investors. It is not yet clear how the fund will be supported, or whether the fund will be given a credit rating.

It is likely that only a bilateral agency or multilateral agency could take the IIGF risk, says one banker, close to one Central Java bid. “No commercial bank is going to lend on the back of purely the IIGF guarantee,” he says. There is sceptism as to whether the bid process for Central Java can be completed on schedule, bearing in mind the pace of introduction of the IIGF.

The closure of the Paiton-3 and Cirebon projects were encouraging signs for IPP developers, which must now re-think their projects under the new fund mechanism, says one legal source. “We are back to square one – we’re looking at a new structure, and that structure is yet to be developed. That causes concerns in terms of delay,” the source adds.

The government has collected comments on the terms of the Central Java project and one central concern for the bidders is the siting of the project. Under the current plan, it is for the bidders to choose a site from a list of potential areas, given by the government. This places land acquisition risk in the laps of the bidders, and at least one candidate has suggested to the government it determines the site before bids are made. “There are so many issues that come out of private land dealings, it becomes political. That political risk really should be with the government,” says one source.

In one respect, Indonesia comes out ahead of the Philippines. Indonesia’s 2009 legilative and presidential elections took place in mid-2009, with the re-election of president Susilo Bambang Yudhoyono. Elections in the Philippines were taking place as Project Finance went to press.