Elsevier

Energy Policy

Volume 37, Issue 4, April 2009, Pages 1580-1584
Energy Policy

Does Brazil need new nuclear power plants?

https://doi.org/10.1016/j.enpol.2008.12.020Get rights and content

Abstract

In October 2008, the Brazilian Government announced plans to invest US$212 billion in the construction of nuclear power plants, totaling a joint capacity of 60,000 MW. Apart from this program, officials had already announced the completion of the construction of the nuclear plant Angra III; the construction of large-scale hydroelectric plans in the Amazon and the implantation of natural gas, biomass and coal thermoelectric plants in other regions throughout the country. Each of these projects has its proponents and its opponents, who bring forth concerns and create heated debates in the specialized forums. In this article, some of these concerns are explained, especially under the perspective of the comparative analysis of costs involved. Under such merit figures, the nuclear option, when compared to hydro plants, combined with conventional thermal and biomass-fueled plants, and even wind, to expand Brazilian power-generation capacity, does not appear as a priority.

Introduction

Power-generation projects should not be chosen under political or commercial pressures, such as is sometimes the case, but, rather, through judicious scrutiny based on comparisons between available alternatives, in considering the environmental impact, the possible exposure of the population to the risk of accidents, the foreseeable deadlines for the start of the operation, the guarantees regarding fuel supply (gas, oil, etc.), and whether there is enough large-scale industrial capacity for the enrichment of uranium and the manufacturing of fuel, in the case of nuclear power plants. Finally, but no less important, one must be aware of the costs, upon which the tariffs are based, to be paid for by the consumers.

In this article, we will discuss the aspects that intervene in the formation of the production costs of electricity. Power-generation costs are composed of part made up by fixed costs, from which the invested capital is recovered and repaid throughout depreciation lifetime of the generating power plant; and of another part made up by variable costs, composed of the expenses that are required to operate the plant. The fixed part (invested capital) includes expenses incurred in the implantation of the power plant (feasibility studies, engineering studies, equipment, preparation of the site, construction work, assembly, tests and commissioning), while the variable part is comprised of operation and maintenance expenses, insurance, taxes, salaries, overhead, etc., as well as fuels, in the case of thermal power plants.

The final costs (the sum of the fixed and variable costs) should be calculated in such a way as to allow for the setting up of tariffs that ensure return; i.e., both attractive to investors and fair to consumers. Hence, to keep the profits of the investor (or utility) from sacrificing the consumers, the internal rate of return (IRR) used to calculate the generation costs should be established by means of negotiations between the regulatory body and the utility or through tender bidding process to secure supply from investors, into which enter subjective criteria, such as “attractiveness” to the utility or investor and the “reasonability” to consumers. That is why there is an ethical imperative for the process to be completely transparent.

In practice, the internal rate of return reflects the opportunity cost of capital, i.e., the potential benefit that could be accrued from its allocation to next best alternative investment (Bitu and Born, 1993; Viscusi et al., 2000).

In capital-intensive projects, such as those of power sector, the main cost components are the amortization of the investment (cost of capital) and the cost of the fuel, when applicable. All other components (operational expenses, insurance, taxes, wages, etc.) have a less-intense effect. However, as the project approaches in the end of the accounting depreciation term, the importance of these expenses grows in comparison to the cost of capital.

The lifecycle of hydroelectric power plants surpasses the accounting depreciation term, which is conventionally set at 30 years. Hence, power plants that have already been paid off continue to generate energy at a cost that is reduced to the operational and maintenance expenses, insurances, wages and labor taxes. There are hydroelectric plants that were implanted in the beginning of the 20th century that continue to operate normally to this day, which is of great advantage to society, since people continue to benefit from the service without the burden of a new investment.

For coal-based thermoelectric plants, the cost of the fuel does not include the investments that must be done in the regions from which coal is extracted, to alleviate the environmental impacts (the contamination of rivers and water tables, air pollution, damage to public health, etc.). The environmental impacts of thermoelectric plants using natural gas—which are of considerably less importance than the coal-based plants—are also not computed in the cost of the power generated.

The fuel cost for nuclear power plants is made up of the sum of the costs of each of the steps in the uranium cycle, which ranges from mining up until the manufacturing of the fuel rods. In this composition, the most expensive stage is that of enriching the uranium, which comprises 36% of the costs. The impact of the cost of the uranium (U3O8) is around 27%.

The accounting depreciation term of nuclear power plants is equal to their shelf life (40 years, after which the plants must be decontaminated and decommissioned.

Decommissioning expenses should be brought to present value and included in the generation costs, so that a fund can be created with sufficient resources to cover those expenses. In Great Britain, for example, the government attributed a budget endowment of £2.47 billion (US$4.34 billion) for the term of 2007/2008 to the public organ that is responsible for decommissioning nuclear plants (Nuclear Decommissioning Authority).1 Other components of the cost of nuclear power generation are the management of low- and medium-level waste, and that of the final disposal of high-level radioactive waste.

The facts show that planned costs of nuclear energy were optimistic when compared to actual costs for completed plants. As an example, the cost for the first new-generation pressurized water reactor that Areva, (French nuclear construction company) is building in Finland, is 50% higher than originally estimated (Rienstra, 2008). A recent assessment carried out by United States Congressional Budget Office (CBO, 2008) recognizes that “CBO's assumption about the cost of building new nuclear power plants in the United States is particularly uncertain because of the industry's history of construction cost overruns. For the 75 nuclear power plants built in the United States between 1966 and 1986, the average actual cost of construction exceeded the initial estimates by over 200%. Average overnight construction costs soared from projected 938 to actual 2959 US$/kW. Although no new nuclear power plants were proposed after the partial core meltdown at Three Mile Island in 1979, utilities attempted to complete more than 40 nuclear power projects already under way. For those plants, construction cost overruns exceeded 250%. The Federal Energy Regulatory Commission Office of Enforcement developed assessment of likely electricity costs in the coming years (FERC, 2008). In 2003–2004, its estimates for the capital cost for nuclear power plants ranged around 2000 US$/kW, whereas revised figures soared to 5000–8000 US$/kW. Two recent nuclear procurements in South Carolina and Georgia produced cost estimates of $5100 and $6400/kW, respectively, for the same Light Water Reactor technology. The reasons for the increase in building costs of nuclear power plants include rising global prices for materials, labor costs, the need to bring in additional safety requirements and the soaring cost of nuclear clean-up and waste disposal. These facts seem to indicate the possible existence of “negative learning curve” for nuclear plants, which may further harm its ability to compete with newcomers to the energy industry like wind and solar options.

For both the hydroelectric plants and the nuclear and thermal biomass and fossil fuel plants, the premiums paid to insurance companies are, on average, around 1% per year of the invested capital or of the insured amount.

In this article, we compute only bus bar cost of individual plant options, without quantifying synergies deriving from system integration. Thus, they do not take into account benefits such as secondary power from hydroelectric plants that allows for savings of fuel in complementary thermoelectric plants using natural gas, oil, biomass or even wind, all of which result from possible optimization in planning and operation in the framework of interconnected national power system.

The development of wind energy in Brazil is still in its initial stages when compared to energy from other sources. That is why wind energy is not explicitly included in the scope of the article. However, it is worth pointing out that based on surveys already conducted by the Brazilian Center for Research in Electrical Energy (CEPEL). Brazilian estimated potential exceeds 143 GW, especially along 8000 km of Atlantic coastline (EPE, 2006). The wind patterns seasonally complement the hydro patterns, in such a way that the capacity factor of the wind energy system could reach a level of, approximately, 20%, higher, therefore, than the average for systems of this kind. The cost for capacity contracted under the PROINFA (Alternative Energy Sources Incentive Program) has ranged from 107 to 137 US$/MWh 2 (MME, 2007). Learning and scale gains are expected to further reduce costs and enhance chances of wind power to compete, especially with the nuclear option.

These conditions would further favor the interconnection of the entire Brazilian electrical system in a grid of water–thermal–wind energy, similar, to a certain extent, to the thermal-wind grid that is being studied in some European countries (Ummels et al., 2008).

Section snippets

Power-generation cost of the Angra III nuclear plant project

According to the Brazilian Nuclear Power Company, Eletronuclear, the Angra III plant will cost a total of US$4.66 billion (R$7.91 billion) of which US$330 million (R$560 million) have already been invested in the acquisition of the main mechanical components of the nuclear steam supply system (reactor vessel, pressurizers, steam generators, main coolant pumps and support structures) and some of the main components of the secondary circuit, such as the turbo-generator group, the main water

Natural gas power plants’ generation cost

Calculations were performed for a typical combined cycle power plant of 500 MW capacity. The term for construction is of 36 months and the direct cost of the power plant amounts to US$1000 per installed electrical kW.

We have considered the thermodynamic efficiency of the system to be 50% and that the calorific value of the gas supplied to the power plant is of 36.8 MJ/m3 (8800 kcal/m3), thus the consumption of natural gas will be of 122.15×103 m3/h.

We also consider that the capacity factor will be

Coal power plants’ generation cost

Due to great demand, the investment costs in coal-based power plants have increased rapidly. For example, in China alone one coal-based thermal power plant is constructed every week (Harrabin, 2007). In Europe, in the United States and in Australia there are strong interests linked to coal-based thermoelectric plants, especially after considering the development of capture and CO2 capture and storage technologies (Thambimuthu, 2008). Nevertheless, even if a technically safe and economically

Biomass power plants’ (sugarcane bagasse) generation cost

Although sugarcane bagasse market is still incipient, among other reasons due to logistic costs and absence of infrastructure, prices average around US$15/t. Sugarcane harvest season extends over an 8-month-period, usually from April to November, in Brazilian Southeast, and nicely complements the rain season that usually spreads from November to April. Hence, in principle, plants using bagasse can operate with a capacity factor of 60%, and in synergy with the hydroelectric power plants, all

Hydroelectric power plants

Table 2 summarizes the Brazilian hydroelectric potential. Table 3 shows that the largest part of the non-exploited potential can be found in the Amazon. Large part of this potential can be technically and environmentally tapped, especially if appropriate regulatory framework and negotiation processes required to overcome social and environmental questions are implemented. Aside from the large-scale hydropower plants, there are also the small hydroelectric plants, whose combined potential is as

Power-generation costs of Santo Antônio and Jirau power plants on Madeira River

The Santo Antônio and Jirau hydropower projects are good examples of the not yet exploited potential in Brazil. As such, we can consider the power-generation cost of these power plants to be the representative cost of the large part of the remaining potential of Brazilian hydropower plants, having an estimated capital investment cost of around US$1600 per installed kW (Table 4). Assessments indicate that up to 75 GW of additional capacity could be developed with investment cost of up to 1500

Final remarks and conclusions

The extension and the perspectives for making use of Brazil's hydropower potential in the short, medium and long term, combined with thermal, biomass and wind complementation, lead to the conclusion that the program to build new nuclear power plants announced by the Brazilian Government is not a priority.

The country, therefore, has practically no need for large-scale thermal power plants, since, as shown above in Table 2, the hydropower potential is of 261.1 GW, of which merely 71.2 GW (or 27.3%

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