Large hydropower plants currently account for around 80% of domestic electricity generation in Brazil. However, continued expansion of hydropower is increasingly constrained by environmental sensitivities. The threat of multi-year drought, the high cost of modernising or replacing ageing hydropower plants, and the growing need for more stable generation capacity has prompted successive governments to engage in a campaign of energy diversification. To this end, the Brazilian regulator Agência Nacional de Energia Elétrica (ANEEL) has undertaken a series of power auctions open to wind, solar, hydroelectric and thermoelectric projects (including gas, coal and biomass). Several gas-fired projects have successfully bid for and been awarded 25-year power purchase agreements (PPAs). Because of limited domestic gas supply, most gas-fired projects in Brazil have been structured as liquified natural gas (LNG) to power projects and reflect the requirements of the highly regulated Brazilian power market.


LNG inventory management is a key bankability issue in all LNG-to-power projects, and in Brazil, the matching of electricity dispatch notifications with LNG cargo scheduling is one of its most complex components. To guarantee power supply during Brazil’s dry season, which typically runs from May to October and during which hydropower capacity is reduced, recently awarded PPAs have different power production requirements based on the time of year. During the dry season, these PPAs require a minimum baseload power supply whereas they allow for flexible power supply during the rest of the year.

While predictability of dispatch during the baseload period makes regular rateable LNG deliveries possible, some recent PPAs impose strict “day ahead” dispatch notifications during the flexible period, and power plants are only required to be dispatched if nominated by Operador Nacional do Sistema Elétrico (ONS), the Brazilian generation and transmission systems coordinator. ONS will usually nominate a power plant if its variable cost of operation is below the electricity spot price. Thus, LNG cargo scheduling during the flexible period relies on the ability of independent power pro- ducers (IPPs) to accurately anticipate dispatch notifications. This can be achieved to some extent by processing water reservoir levels data, forecasting electricity spot prices and reviewing weather patterns.

Under the current regime in Brazil, penalties and fines imposed under the PPAs for failing to produce power when nominated by ONS are particularly severe, so perfecting the scheduling model is of paramount importance for a project. These issues are exacerbated for projects structured with a floating storage regasification unit or a floating storage unit due to the restricted storage capacity.


There are limited mitigants available to an IPP if it fails to dispatch power due to a fuel shortage after being nomi- nated by ONS. With ONS’ consent, the IPP may use a third party’s power plant to comply with its obligations under its PPA. Although there will be no penalties or fines for a permitted power substitution, the price the IPP receives for electricity produced will be less than the PPA price. An IPP may also use energy credits gener- ated when selling spot power to offset against future penalties. These energy credits are intended to compensate for the water that would otherwise be used by hydropower plants to produce an equivalent quantity of power, but if water reservoirs overflow due to higher-than-expected rain falls, no energy credits will be produced. Power plants may only sell electricity on the market and accumulate energy credits if they are not nominated by ONS. The potential unavailability and unpre- dictability of energy credits must be considered in the bankability analysis.


LNG-to-power projects in Brazil offer unique upside opportunities for dif- ferent players in the chain, including international oil companies (IOCs). IOCs are increasingly willing to take equity interests in projects, typically in exchange for the exclusive right to provide the fuel supply for the power plant. Risk allocation between the participants is typically structured as a buy/sell model or tolling model. In the case of LNG-to-power projects with baseload and flexible dispatch periods, risk allocation may also, in certain circumstances, take a hybrid approach with a buy/sell model adopted during the baseload period and certain features of a tolling model adopted during the flexible period.

LNG-to-power projects are likely to continue attracting investments for large scale generation capacity. These projects offer unique upsides to the participants but require detailed bankability analysis considering the strict regulatory regime imposed
on IPPs.

In fact, LNG sale and purchase agreements (SPAs) may be structured to allow the LNG supplier to dispatch power when the power plant is not nominated by ONS (i.e., outside of the baseload period, provided no order-of-merit or out-of-order-of- merit notifications have been issued by ONS). This structuring permits the LNG supplier to use the power plant as a platform to arbitrage between fuel indices and spot electricity prices and participate in a broader set of trading activities. In addition, SPAs may grant the LNG supplier the right to provide LNG or gas to the project thereby broadening the scope of arbitrage opportunities.

The right to provide alternative forms of fuel is part of a longer-term strategy of the suppliers to realise upside linked to supplying cheaper domestic pipeline gas coming from pre-salt fields or neighbouring countries (e.g., Bolivia) or grid gas. However, Brazilian law imposes certain country specific taxes on LNG importation, which may affect the alignment of interests between the LNG supplier and the LNG purchaser (i.e., the project company) because the LNG purchaser is typically liable for domestic taxes in SPAs.

In order to meet the growing domestic electricity demand and the country’s baseload power needs, LNG-to-power projects are likely to continue attracting investments for large scale generation capacity. These projects offer unique upsides to the participants but require detailed bankability analysis consid- ering the strict regulatory regime imposed on IPPs and the somewhat unusual risk allocation.

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