This market is the busiest I've seen it in the decades I've been following Latin America. It's too bad we can't hire enough people to follow it." The line, uttered in confidence so as not to alarm his larger clients, illustrates one of the stranger collisions of the credit crunch and project finance markets. Chile, growing at roughly 5% per year, needs to add 400MW of new capacity per year, but the lumpiness of the capacity bidding process means that this trickle of new business can sometimes resemble a flood.

Capital markets, both in Chile and the US, have suffered much greater damage than the project finance debt market. Moreover, Chilean life insurance companies and pension funds do not invest in the generation sector, both because they are prohibited, and because the dollar revenue streams from power projects are of little use to bondholders with Peso liabilities.

Chile, long a source of toll road business for monolines and banks with local funding capabilities, is now the busiest market for power finance in Latin America. While Mexico's power market ticks along with sporadic refinancings and acquisition financings and a thin diet of construction financings for the country's state power company – Brazil's power sector relies upon playing junior partner to the state development bank, BNDES, and the Inter-American Development Bank.

Chile, on the other hand, offers long tenors, private offtakers and participation only to the more flexible export credit agencies. Until the credit crunch it also offered extremely low pricing, though in common with almost all other debt markets, levels have risen. Thanks to the instability in neighbouring Argentine, the country has turned into a paradise for project finance lenders.

Unreliable partners

The cause of all the activity is the default, subsequent recovery, and succession of populist administrations in Argentina. Argentina used to be a substantial gas exporter, and 40% of Chile's generating capacity was dependent on supplies of gas from the country. It supplied 17 million cubic metres per day of Chile's 17 million in imports.

But following Argentina's 2001-2 default, the country's government imposed price controls upon natural gas, and restricted exports of gas over the Andes. Argentina is now a substantial importer of gas, both from Bolivia and potentially via a liquefied natural gas terminal based in Uruguay. While Bolivian supplies have eased some of the pressure, poor rainfall and cold winters in recent years have been a major drain on its gas-fired capacity.

The restrictions, which were enacted in 2004, have allowed Argentinean industry to stabilise, have avoided wider unrest, and even sparked a small cross-border high-yield bond finance boom, as private equity bonds borrow dollars to pay for infrastructure purchases. But for Chile they have been deeply troubling. Already wary of importing gas from its neighbour Bolivia, with which it fought a war in the late nineteenth century over access to the Pacific, Chile now scrambles to replace another unreliable neighbour.

But Chile's approach to infrastructure is pragmatic, as any investor in its toll road programme can testify. In energy, as with roads, the government worked to modify an investment framework with a heavy market bias in the face of bad macroeconomic news. With the toll road programme it was a restructuring of concession terms, but with electricity the government has made some changes to the relationship between generators and utilities.

Moreover, Chile has turned towards ship-borne supplies of natural gas and coal to fuel its generating fleet. Both changes promise a greater reliance upon contracts in building out energy opportunities, and a sweeter risk profile for lenders. For sponsors, the new framework promises lower pricing and tenors unmatched anywhere else in the region.

LNG looms

Chile's gas companies and generators have decided that the vagaries of the international gas markets make for a more solid foundation for its electricity sector than relying upon its neighbours. The first fruit of this will be the Quintero LNG project, the financing for which is currently in the market.

Quintero, or GNLQ, according to its initials in Spanish, is a 2.5 million tonnes per year receiving terminal located in the central region of Chile, about 162 km from Santiago. It is designed in part to feed the region's small installed gas capacity, but also to supply local gas distributors, state oil company ENAP, and local industry.

The project was announced in 2004, almost as soon as the severity of the Argentinean disruption was clear, and enjoys strong government support. The government has been extremely optimistic about both the cost of the project, and the cost at which it could import gas. The cost of the project has increased from an original, and partial, estimate of $400 million to the $1.2 billion total before bankers today. And sources close to the project indicate that the Chilean offtakers would be buying gas at considerably more than the $4.50 per million BTU estimate from 2005. Henry Hub gas prices, the most likely benchmark for global LNG prices, recently hit $11 per million BTU.

But Quintero has a solid set of sponsors: BG (40%), ENAP (20%) Metrogas (20%) and Endesa (20%). BG's presence as a supplier to the project originally raised eyebrows, since it is much better known as a player in the Atlantic Basin LNG market. But BG's moves to acquire Australian gas resources, through a stake in Queensland Gas Corp and a proposed takeover of Origin Energy, have quieted some of these worries. As one banker close to the financing noted "it doesn't take much longer to get Egyptian gas to Chile than Australian gas." BG has a substantial LNG presence in Egypt.

The lead arrangers of the roughly $1 billion financing are Banesto, BBVA, Calyon, Fortis, ING, Intesa SanPaolo, Mizuho, Santander and West LB, which were chosen after an HSBC-run beauty contest. The leads are currently in documentation, and hope to close, and then carry out a limited syndication, before the end of June.

The size of the group gives some kind of indication of the most marked impact of the crunch. The most recent financings in the Americas – for the US Gulf LNG and Canadian Canaport Terminals – had much smaller, relationship-driven groups. Quintero's group is a mixture of Spanish lenders, with a regional presence or relationships with Endesa, and long-time regional players.

Meanwhile, Suez Energy, the other big presence in gas distribution in Chile, is building a receiving terminal in the northern part of Chile, at Mejillones, 1,400km north of Santiago, as a 50/50 joint venture with copper producer Codelco. Suez is understood not to be looking at project debt to fund the LNG terminal – it and its partner are likely to fund initial works on the $500 million project using internally-generated funds.

The gas will go towards supplying BHP Billiton's Escondida project, Xstrata and Anglo's Collahuasi project, and Codelco, which is responsible for 11% of global copper production, and Antofagasta Minerals, which has signed a 21-year power purchase agreement for its greenfield Esperanza mine. The gas deliveries, for use in their in-house generation fleet, would be equivalent to 450MW of capacity.

Gas or coal?

Suez, which has built up an LNG business that spans the Middle East, Europe, the US and Latin America, is making a bold bet on the continued economic health of the Atacama mining region in northern Chile. Its offtakers are exposed to the price of copper, and Suez and its lenders will need to hope that if something happens to the price of copper, or if gas prices plunge below contract levels, these names will continue to support their obligation.

Suez, through its stakes in Electroandina and Edelnor, has access to roughly 50% of the generating capacity of the northern network, or SING. According to Suez, demand growth for the next 15 years will be roughly 5.95%. Since the north shares with the central region a previous dependence on Argentinean natural gas, Suez thinks that contracts with the big mining companies will command a premium and make gas economic.

Calyon and Fortis currently have a $414 million financing near market for the 150MW first unit at the Central Termoelectrica Andino (CTA) complex, also located at Mejillones. The deal is set to launch this month, and will test lender appetite for such credits. The IFC is in place to finance both the first unit, of which state-owned Codelco is taking 100%, and a follow-up of the same size, which is selling its output to Antofagasta. It pegs the total cost of the project at $1 billion, and says that it has been approached for $590 million in B loans and a $150 million A loan.

Both of the CTA units, however, will run on coal, and are located next to three existing Edelnor units. The credit profile of the project, while relatively straightforward, will need to encompass both commodities risk and the sprawling ownership structure of Suez' Chilean generating assets.

AES Gener has a greater presence in the central interconnected region of Chile, which encompasses roughly half of the country's population, and is the largest thermal generator in the country. Gener is steering clear of gas for additions to its fleet, suspecting, probably correctly, that residential and small industrial users will be much more sensitive to volatile commodity prices than the mining companies.

Gener recently completed two coal financings, one more greenfield than the other, and is working to close a third by the end of the quarter, its largest to date. AES Gener's Nueva Ventanas financing, which closed in June 2007 is the benchmark for debt arrangers to beat. Ventanas closed a $415 million senior secured construction loan and $25 million seven-year debt service reserve letter of credit with Calyon and Fortis.

The financing, despite a 15-year tenor and pricing that started at 95bp over Libor, brought in 20 banks in syndication, and was 40% oversubscribed. A mixture of Spanish, global, as well as Korean lenders supporting EPC contractor Posco, made up the syndicate. The 15-year tenor included construction, and made room for a three-year tail on the tolling agreement supporting the debt.

The financing, for a 242MW coal plant located 120km north of Santiago, relies upon the credit of Gener, which is the tolling counterparty, and in turn sells the project's outputs to its utility and industrial customers. For its future financings, Gener is likely to have project companies sign power purchase agreements directly with utilities.

Proof of this strategy is likely to come when lead arrangers BNP Paribas and ABN Amro send the roughly $1 billion Angamos financing to market. Gener needed to contribute $100 million in equity to Nueva Ventanas, and may need to find as much as $350 million to build out Angamos, a 540MW coal unit located near Antofagasta, which has again lined Posco up as EPC contractor. Next in line are Campiche, a 270MW coal unit with a $440 million capital cost, which is located at the Ventanas site, and could come to market later in the year.

Short and sweet

These financings, particularly to regulated distribution companies in the SIC region, are possible because of the passage of Short Law II. The law (the first Short Law covered transmission tariffs), was designed to allow faster investment in new generation, by enabling the long-term contracts that are central to the current wave of project financings.

The 1982 electricity law has survived both the 1999 drought in Chile, which hit the south of the country hard, and the 2004 convulsions. One lender active in the market calls it "the best electricity law ever written". The law, heavily influenced by the Chicago economists, mandates a combination of spot prices, regulated node prices, and unregulated contracts for large industrial users.

Short Law II essentially allowed distributors to bid out supply to contracts to the generators without reference to node prices. Node prices were set by the CNE, Chile's regulator, by reference to a formula based on the notional operating cost of a gas-fired simple-cycle unit. And contracts between large industrial users and the generators set the bands within which node prices could move. While it was subject to a number of other variations and adjustments, the node price did not respond quickly enough to the Argentina crisis.

The capacity bids, combined with the health of the copper industry, have provided the necessary spur to new generation. Indexing contract prices to fuel prices allows generators to collect on fuel cost increases on their contracts with utilities. While they now suffer short lags between the impact of fuel increases and being able to collect these from their customers the utilities, the risk is minimal.

But prices have increased sharply, and utilities and consumers alike have had to adjust to an operating environment where prices per MWh are as high as $150, up from $15 dollars in recent memory, and the penalty price for electricity, for generators that do not have the resources to meet their obligations, is $300 per MWh. The retail business is still profitable, but PSEG, completing its withdrawal from the region, sold its 50% stake in Chilquinta Energia, which serves 454,140 customers, to AEI earlier this year as part of a portfolio sale.

But it's hard to find lenders or sponsors with lingering concerns about Chile, since it has proved to resilient in the face of previous shocks. A concerted move to connect the northern and southern regions would have marked effect on electricity markets, though its impact would be at most the equivalent of 1,000MW of new capacity. But since the country's principal transmission operator, Transelec, was sold by Hydro-Quebec to a Brookfield-led consortium, these plans have been put to one side.

Hydroelectric capacity from the south of the country might also have a marked effect on market fundamentals. There are up to 10,000MW in identified hydro opportunities, of which 1,500MW would be feasible. But many of these prospects are located in environmentally sensitive areas, and few utilities, remembering the drought of 1999, want to make themselves dependent on hydrology again.

For this reason many of the hydro plants to come to market do so with a heavy merchant element, which scares project finance lenders but has allowed the International Finance Corporation to carve out quite a niche. In the last ten years, the IFC has financed every single hydro plant in the country that is larger than 50MW, including the partially merchant La Hiuguera and LaCconfluencia plants (both sponsored by Norway's SN Power, and about which more information can be found by searching by name).

The IFC is looking to bundle smaller hydro projects, which excite less controversy, into financeable clumps, though these are unlikely to provide substantial fee income to commercial lenders. Moreover, coal and gas prices, not to mention an increasingly assertive environmental lobby, could still upset the power market. But its resilience to date has created a devoted lender following.