There appears to be confusion on the amount of generation produced by CCGTs and types of services they can offer.
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Utility turbines bridge the capacity gap.
Despite continued price volatility, natural gas is still the best short-term option for electric utilities looking to add new generation to meet growing electrical demand.
At least, that’s the way two state regulators see it.
“When you consider the (construction) lead time, the availability of the fuel, the fact that it’s cleaner than coal, and the fact that it doesn’t generate the societal concerns associated with nuclear power, right now gas is the primary choice,” says Edward S. Finley, Jr., chairman of the North Carolina Utilities Commission.
“Minnesota requires (utilities) to look at energy efficiency, demand response and renewable-energy options first. If that’s not sufficient to meet the forecasted demand, then they can consider generation options,” says Phyllis Reha of the Minnesota Public Utilities Commission. “Until carbon capture and other coal risks are worked out, natural gas looks to be the least-cost option.”
These are trying times for electric utilities attempting to cobble together resource plans for the next two decades. On the one hand, electrical demand in most parts of the country is rising and expected to increase further. On the other, the new administration is expected to institute green-house gas legislation that will limit carbon emissions and spur some degree of carbon-allowance trading.
That scenario, combined with still unproven carbon-capture concepts, has put at least a temporary kibosh on new coal-fired base-load units and pointed utilities towards gas-fired generation, which generally is viewed as the best way to meet short-term load growth and backstop less reliant renewable energy sources like wind and solar generation.
“We have a lot of wind energy in Minnesota and we have a wind mandate in place for power suppliers,” Reha says. “Natural gas is certainly the most compatible form of backup for renewable energy.”
Finally, while the much-discussed nuclear renaissance still is in play, it’s probably ten if not more years down the road, if it happens at all.
“It’s a tricky question to answer right now,” Finley concedes. “With gas, you’ve got price volatility and questions about the availability of supply. But all potential sources of generation can be criticized for one reason or another.”
One way for a utility to hedge its bets is to use natural gas to diversify its generation mix.
Duke Energy subsidiary, Duke Energy Carolinas, is adding more natural gas to a portfolio that relies heavily on coal and nuclear. With roughly 2.3 million electric customers in its 24,000-square-mile North and South Carolina service territory, the generation mix currently stands at 50-percent coal, 49-percent nuclear, 1-percent hydro or natural gas.
With the Carolinas drawing some 50,000 new residential customers per year, additional capacity is needed to meet the added demand and resolve transmission-system voltage concerns, especially in North Carolina. Despite historical price volatility, the utility says its modeling shows that adding significant natural gas-fired generation is the lowest-cost option when it comes to meeting new load demand.
Towards that end, Duke