Utilities traditionally have met renewable portfolio standards with power purchases from IPPs. But new approaches are allowing utilities to build their rate bases with investments in solar...
PV vs. Solar Thermal
Distributed solar modules are gaining ground on concentrated solar thermal plants.
requirements will increase the regulatory risk of the project and potentially lead to construction delays and higher costs.
Another critical issue is water, or rather a lack of water. The steam turbines used at CSP plants require water for cooling; using wet cooling towers, the proposed APS/Abengoa 280-MW CSP generating facility can be expected to consume between 600 million and 700 million gallons of water, roughly 1,900 acre-feet, per year. But in the desert Southwest, available water resources are becoming more scarce, as populations continue to grow. There are virtually no additional surface water supplies available and groundwater recharge rates are so slow as to make groundwater supplies effectively fixed. 8
While several conventional thermal- generating facilities use treated wastewater from nearby urban areas, it is doubtful that this approach could be adopted for all of the proposed CSP generating plants in the desert Southwest. Moreover, treating and piping wastewater to far-flung CSP plants in the desert will add significant costs. As a result, CSP plants likely will require dry-condenser cooling—which minimizes water use, but does so at a significant cost, in the order of $200/kW by some estimates. 9 Furthermore, dry-cooling reduces both net generation and thermal efficiency, especially on the hottest days of the year, when summer-peaking utilities most need power. The loss of efficiency in a steam plant with a state-of-the-art dry-cooled condenser can be as high as 25 percent on very hot Southwest summer days. This reality will affect the economics of CSP plants as Black & Veatch recognized in a report prepared for the Renewable Energy Transmission Initiative (RETI) in California. 10
Black & Veatch estimates that if the Gila Bend plant were dry-cooled, it could cost between $50 million and $60 million more to build, and would produce less electricity at a higher cost than currently expected. And a recent EPRI feasibility study for central-station solar power estimates power from a utility-owned 125-MW dry-cooled solar-trough plant (located in New Mexico and without molten salt storage) will cost between 24 and 26 cents/kWh, including the 30-percent federal investment tax credit. 11
CSP technologies (including central solar receiver, linear Fresnel concentrator, and parabolic dish Stirling cycle) pose a number of other technical and financial risks. For example, parabolic dish Stirling engine technology lacks manufacturing capacity or commercial operation experience, although a leading manufacturer has signed between 800 MW and 1,750 MW in long-term power purchase agreements for commercial development. This suggests that building these plants will require the manufacturer to abbreviate the technology development stage and move straight into manufacturing and commercial operation, skipping manufacturing optimization or operational pilot-plant stages. How such a strategy will work in practice remains uncertain, but the effort likely will show the strengths and weaknesses of the latest CSP technologies.
PV Catches Up
PV technology also is advancing as a result of significant utility commitments.
Although announced with much less fanfare, Southern California Edison plans to install 250 MW of commercial rooftop PV at an estimated cost of $3,500/kilowatt (2008 dollars). This figure reflects an accelerating price differentiation between PV technologies. Some types