Special Report: Access to Capital: Project Finance Issues Threaten Gas-Fired Power Development in Brazil

Brazil’s goal of quintupling the natural gas share of its energy mix this decade hinges on its ambitious program of installing several dozen gasfired thermal power plants throughout the country.

Official projections call for gas-fired plants to account for 18% of the Brazilian power mix by 2005 vs. less than 7% today, while hydropower accounts for all but a fraction of the remainder. Sales of natural gas in Brazil are expected to soar as a result of efforts to add an average 4,000 MW/year of power capacity for the next 10 years.

But burgeoning demand for power has outstripped the country’s ability to keep pace with capacity additions, spawning an energy crisis that persists today.

The primary hurdles to adding new gas-fired thermal power capacity in Brazil are governmental delays and regulatory bottlenecks specific to this growing component of the country’s energy mix.

After many years of ignoring the obvious signs of an impending energy crisis (a virtual lack of new capacity additions coupled with a growing economy), Brazil has found itself precariously short of power. The politicians prefer to blame it on last year’s low rainfall in critical reservoir areas, but what they fail to note-at least publicly-is that Brazil, with over 90% of its power capacity in hydro assets, has some reservoirs with S-year storage capacity One year’s rainfall (or lack thereof, in a smoothly running system, should have little or no effect.

For those of us who have been working in this area in Brazil over the past several years, the reasons for the lack of new investments are clear: Not all are due to inaction or ineffective action on the part of the Brazilian government and regulatory agencies, but a significant majority is.

There are daily challenges in the struggle to get projects financed. What follows is a discussion of some of the current issues facing investors seeking nonrecourse financing for their power projects. Some points are specific to thermal power plants, as this type of asset raises unique concerns in this primarily hydro-based country.

Risk associated with foreign exchange

Brazil’s currency has exhibited significant weakness with respect to the US dollar since the so-called “maxide– valuation” of January 1999 (77% at its worst), subsequently supplemented by a creeping devaluation that has turned out to be equally significant (38.8% since Jan. 1, 2001),

The weak currency, together with an economy suffering from, among other things, its proximity to fiscally troubled Argentina, have made financing in general quite difficult. Among the financing options in the market, the currency most available is the dollar. In a sector where it is rare to peg the final product (electric power) to the dollar-and in the case of Brazil where it is specifically prohibited-this presents a series of problems. In a weak currency environment, dollar exposure can be dangerous.

Another result of the volatile market is that long-term hedging instruments are either not available or prohibitively expensive. A pass-through pricing mechanism that has been instituted to regulate the relationship between distribution companies and their clients allows for some adjustment linked to foreign exchange rate fluctuations, but at least in the case of thermal power projects, it is generally not of a sufficient amount or frequency to cover the project’s dollar obligations.

Until recently, intrayear purchases of natural gas were completely uncovered, in that the payment obligation was in dollars but project revenues were held constant in the local currency on an annual basis. After several years of constant messages to the government that this system would not work-and several years of the government telling investors and bankers that they were being unreasonable a solution was crafted to allow gas obligations on the part of thermal projects to be held constant in local currency during the year.

It should be noted that, even if a dollar-based power purchase agreeme (PPA) were available, it would not prc vide a complete cover for foreign exchange risk. Experiences of lenders in other key emerging markets such as Ii donesia and India showed that even with revenues in dollars there can be significant risk if either the offtaker is unable to pass through to its custome all costs associated with its energy pu: chases, or if the end-user becomes problematically burdened by the final price of energy.

Credit risk of counterparties

In project finance, the strength of the offtaker is a key element. In Brazil, many of the traditional energy offtakers, the electrical distribution companies (discos), are burdened with balance sheets that do not make them ideal candidates for a project financing.

This condition is often the result of the currency and financing dynamics previously described here. Discos accessed the dollar loan market for the last few years, and now some of them are paying an unexpected price.

Another important project partner, the Brazilian construction company that is the traditional guarantor of completion and construction risk, faces challenges in getting lenders and sponsors comfortable that, in a worst case scenario, it will have the financial strength to honor penalty provisions contained within the construction contract.

Regulatory development state

Brazil, like many other countries, is in the process of reregulating its energy industry.

A decision was made some years ago that there was to be a very limited role for the state in many of the areas ol the energy sector, and the state proceeded to halt significant investments Unfortunately, however, a regulatory framework that encourages significant private investment was not developed. This is fundamental in understanding why Brazil is facing its current energy crisis.

Not only are some vital regulatory elements still in the process of being developed (a smoothly running wholesale energy market, for example), but some are quite new and yet to be tested or fully clarified (exactly how the annual adjustment on the energy tariff will work). Furthermore, some existing regulations are being selectively ignored, such as Annex 5 in the distribution concession contracts, which allows for compensation from generators in a failure-to-deliver situation (read: rationing).

In addition, there has been a general lack of following “the letter of the law” in terms of regulation-the strict observance of which would have been favorable to the industry, but a potential result would have been increased energy tariffs or an impact on inflation. As a result, the sector has lost some confidence in the strength of the regulatory system. This is problematic, because it makes it even harder to convince boards that make their companies’ investment decisions that Brazil is worth the risk.

With respect to financing, lenders are concerned about putting large amounts of capital at risk in an evolving regulatory environment with a record for selectively enforcing the framework.

Competitiveness of thermal projects

In a 90%-plus hydro system, developers and financiers of thermal projects are facing an additional challenge-the long-term competitiveness of these investments.

The country has made a strong political statement that the development of thermal power plants (in particular, natural gas-fired) is an important element in the diversification of its energy matrix.

The policy has been backed by the construction of the $2 billion, 30 million cu m/day Bolivia-to-Brazil (BTB) pipeline, and additional pipelines and expansions of existing pipelines are in the works.

Significant gas reserves have been discovered and developed in Brazil as well, which perhaps ensure even more so than the cross-border investments that thermal plants will continue to be viable.

Petroleo Brasileiro SA, the owner of the majority of the gas assets in Brazil, is a virtual marketmaker in the country, and it is difficult to imagine a situation developing where Petrobras would not have purchasers for its gas.

In any case, the primary large-scale source of gas today is Bolivia. Officially, due to the terms of the BTB pipeline financing agreements, its owner is forced to enter into contracts with its clients, the state gas distribution companies, with extremely aggressive take-or-pay or ship-or-pay obligations. (Market rumbling claims that Petrobras, the major pipeline investor, just wants to recoup its capital in an unreasonably short time).

Most projects-with some notable Petrobras-private sector partnership exceptions-have payment obligations of up to 80% of their maximum guaranteed take, even if they don’t use it. As the system is based on a unitary tariff economic dispatch, this forces thermal projects to declare themselves inflexible (and therefore to obtain baseload dispatch) to the independent system operator-or otherwise face a questionable economic future.

The question then becomes one of who is going to continue to pay for the high-priced thermal energy if there comes a time of abundant water and a resulting extended period of low– priced energy available on the wholesale market. Even the existence of a long-term, fixed-price contract with a healthy offtaker may not protect an out-of-market price producer. It leaves the project in a vulnerable position and at risk of renegotiation or breach of its energy sales contract.

Obtaining long-term PPAs

The good news is that electricity distribution companies are required by law to sign up 85% of their demand under long-term contracts. The bad news is that “long-term” is defined as a minimum of 2 years.

Thermal-and for the most part hydro as well-independent power producers with true third-party offtakers have faced challenges in executing long-term PPAs. This is due in part to the uncertainty surrounding the evolution of the long-term price of energy and the corresponding reluctance to lock in a long-term (i.e., 20 year) price of power.

Thermal projects are in a particularly sensitive situation, as part of their tariff can be linked to the dollar exchange rate, which could continue to decouple from the Brazilian currency. As the market continues to reregulate, distribution companies are concerned with their own competitiveness and need to seek out the lowest-priced sources of energy. So far, the decision to commit to long– term contracts in general has been put off. The contracts that have been signed by and large are between distribution companies and generation projects with the same owners. That’s convenient if you happened to buy a disco and problematic if you didn’t.

Due to the lack of history of the wholesale market price (the wholesale market commenced operations this year), a project without a long-term PPA selling into the pool is a difficult candidate for project finance. There are a limited number of rather high-profile “merchant” projects in the process of obtaining limited-recourse financing, but a little analysis reveals that in fact they are not exposed to any downside market risk due to an innovative arrangement with Petrobras.

ICMS and natural gas sales

A thorny issue that has been around for a long time and only now is really becoming widely publicized (due to the fact that gas contracts are being canceled) is the problem of Brazil’s ver. sion of a value-added tax, called ICMS, and the sale of natural gas to thermal projects.

The concept of ICMS is that the end– consumer pays. No one in the valueadded chain is meant to be burdened with this payment obligation. The problem with thermal projects is that they happen to be the end-consumer of gas, but in general their clients (distribution companies) are not the end-consumers of the electricity. When thermal projects are forced to pay ICMS on all purchases of gas but are unable to charge ICMS on sales to discos, a 700 MW thermal plant experiences an additional cost of $1.5 million/month in its operations– a cost that no plant can endure.

States that have signed gas contracts with thermal plants utilizing gas produced domestically (most notably the state of Rio de Janeiro) have conveniently avoided this problem as it becomes a one-state issue (gas is not moving from one state to the other), and they have deferred payment of ICMS on gas until the electricity reaches the final consumer.

States utilizing Bolivian gas have not developed a solution yet (most recently a project in the state of Sao Paulo has had its contract canceled by the local gas distribution company). Although it is often difficult to get to the root of some of these roadblocks in regulatory development, it is important to note that the first state into which Bolivian gas enters Brazil is Mato Grosso do Sul. It is said that Mato Grosso do Sul is not eager to watch a potential gold mine flowing through its state without receiving some benefit (remember, ICMS is a state tax). As soon as one state charges ICMS, the charge must be passed along down the line until the last stop (the thermal plant), with no opportunity for deferment as has been done with success in Rio de Janeiro. It is obvious that there will be a solution to this issue, but as with many of these regulatory roadblocks, the question is: How long will it take?

Lack of viable backup energy

A long-discussed issue in Brazil is how to manage the situation when a plant with energy delivery obligations is, for whatever reason, unable to honor them.

In project finance, quantifying financial obligations is essential; the project should not have an unknown (and uncovered) potential financial obligation.

One solution is to shift this risk to the side of the suppliers (i.e., in the case of fuel delivery) or the contractors (i.e., in the case of operations). The reality is, however, that these entities are generally unwilling to take unlimited risk as well. For example, in the case of Petrobras, the stated policy is a cap of $200/Mw-hr in the case of failure to deliver fuel. That sounds reasonable until one looks at the recent prices on the wholesale market from where the project potentially would have to purchase energy to comply with its obligations, and these prices have been up to $274/Mw-hr. The calculations BNP Paribas has made on projects under mandate is that, within a month, the project would potentially have to declare bankruptcy. This is obviously an untenable situation, made particularly clear given current prices on the wholesale market.

One of the interesting evolutions of the market is that there now is a potential source of a back-up energy contract: the latest large-scale entrant into the energy generation business, Petrobras. Petrobras is long in energy these days, and BNP Paribas is currently involved in discussions with the state oil company to be a provider of back-up energy for its clients. BNP Paribas is optimistic about success, because this endeavor is a win-win situation for both sides: an opportunity for further monetization of Petrobras’s assets and a vital risk-mitigation tool for projects.

Dynamics of global energy investment

It is obvious that Brazil has felt the effects from the boom of new capacity additions taking place in other parts of the world, in particular in the US. When investment opportunities in the US diminish, the impact (a positive one) will be felt in Brazil. This may occur faster than expected after the events of Sept. 11.

Last year, the author was invited to give a series of workshops to a group of individuals from Brazil’s national electric regulatory agency, ANEEL, and the Ministry of Mines and Energy, principally to help them understand why project finance was facing such challenges in Brazil.

During the first presentation, which focused on basic concepts while showing excerpts from key project contracts, the workshop sought to identify what was missing from the Brazilian scenario in order to make project finance a viable option. A participant observed that it might be a challenge for Brazil to adopt international standards. The reality, however, is that Brazil is part of the global marketplace, and it will compete with other countries in the capital-allocation decision process. Many investors faced with limited capital with which to develop projects have opted to invest their money outside of Brazil. The riskreturn ratio for Brazilian investments has been a tough sale and continues to be even for those investors that have remained extremely bullish on investments in the region.

Conclusion

Given the challenges faced by investors pursuing project finance for their energy investments in Brazil, invectors sometimes become concerned and wonder how they will persevere.

But there is sufficient scope for optimism. The fundamentals of Brazil are what were appealing in the beginning, and these have not changed. Developers currently active in Brazil consider it to be a key market due to its size, industrial base, and growth dynamics among other reasons.

After the economic crises in Asia and Russia, many investors abandoned emerging markets. Those that remain have chosen to focus on large markets where achieving economies of scale is possible and regulatory developments are favorable. Brazil continues to score well based on this criteria. The country has faced and is continuing to face significant fiscal, political, and economic issues, and it has been difficult to make a quick and painless transformation from a state-controlled energy sector to a privately controlled one.

However, we continue to work on a daily basis to see that the transformation will be successful, and we are convinced that the partnership forming among the state, the investors, the financial institutions, and all of the other participants will be the basis for a functional energy sector in Brazil in the near future.

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