Chapter 9
Mexican power projects following Samalayuca II and Merida III
After AES was awarded the mandate for Merida III in March 1997 (see Chapter 8), three power project concession awards followed the build-lease-transfer (BLT) model of Samalayuca II (see Chapter 7): the 450 MW Rosarito III project, the 100 MW Cerro Preto project and the 435 MW Encino project. Subsequently, budget cuts made the Comision Federal de Electricidad (CFE) more receptive to the private sector and several more inde- pendent power producer (IPP) ventures were approved. The structure for the Merida III loan from the International Finance Corporation (IFC) was sufficiently sound to be essentially replicated in two recent loans from the IFC to Mexican IPP ventures, the Rio Bravo and Saltillo projects, and a loan from the Inter-American Development Bank (IDB) to another such venture, the Hermesillo project.
In all these power projects the CFE provided virtually all the specifications and the developer bid a price as well as qualifications to do the job. More recently, as Jonathan Lindenberg, Managing Director of Citibank, observes, IPP ventures negotiated with the CFE have allowed their sponsors increasing flexibility with regard to site selection, fuel supply and the sale of excess power. For example, when InterGen, a Shell/Bechtel venture, submitted bids to the CFE for the Bajio and La Rosita projects, described below, it delib- erately specified larger plants than were necessary to satisfy the CFE’s needs so as to be able to offer a lower price to the CFE, to start exporting power to the United States and to develop a bilateral market for power sales to Mexican industrial customers. In the bankers’
view, the ability of border-region plants to sell power in either country enhances their cred- itworthiness. Mexico now has investment-grade ratings from Moody’s, Standard & Poor’s and other agencies. As a result, there should be less requirement than before for support from the multilateral and bilateral agencies, such as export credit agencies, whose country capacities are strained.
Lindenberg of Citibank observes that project oversizing adds a new credit wrinkle from the CFE’s perspective. The CFE has always agreed that if it defaults, or following certain events of force majeure,it would have to buy out the project, and make debt and equity hold- ers whole. That is reasonable when the size of the power purchase agreement (PPA) and the project size are the same, but different issues arise when the project is bigger than the PPA because it is selling additional power to industrial or export customers. Recently, the CFE has indicated that, in the event of default, it might be willing to bear the risk of having to buy out projects larger than the related PPAs just so that it can stay in control of the situation.
The following sections describe the financing of the Bajio and La Rosita projects, and of Termoelectrico del Golfo I and II, two ‘inside the fence’ power projects financed under Mexican self-supply energy legislation. A power project ‘inside the fence’ is located within a company’s industrial plant or complex, is owned by the company and is intended to serve mainly the needs of that plant or complex. Sometimes excess power is sold to other users.
Bajio
InterGen’s 600 MW Bajio project in San Luis de la Paz, 160 miles northwest of Mexico City, shows some new directions for IPPs in Mexico. The project sponsors are InterGen and AEP Resources, a subsidiary of American Electric Power. The project will use 495 MW of its capacity for sale of electricity to CFE under a 25-year PPA and the remaining 105 MW for sales to third-party industrial customers. A Mexican IPP with a ‘self-supply permit’ is
BAJIO, LA ROSITA AND TEG, MEXICO
allowed to sell electricity to industrial customers that hold a nominal 2 per cent share in the project. This is just a legal requirement; these companies have no shareholders’ rights.
InterGen deliberately oversized the project so as to be able to offer the CFE a lower electric- ity tariff. This helped the developer win the bid from the CFE against heavy competition and establish a position in the nascent Mexican wholesale power market.
Financing for the Bajio project, which closed in June 2000, came from:
• a US$22.5 million IDB A loan;
• a US$113 million B loan syndicated by BNP Paribas, Citibank, Deutsche Bank and Dresdner; and
• a US$215 million commercial paper facility provided by Citibank.
Commercial paper offers the project lower-cost financing than a loan based on the London interbank offered rate (Libor) would have. Citibank will sell the commercial paper through a conduit vehicle called Govco, which it developed several years ago for government-guaran- teed financings. This is the first time that this vehicle has been used for a non-recourse pro- ject financing.
The commercial paper is backed by a comprehensive guarantee from the Export-Import Bank of the United States (US Eximbank), which further reduces the cost. US exports include gas and steam turbines from General Electric Power Systems. US Eximbank set a precedent with this financing as well. Bajio is the first project for which its comprehensive guarantee covers both the construction and the operating period.
Bankers based their credit decisions primarily on the PPA with the CFE, considering that the risk related to industrial sales would be borne by the sponsors. In an unlikely worst-case scenario, the sponsors would bear the cost of a 600 MW plant but only receive the revenue from a 495 MW PPA. From a business perspective, some see InterGen as breaking even on the PPA and making its profit on the industrial sales.
La Rosita I and II
In December 2001 InterGen closed a US$625 million commercial bank financing for La Rosita I and II (formerly called Rosarito but renamed because of confusion with other pro- jects), in Baja California, about six miles south of the US border. Of the total amount, US$420 million is covered by political risk insurance from the Export Development Corporation of Canada. The covered portion has a tenor of 15 years and the uncovered portion 11 years.
Guillermo Espiga, Director – Finance, Latin America, for InterGen Energy, Inc., in Coral Gables, Florida, noted that the successful syndication of the Bajio project helped with this financing. As with Bajio, InterGen oversized La Rosita I in order to achieve economies of scale and to be able to offer a better rate to the CFE. InterGen will use 500 MW of the plant’s capacity to sell to the CFE and 250 MW to export to the California market.
La Rosita I and II is the first Mexican IPP in which the developer rather than the CFE has selected the site, which in this case was based on serving both the Mexican and the Californian markets. Also, instead of buying fuel from Pemex Gas y Petroquimica Basica (Pemex), the Mexican state-owned energy company, as previously established IPPs have, La Rosita I and II has the flexibility to arrange its own fuel supply from either the US or the Mexican market.
The plant’s natural gas fuel supplier is Coral Energy, which has a tolling arrangement for the 250 MW of its power sold in the US market. Coral Energy is the AAA-rated trading arm of Shell, InterGen’s 68-per-cent owner. The fuel will be supplied through the North Baja pipeline, a joint venture between two potential customers of the plant, PG&E Corporation and Sempra Energy.
The 310 MW La Rosita II plant is an entirely merchant facility that will sell power through Coral Energy into the Californian market. It therefore has a considerably higher risk profile than La Rosita I, with its CFE contract. The bank financing addresses the varying level of merchant risk through an innovative borrowing base approach that limits leverage and dis- tributions (after the plants begin to operate), based on proportions of contracted power and forecast power prices. Leverage will be 75 per cent for La Rosita I but just 50 per cent for La Rosita II. Thus US$625 million is the maximum commercial bank commitment. The amount of loans that can be drawn at a given time is calculated according to a borrowing base deter- mined by the respective leverage of the two power plants.
InterGen’s long-term strategy is to build a national energy company in Mexico, continu- ing to bid on CFE projects but always adding value through factors such as industrial and export sales.
TEG I
Termoelectrico del Golfo I (TEG I) is an ‘inside the fence’ project costing about US$370 mil- lion. The plant is located in Tamuin in the central Mexican state of San Luis Potosi.
The project is sponsored by Sithe Energies, Inc., ABB Alstom Power and Cemex. The sponsors have put in place wheeling arrangements with the CFE so that the project can trans- mit power to 12 Cemex cement plants. Wheeling is the movement of electricity from one system to another over the transmission facilities of intervening systems. Wheeling is required to offer customers a choice of electricity suppliers. The project will sell surplus power to the CFE.
Sithe is the largest non-utility IPP in the United States. The company has no political risk insurance on its equity. Robert Kartheiser, Sithe’s senior vice president for Latin America, believes that political risk in Mexico today is manageable, based on recent struc- tural and economic changes, increasing integration with the US economy as a result of membership of the North American Free Trade Area, and Vicente Fox’s victory in the pres- idential election in July 2000. In the past Sithe has followed an opportunistic worldwide IPP strategy. More recently, its shareholders have decided to focus on Canada, Mexico, and the United States.
ABB Alstom is a turbine manufacturer based in Belgium. The banks lending to this pro- ject were concerned that the clean-burning, fluidised bed technology that ABB Alstom planned to use in the boilers was, although not completely new, an extension of an existing technology. Further, this technology had never been employed in such a large plant. To allay their concerns the lenders became comfortable with ABB Alstom’s reputation and negotiat- ed an acceptable level of liquidated damages under the engineering, construction and pro- curement contract.
Cemex, the power offtaker, is one of the largest industrial companies in Mexico and the third largest cement maker in the world. TEG I represents a strategic measure for Cemex to manage its long-term cost of electricity, which accounts for about 20 per cent of
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its manufacturing cost. The company wanted a secure, predictable and competitive source of power.
For fuel, the TEG I plant uses petroleum coke, which costs less than natural gas.
Whereas the price of natural gas has doubled in the past two years and there is considerable uncertainty as to where it will go in the future, the price of petroleum coke has been stable over the past 20 years and recently has been dropping as Pemex produces it in increasing volume. Pemex has converted its Cadareyta and Madero refineries and will soon convert other refineries as well to produce lighter, lower-sulphur fuels. In producing those fuels, Pemex also produces what Robert Kartheiser describes as ‘literally mountains’ of petroleum coke as a byproduct.
TEG I is the first project financed under Mexico’s self-supply energy legislation. Current law in Mexico permits three types of privately financed IPPs:
• CFE-sponsored projects;
• cogeneration facilities; and
• self-generating facilities.
TEG I fits into the last of these three categories. Under Mexican law Cemex cannot simply take the initiative to build a plant to supply its own power, but must structure the offtake and ownership of the generating plant to comply with Mexican self-generation regulations.
In addition to 25 per cent equity from the sponsors, financing for TEG I comes from a US$75 million IDB A loan and a US$102 million, 14-year B loan priced at the following spreads over Libor: 225 basis points (bps) for years one to three, 262.5 bps for years four to six, 300 bps for years seven to 10, and 337.5 bps to maturity. ABN AMRO and Deutsche Bank arranged and syndicated the B loan. TEG is the first ‘inside the fence’ project sup- ported by the IDB. Half of the debt is covered by a comprehensive political and commer- cial guarantee from Compagnie Française d’Assurance pour le Commerce Extérieur (Coface).
Miguel Pachicano, Group Vice President of ABN AMRO in Chicago, reports that the B loan was syndicated quickly and oversubscribed. Four of the issues that lenders focused on were:
• the credit of Cemex, the offtaker;
• the technology;
• the project structure; and
• a default scenario.
As one of the fastest growing and most innovative cement companies in the world, Cemex made a positive impression in a presentation to the lenders.
The lenders required a little extra time to understand the rather complicated legal struc- ture of the project, in which the actual borrower and holder of the assets is a Mexican busi- ness trust, supervised by a master trust. That structure is dictated by the Mexican self-supply law and tax considerations.
Finally, the lenders were concerned about what would happen if Cemex defaulted and the CFE at the same time was partially or fully privatised. They did a dispatch study and concluded that the low fuel price would enable the plant to be competitive in a wholesale market.
TEG II
TEG I was followed later in 2001 by TEG II, a sister plant also sponsored by Sithe on the same site, at an estimated cost of US$330 million, less than the first plant because of economies of scale. The offtaker is Pinoles, a Mexican mining and metals company with a similarly heavy need for electricity in its manufacturing process.
According to Robert Kartheiser, Sithe’s objectives are to replicate a good project with another blue-chip offtaker for which electricity is a strategic input; to capitalise on economies of scale; and to achieve a similarly successful loan syndication. Coface will provide compre- hensive commercial and political risk insurance, and the British agency, the Export Credit Guarantee Department, will also provide political risk insurance.
Fuel supply issues
One of the most important trends with recent IPPs in Mexico has been delinking PPAs and fuel supply agreements. With Samalayuca II and Merida III, the CFE not only bought the plant’s electricity under the PPA but acted as the intermediary for the purchase of fuel from Pemex. Dino Barajas, an attorney with Milbank, Tweed, Hadley & McCloy in Los Angeles, explains that, even if the CFE did not supply the fuel, the power plant would receive its capac- ity payment to cover debt and capital costs.
Developers are now concluding PPAs and fuel supply agreements separately. The major- ity of their fuel supply agreements are with Pemex, but some plants near the northern border have US-based fuel suppliers. Further, with recent IPP ventures developers have been required to submit bids before concluding fuel supply agreements. Bidders win largely on the basis of the prices quoted in their PPAs, which are based on their best estimates of fuel prices.
Therefore a developer risks fuel price arrangements that turn out to be higher than anticipat- ed when the electricity price bid was submitted. In addition, an IPP venture now bears the risk that the CFE will dispatch tomorrow but Pemex or another supplier will not deliver the fuel.
In an article in the Journal of Structured and Project Finance(Fall 2002), John Schuster, a senior project finance credit director, and Bob Marcum, a project finance loan officer, explain that as IPPs take on increasing natural gas procurement risk, lenders tend to require lower project leverage and more sponsor support. IPPs’ fuel-supply agreements with Pemex are divided between variable or ‘swing’ supply and firm supply on a take-or-pay basis. A higher proportion of firm supply results in a lower fuel price, which helps the developer to quote a lower electricity price and win the bid, but also exposes the developer to a higher risk that the IPP will have to pay for natural gas that it cannot use. Marcum and Schuster recom- mend that Pemex consider two possible remedies to help IPPs with take-or-pay risks:
• offering different levels of take or pay for different commitment periods, for example, a 30 per cent minimum take on a weekly basis but a higher 60 per cent take on an annual basis – allowing an averaging process to work over the course of a year to the IPP’s benefit; or
• allowing IPPs, in their ongoing efforts to match fuel nomination with electricity dis- patch, to be relieved of a certain portion of their take-or-pay obligations with sufficient advance notice.
Marcum and Schuster also note that natural gas suppliers typically offer two forms of con- tractual remedies to mitigate delivery performance risks: penalties to cover lost capacity pay-
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ments; and ‘in kind’ replacement of supply, in the form of either natural gas from another source at market prices or delivery of electricity. However, according to these authors, Pemex appears to be leaning towards a third option: to provide for penalties that are equal to a per- centage of the cost of the minimum take-or-pay level of the fuel that was not delivered, based on the current fuel price. They see a potential mismatch problem with this approach. Penalties equal to a percentage of gas commodity costs may be either more or less than the plant’s lost capacity revenue resulting from a lack of fuel and failure to generate. The CFE, if willing, could help solve this problem by curtailing the plant’s dispatch when it has insufficient fuel supply. Exactly how IPPs will deal with their fuel price risk and how lenders will respond through the terms of their loans are still being determined.
Future structure of the Mexican power industry1
Since the Samalayuca II financing, one of the future contingencies that IPP project sponsors and their bankers have kept in mind has been the possible eventual privatisation of the CFE.
If the CFE was privatised and the resulting successor entity had a credit standing less than the CFE’s, a default would be triggered in most IPP loan agreements. Today, however, while bankers do not ignore the possibility that the CFE could be privatised some day, it appears to be unlikely, at least over the next few years. Since 1960 the Mexican constitution has defined public electricity services as the sole responsibility of the state power utilities.
Therefore a major change such as the privatisation of the CFE would require a constitution- al amendment, which would have to be approved by at least two thirds of Congress, and would be opposed by labour unions and the two opposition parties, the Institutional Revolutionary Party (PRI) and the Democratic Revolution Party (PRD), because of concerns including possible job losses.
After he was elected President in July 2000 Vicente Fox took up the power sector reform proposals put forward by his predecessor, Ernesto Zedillo, in February 1999 (described in the Merida III case study in Chapter 8), but with the caveat that he would not sell any state-owned electricity assets. Fox said that Mexico needed a competitive electricity market, grounded in the most advanced technology, to meet the needs of its economy. He called for reforms that would allow Mexico to guarantee its energy supply in the coming years with the greatest effi- ciency and competitive prices. He was motivated by projections showing that Mexico’s demand for electricity would grow at 6 per cent per year and that the country would need an additional 28,000 MW of installed capacity by 2010. In response, the PRI and PRD argued that there was no need to change the constitution, because under the Mexican IPP law of 1993, private companies already can generate electricity as IPPs, generate electric power for industrial use and build cogeneration plants.
Rather than fight a difficult and possibly losing battle to privatise the CFE, Fox’s gov- ernment has concentrated on efforts to make the IPP programme more attractive to develop- ers. Its recent initiatives have included efforts to develop a private bilateral contract market and a methodology for private plants to place excess power on the national grid at prices that are competitive with those of the CFE’s power plants.
Lessons learned
The case studies on Samalayuca II, Merida III, Bajio, La Rosita I and II, and TEG I and II in