Survey of Energy Resources 2007
A Typical OTEC Design
To put this into perspective, consider a specific design for an OTEC plant. The example described is a 10 MW closed cycle floating OTEC plant, for application in a specific Caribbean or South Pacific island site. It was initially designed in the mid-1980s and has been progressively updated. Landed costs for fuel oil in these islands can be 75% higher than in mainland locations - US$ 50+/bbl rather than the US$ 30/bbl which has typified continental prices over the last decade - although in 2006 prices were double the latter figure.
Power generation is provided by two of the three 5 MW power 'pods'. The concept recognises that, as a 'demonstrator plant', reliability will be lower than for a production plant, and the third power pod is included both for development work and as a standby for times when a production pod is out of use either for regular service or an unscheduled outage. The two sites chosen have the cold deep resource close to shore - in the Caribbean the 1 000 m depth being no more than 2.5 km from shore, and the minimum measured temperature difference between the surface and that depth being 21oC, increasing to 23oC at the warmest time of year. The 21oC difference is used as the basis for calculation, which results in an overall efficiency of 2.7%. This compares with an efficiency value for diesel fuel power plants of 25-35%, and values at the upper end of that range for a modern fossil-fuel power station.
Specific costs of individual components were calculated, and used as the basis for total capital, and then derived generating costs, the latter incorporating all operating, maintenance and insurance costs in addition. Contingencies were assessed, with the cold water pipe having the lowest confidence level - but with component replacement techniques included.
Total estimated cost for the plant, in 2006 dollars, incorporating the target costs for components as a basis, is US$ 115 million which, depending on the contingencies, could increase by as much as 25% or decrease by up to 13%.
A discount rate of 5% was used, on the basis that this demonstrator plant was akin to a public sector project. Although the design life of the plant was 25 years, payback was taken as 10 years - a stringent assumption, with interest charged at 11%, which with present lower levels of interest rates worldwide, may also be unduly harsh. Annual inflation rates were assumed at 5% and again this is possibly pessimistic in the present industrial climate.
Availability of the plant was assessed at 90%. This would be high for a normal demonstrator, but here the third pod is available as standby. The resulting calculated generating cost was 21 cents/kWh, with no allowance for potable water production since, as a floating plant, desalination can only be provided as a by-product of electricity generation. However, if the price of water is high enough, a financial credit will be obtained. Using the PICHTR calculations as a basis, the generating costs for this 10 MW-sized plant would fall from 21 cents/kWh by approximately 4 and 7 cents/kWh respectively, to 17 and 14 cents/kWh, corresponding to potable water credits of 40 cents/m3 and 80 cents/m3. Since potable water in Pacific islands can cost from 40 cents/m3 up to US$ 1.60/m3, the generating cost of 14 cents/kWh - corresponding to a water credit of 80 cents/kWh - is considered realistic.
Other potential by-products, described earlier, are ignored because the quantities needed here are small when compared with those available from the OTEC/DOWA plant, and initially will have only a small influence on the overall economy, although the human benefits of these by-products to a population may well be considerable. In the present calculations, therefore, no benefit is claimed for these by-products in terms of reduced generating costs for electricity from the OTEC plant.
The remaining economic item to consider is 'environmental benefit' - or put the other way, the proposed 'Carbon Taxes'. Such taxes would clearly benefit a renewable energy system, such as OTEC. The proposed levels of such a tax have varied considerably, from as little as US$ 3/bbl to as much as US$ 13/bbl, which would result in a likely 'effective benefit' further to decrease OTEC/DOWA generating costs by between 0.5 and 3 cents/kWh.
All these calculations have been for a demonstration plant. On the assumption that, without any benefits of major re-design, but with operating experience to refine detail design, manufacture and operation, the overall improvement in the system for the eighth production 10 MW floating plant is calculated to achieve a significant 30% reduction in electricity generating cost; that is to 14.7 cents/kWh for the basic OTEC plant, and to 11.9 and 9.8 cents/kWh respectively with water revenues at the levels of 40 cents/m3 and 80 cents/m3.
Whilst these generating costs are now competitive for a number of island sites with conventional sources for electrical power generation, the OTEC plant must also be attractive to the utility that is to operate it. For the 10 MW plant described here the rates of return are 20.4% (nominal) and 14.7% (real), which are reasonably attractive in terms of accepted commercial practice.
For this demonstration plant, the prospects for both plant operator and the consumer of electricity are looking genuinely competitive, a significant change from the situation just 10 years ago. On a simple costing basis OTEC is becoming economically attractive, with its DOWA and environmental benefits as a bonus, over and above the base economic case.