Open the pages of a Brazilian broadsheet and it is rare nowadays not to find an article on the ?apagão? ? the Brazilian energy crisis. Although the demand centres of São Paulo and Rio de Janeiro are bearing the brunt, electricity rationing in Brazil is affecting everyone, from the micro-economic effects on companies and consumers, to the adverse macro-economic effects on the Brazilian economy.

The writing has been on the wall for some time. Brazil's 92% hydro-dependent electricity market has been seriously undermined by low precipitation over past years, while the inauguration of the Brazil-Bolivia natural gas pipeline in 1999 and increased natural gas-harvesting from Brazil's Campos Basin, failed to energise the much hoped development of gas-fired IPP's.

Brazil urgently needs more electrical capacity and the government is pinning its hopes on gas-fired thermoelectric projects to provide it under the guise of the ?PPT? ? the Thermoelectric Priority Programme. The PPT targets the construction of approximately 50 thermoelectric plants by the end of 2003 and the open-cycle operation of approximately 3000MW of gas-fired generation by the end of 2001. Although the time-frame for achieving the PPT's objectives is undoubtedly ambitious, there has been unprecedented IPP development progress in Brazil over the past 12 months which should see the open-cycle generation goal realised during 2002. An analysis of project sponsors and the project risk allocation models being utilised by them, is pivotal to understanding how such progress has come about.

Power projects currently being developed in Brazil demonstrate that there is a general correlation between those companies forming the sponsor consortium and the project risk allocation model adopted. Three general sponsor classifications can be made, namely: (i) consortia comprising Petrobras, (ii) consortia comprising a Brazilian regional distribution company, and (iii) consortia comprising neither of the above. Three differing project risk-allocation structures are being used, namely energy conversion or ?tolling?, traditional PPA and merchant. Generally, consortia comprising Petrobras tend towards the energy conversion or ?tolling? model (with a ?merchant? element for excess power), consortia comprising a regional distribution company tend towards the traditional PPA model while consortia comprising neither Petrobras nor a regional distribution company have generally adopted the merchant model.

It is not surprising that those consortia comprising Petrobras have tended towards the energy conversion or ?tolling? model. In an attempt to ensure that power demand is met, the Brazilian Federal Government has authorised state-owned Petrobras to participate, either as shareholder, offtaker or both, in a number of strategically important thermoelectric power projects. Such move into the electricity market is consistent with the trend of other major oil and gas companies. Given that Petrobras' contract for the purchase of natural gas from the Brazil-Bolivia pipeline is on a take-or-pay basis and that Petrobras will need to ensure a guaranteed supply of power for the continued operation of its refinery operations, Petrobras' participation in the PPT promotes a natural hedge for its business activities. Those projects comprising the PPT open-cycle generation target (many of which will come on line in 2002) are dominated by consortia comprising Petrobras and the energy conversion or ?tolling? structure.

Turning now to a broad overview as to how each of the risk-allocation models has faired as a development platform during 2001, substantial and rapid progress has been achieved through the energy conversion or ?tolling? model, which looks set to remain on centre-court for some time to come. The 420 MW Termobahia (Petrobras tolling) project and the 470 MW Araucária (Copel tolling) project are two of the front-runners in the race towards financial close, with the 705 MW Ibirité (Petrobras tolling) and 460 MW Cubatão (Petrobras tolling) projects biting at their heels. A good deal of progress has also been realised through the merchant model with Enron's Eletrobolt and El Paso's Macaé Merchant projects, although both are affected by the ongoing suspension of trade accounting at the Brazilian electricity wholesale market (see 3(c) below). Although the traditional PPA model has been slower to progress, the 945 MW Carioba PPA executed with São Paulo regional distribution company CPFL, is a landmark achievement. EDF's Norte Fluminense project, with Rio de Janeiro based Light as offtaker, may soon follow suit. Other PPA-based projects under active development tend towards fossil fuels (avoiding some of the pricing issues associated with natural gas in Brazil) and include the 1000MW coal-fired Sepetiba Bay project being sponsored by EnelPower, and the 630MW fuel oil project being developed by PSEG and Petrobras.

Although natural gas-fired IPP development has achieved real momentum in Brazil, a crucial observation must be made. Those sponsors wishing to arrange non or limited recourse financing have to date undertaken substantial construction on an equity basis prior to reaching the Lenders' negotiation table. This is likely to be a feature of IPP development in Brazil for the foreseeable future owing to the continued existence of a number of critical legal and commercial impediments which are now coming more clearly into focus at the international lender level. These are discussed below.

Power developers have traditionally had a tough time in Brazil; the reason lies in the complex web of their inability to pass-on foreign currency costs of developing new generation, the reluctance of regional distribution companies to sign long-term PPA's, an electricity regulatory system struggling to find its feet in the wake of rapid privatisation in a country with little regulatory tradition, and the stranded-asset risk inherent in developing a gas-fired project in a hydro-dominated system.

(a) Brazil is unique. Approximately 92% of its existing power matrix consists of hydroelectric plants, and Brazil's Ministry of Mines and Energy targets that natural gas-fired thermoelectric generation will eventually account for 15% of such power matrix to ensure the reliability of the overall system. However, the cohabitation of natural gas and hydro generation is not easy to reconcile. The project cost and lead-time for constructing a hydro plant in Brazil has generally reduced since privatisation of the Brazilian electricity sector in 1996, and this is particularly true of mini hydro plants or PCH's. Also, hydro plants can be financed in local currency, whereas their natural gas-fired cousins will typically require between 50 and 60% financing from foreign lenders and will be forced to grapple with a US Dollar-based gas price. Such factors take on increased significance in Brazil, where the ability to index (Reais) revenues to foreign currency costs is limited under law (see (b) below). Such issues increase the time and cost of the development endeavour, and results in hydro power being cheap when compared to power produced by natural gas-fired plants. So what are the implications for plant despatch?

Hydro plants are despatched centrally by the Brazilian National System Operator (the ONS). Those hydro plants not despatched are protected under the Energy Reallocation Mechanism which guarantees a payment for firm energy, effectively transferring energy generated by those hydro plants having excess water to those hydro plants having insufficient water for despatch.

Turning to natural gas-fired projects, the structure of the natural gas industry in Brazil generally requires that natural gas be sold to IPP's through regional gas supply companies. The take-or-pay requirements in these contracts will typically mirror the upstream gas supply agreement entered into between the regional gas supply company and Petrobras. In order to mitigate the IPP's fuel supply take-or-pay liabilities which could arise from non-despatch, the ONS is granting natural gas-fired IPP's an ?inflexible? or ?must-run? status to cover such fuel take-or-pay requirement. However, the precise mechanics for natural gas-fired plant despatch are not as well developed as those for hydro plant and have yet to be clearly elaborated at the regulatory level. More clarification on this aspect by ANEEL, the Brazilian electricity regulator, would be a welcomed intervention, with particular focus on how the gas-fired plant ?inflexible? despatch mechanism will work in times of power surplus with the cheaper hydro power price driving the market. Is it still contemplated that more expensive gas-fired plant will be despatched to its ?must-run? level with cheaper hydro plant lying idle?

In summary then, subject to clarification from ANEEL, the cohabitation of hydro plant and gas-fired plant brings with it the potential for stranded asset risk as against the longer-term power surplus price risk ? a key factor in the reluctance of Brazilian regional distribution companies to sign long-term PPA's1.

(b) As projects have progressed towards the financing stage, a major stumbling block for lenders and developers alike has been the currency mismatch between project company revenues from energy sales (denominated in Reais), the cost of natural gas (US Dollars-based), the cost of equipment (partially foreign currency denominated), the cost of debt service (predominately foreign currency denominated) and the inability under Brazilian law to adequately index the power purchase contract tariff to cushion against such foreign currency exposure. A fundamental part of Brazil's anti-inflationary Real plan, provides that contractual price readjustment may occur once annually. Mechanisms which produce financial effects equivalent to more frequent adjustments to price are expressly prohibited by law. In a PPA or Energy Conversion Contract, therefore, the project company is potentially exposed to intra-year currency risk which may have the effect of rendering the project company unable to meet mandatory cover ratios or even debt service repayments.

In order to address the project company's intra-year foreign currency exposure to natural gas price, the Brazilian Federal Government created, in June of this year, a tracking account for gas price variations applicable to PPT projects. Under such mechanism, the gas supplier absorbs foreign currency movements until the price readjustment date under the gas supply agreement, at which point a compensation amount is calculated and passed-through to the project company. Such mechanism would operate for 12 years, coincident with debt tenors typically being offered by multilaterals and ECA's. However, it is likely that the project company would still bear some currency risk at the end of the year under its power purchase arrangements due to the indirect impact on power purchase price caused by the ?valor normativo? ? the incentive regulation price cap for electricity sales applicable to Brazilian regional distribution companies (see below). ANEEL, the Brazilian electricity regulator, has been authorised by the Ministry of Mines and Energy to construct a similar mechanism which could be applied to intra-year currency movements under a PPA or Energy Conversion Contract, however a proposal has yet to materialise.

Given this background, Brazilian lawyers are constructing creative ?cost-plus? mechanisms to simulate the effects of linking tariff to foreign currency costs, albeit within the parameters of Brazilian law. However, as one might expect on such a difficult issue, legal opinion as to the viability of such mechanisms is diverse, and intervention from ANEEL as to a preferred mechanic is encouraged.

Intra-year currency indexation is only part of the ?foreign currency exposure? issue. Electricity distribution in Brazil is regulated by the ?valor normativo? or ?VN? ? an incentive regulation mechanism which limits the distribution company's ability to pass through to the distribution tariff those costs incurred in purchasing electricity for resale. Every long-term electricity offtake contract executed by a distribution company must be registered with ANEEL, at which point a VN will be assigned to it. The VN remains in force for the life of the offtake contract and is readjusted annually based on an index comprising Brazilian inflation (IGP-M), oil prices and foreign currency exchange rate variations. Although the distribution company has some latitude to assign different ?weights? to each of the above factors at the time of ?setting? the VN with ANEEL, at least 25% of the VN index must by law correspond to the domestic inflation index ? IGP-M. The upshot of this is that only a maximum of 75% of foreign currency costs may be passed through to the distribution tariff. This restriction is likely to have an important impact on the tariff acceptable to a distribution company under a project company's power offtake arrangements and may leave the project company exposed for those foreign currency costs not absorbed by the distribution company. This is a significant impediment to raising foreign currency financing.

International lenders typically require a project company to guard against currency devaluation by transferring project revenues to offshore accounts secured in their favour. However, stringent Brazilian Central Bank regulations only allow payments offshore in accordance with previously registered loan agreements. Unless a project company is willing to pay debt service more frequently than the customary semi-annual basis, significant Reais revenues will be trapped on-shore and, therefore, subject to devaluation, convertibility and transferability risks.

Given this state of affairs, the Central Bank has established the US Dollar denominated ?2644 Account? (named after its founding regulation). The 2644 Account allows those Reais revenues earmarked to repay US Dollar denominated costs, to be converted into US Dollars and held on-shore pending the required payment date, thereby mitigating devaluation risk.

Although the 2644 Account was established to facilitate international financing in the electricity and oil sectors, it is a relatively new device in need of regulatory clarification by the Central Bank. For example, it is generally accepted that project company revenues from power sales can be deposited into the 2644 Account and converted as appropriate, however a question mark remains as to whether the 2644 Account can be used for a lump-sum early termination payment made under a PPA or energy conversion contract ? a critical lender issue. Now is a timely moment for the Brazilian Central Bank to provide guidance on this issue.

Quite apart from the above, international lenders are still coming to terms with the concept of on-shore foreign currency accounts (with their attendant convertibility and transferability issues) versus the more traditional offshore account structure customarily associated with non or limited recourse financing.

(c) The Brazilian electricity sector privatisation model is essentially based upon the former UK electricity pool. The wholesale electricity market, or Mercado Atacadista de Energia (MAE) as it is known, was launched in September 2000 and spot-market transactions commenced shortly thereafter.

Quite apart from the vagaries surrounding future plans for despatch of plant examined in (a) above, there are a number of MAE procedural lacunae waiting to be addressed by the MAE Rules and Procedures which, at the time of writing, are still works in progress. The absence of detailed Rules and Procedures has given rise to some regulatory uncertainty, particularly over the financial settlement of spot market transactions. The accounting of transactions at the MAE was suspended due to injunctions obtained by regional distribution companies shortly after its inception. At the date of writing, the accounting of transactions at the MAE remains suspended with uncertain future implications for merchant plant.

(d) Brazilian taxation applicable to IPP's is extremely complex, owing to the intricacies and interplay of both State and Federal taxes. Although an analysis of such taxation is beyond the scope of this Article, I will consider briefly the state sales tax known as ICMS, since it continues to present important issues for sponsors wishing to raise non or limited recourse financing.

Equipment and fuel purchases as well as services provided to a project company will generally attract ICMS. Certain states such as Santa Catarina have indicated their willingness to provide ICMS ?holidays? for equipment purchases, however these are in the minority. After paying ICMS, the project company is granted a corresponding credit, however since the ICMS on energy sales across a state is deferred to the final consumer, the project company is unable to utilise such credit against any ICMS it might otherwise have received on energy sales. It is possible in Brazil to sell ICMS credits to third parties, however, this is difficult to structure in practice and is generally done at a discount. To mitigate the issue, developers are approaching State authorities on a project-by-project basis to seek ICMS relief.

Current ICMS legislation, therefore, creates no incentive for a State to be supportive of the IPP programme (since the State receives no ICMS revenue from energy sales) and increases the cost of developing an IPP significantly.

After much promise but little action for so long, IPP development in Brazil is now firmly on the map. Significant progress has been made over the past year and is set to accelerate into 2002 which should see a number of IPP's reach financial close. Although the Brazilian Government's pro-active approach to the electricity crisis has been impressive to date, some critical issues remain to be addressed and this Article has attempted to articulate some of them.

Each of the tolling, PPA and merchant risk allocation models appear to be a credible development platform for Brazilian IPP's, although the MAE will need to resume accounting of trading to stimulate further merchant activity. The energy conversion or ?tolling? risk allocation structure is currently dominant due to Petrobras' unique position as fuel supplier and the ability of that risk allocation model to overcome those issues explained in this Article.

The Ministry of Mines and Energy has recently established Comercializadora Brasileira de Energia Emergencial (CBEE) ? a special purpose state-owned power trading company established to enter into electricity offtake contracts to further stimulate IPP development. It is not yet clear to what extent CBEE may offer state-backed payment guarantees to contract counterparties. However, although CBEE has not, as at the date of writing, entered into a long-term power offtake contract, it will be interesting to chart the progress of CBEE throughout 2002 and assess its overall impact on the PPT. n

Footnote

1 Regional distribution companies are subject to the requirement that at least 85% of their demand must be contracted under PPA's with a term of at least 2 years.

Julian Nichol, Senior Associate specialising in energy project finance at Clifford Chance Rogers & Wells, São Paulo, Brazil (Julian.Nichol@cliffordchance.com) advising on a number of power projects forming part of the PPT. I am grateful to my colleague Paula Rios for researching aspects of this Article and colleagues Stephen Hood, Jaime Areizaga and Adrian Calvert, as well as David Nicoll, President of Frentex Incorporated, for their comments on this Article.