As the power industry is about to begin its next wave of generation capacity additions, coal and nuclear are the most talked about sources for new baseload capacity. Within both categories the industry has options to consider, and the best choices have yet to be determined by markets and other factors.

A nuclear renaissance has begun and it’s being driven by high natural gas prices, concerns about national energy security and public policy laid out in the Energy Policy Act of 2005 (EPact), Ed Cummins, Westinghouse vice president for regulatory affairs, told a Houston audience last Thursday. In Cummins’ view, disposal of spent nuclear fuel and the uncertain future of Yucca Mountain is more of a political issue rather than a technical challenge, but it still has the potential to be a stumbling block.

“I think it’s a big political issue, still,” Cummins said following a big sigh. “Solving Yucca Mountain is not seen as a prerequisite to going forward. There are some utilities that see it that way, though.”

Additionally, like much of the rest of the energy industry, the nuclear business will continue to suffer from a shortage of skilled workers in the years ahead, he added.

While the licensing process for new nuclear plants has been streamlined somewhat, it still presents challenges, Cummins told attendees at the 2006 Power Conference of the Global Energy Management Institute at the University of Houston. The theme of the half-day event was how new power technologies will transform the electricity marketplace. Telling was the fact that the only mentions of natural gas-fired generation were largely in passing and related only to fuel and capital costs.

Cummins devoted a portion of his talk to touting Westinghouse’s latest nuclear plant technology, known as AP 1000, which received design certification from the Nuclear Regulatory Commission (NRC) in December last year. Currently, several U.S. utilities are evaluating new nuclear plants, Cummins said.

Dominion, Exelon Corp. and Entergy Corp. have permits for new nuclear plants under way, and Southern Company is planning to apply at the NRC, Cummins said. These, however, are not commitments to actually build the facilities, he noted. If these projects do go forward, they and any others like them will benefit from provisions under EPact that are intended to encourage nuclear development. These include federal insurance to cover the cost of project delays caused by government or public interference; production tax credits for the first 6,000 MW of new nuclear capacity; federal loan guarantees for up to 80% of project cost; and other incentives, Cummins said.

Before new nuclear plants are completed, most industry observers believe that existing plants will be expanded wherever it is economic to do so. When it comes to new plant development, this time around will be different from what happened during the 1970s, Cummins said. This time operators will be standardizing their plants to achieve economies of scale in their plant operations. During the last nuclear build out, a variety of different plant designs were built. One reason the nuclear industry has been so successful in France is the fact that plant design is standardized.

Regardless, the nuclear industry is clearly positioned to benefit from high and volatile natural gas prices. With a natural gas-fired combined-cycle plant, about 80% of costs go to fuel. That figure drops to 35% for coal-fired plants and plummets to 12% for nuclear plants, Cummins said. While uranium is cheap, the plants that can turn it into electricity are not. Still, the high capital cost of nuclear power is outweighed by the volatile market for natural gas, Cummins said.

Other factors driving consideration of nuclear power are the regulatory uncertainty for coal plants with regard to emissions, the relatively stable regulatory environment for nuclear plants, as well as the incentives provided by EPact, Cummins said. He predicted that there will be at least one Westinghouse AP 1000 plant operating in the United States by 2015.

On the coal side probably the biggest wild card is whether/when the United States becomes a carbon-constrained generation market. That is to say, when will CO2 be capped and regulated as most of the industry expects it will? Currently, provisions of the Clean Air Act are driving the increased use of “compliance coals” from the western United States. Midwestern and eastern coals are clearly disadvantaged in this market by their sulfur content. So while eastern coals lie unused, prices for western coals have escalated, explained Daniel Tse, General Electric commercialization manager.

Two coal technologies will compete as the industry tries to make better use of U.S. coal supplies. Integrated gasification combined cycle (IGCC) and supercritical pulverized coal generation are in varying stages of development.

General Electric acquired the coal gasification technology of Texaco. GE and Bechtel are in an alliance to develop IGCC. As with nuclear, standardization of plants is seen as key to making them more economic, and the GE-Bechtel effort has a high degree of standardization in its design, Tse said. He maintains that IGCC is better than supercritical pulverized coal generation as it offers “fuel gas” instead of “flue gas,” and claims that emissions from IGCC plants come close to levels seen from natural gas-fired generation. Currently there are two announced IGCC projects, he said: American Electric Power’s project in Ohio and a Duke Energy (formerly Cinergy) project in Indiana. They are expected to be online in 2010 and 2011, respectively, Tse said.

Electric Power Research Institute (EPRI) CEO Steven Specker emphasized that EPRI is technology neutral when it comes to generation. “We work on all generation technologies. We love them all.” Using EPRI’s $6/MMBtu gas price assumption, Specker said supercritical pulverized coal generation is the least-cost option in a world where carbon dioxide credits cost up to $35/metric ton.

However, when carbon capture and sequestration is considered, IGCC generation has a significant advantage over supercritical pulverized coal. The additional equipment to capture carbon emissions from power plants is not what presents the cost barrier. The biggest stumbling block to carbon capture is what it does to plant efficiency, Specker said. IGCC plants take a much smaller hit to efficiency than pulverized coal plants when carbon capture equipment is added. Figuring out how to economically capture carbon emissions from pulverized coal plants is a critical technical challenge for the industry, he said. There is about 70 GW of new pulverized coal generating capacity on the drawing board over the next 10 years. “Having the option to capture CO2 from pulverized coal is very important.”

Specker added that the industry has “an extraordinary opportunity” to develop a low carbon generation portfolio by 2020.

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