Integrating more renewables into the US grid will be costly and have unintended consequences, including potential for increased carbon emissions, that policymakers need to plan for, warns a new Massachusetts Institute of Technology Energy Initiative study.
The study, unveiled Monday, looked at what needs to be done to accommodate increasing percentages of renewables on electricity grids, said MITEI head Ernest Moniz.
The study’s message for policymakers and regulators is that intermittent sources will cost more for total operations, and they have to decide who is going to pay for it – a message that is “not popular,” conceded MIT Professor John Deutch.
Problematic for Generators
The US in 2011 received about 42% of its electricity from coal, 25% from natural gas, 19% from nuclear, 8% from hydro and less than 5% from renewables, but more than half the states are pursuing policies requiring more renewables use.
Researchers found that, even now, increasing amounts of intermittent renewables are forcing grid operators to order cycling of fossil fuel thermal plants in order to keep the grid balanced. While natural gas combustion turbines can start and stop fairly quickly, coal and nuclear plants were designed to run flat out, with start up and shut down taking comparably longer.
For nuclear, load-following – raising and lowering power to compensate for renewables whose output varies over time, like wind and solar – stresses equipment and raises safety issues, said MIT Professor Howard Herzog. Moniz added that nuclear operating costs are so relatively low that decreasing nuclear output makes no economic sense.
Natural Gas the Clear Choice – For Now
For coal, Herzog said, load-following increases thermal and chemical stresses on plant components, decreases efficiency of fuel use with a concomitant increase in carbon emissions per megawatt-hour, decreases efficiency of pollution controls, and increases costs overall.
“In the absence of affordable storage,” said Moniz, “natural gas remains the key backup for intermittent resources.”
Right now, natural gas is also inexpensive. But, Moniz noted, with tens of gigawatts of older coal plants that can’t meet new environmental rulesexpected to shut in the next few years, it’s not at all clear natural gas prices will remain at their current lows over the long term.
Ignacio Perez-Arriaga, an MIT visiting professor and an electricity regulator in Ireland, said systems with large hydro installations, such as Brazil and Norway, can use those turbines to compensate for renewables’ variability. But countries dependent on thermal systems like the US have much less flexibility, he said.
Every Unit Has to Make a Living
An additional complication, speakers noted, is the US system that regulates electricity state by state, so US policies are fragmented. Perez-Arriaga noted the 27 European Union countries all regulate at the national level, and they’ve agreed to form a single power market in 2014 to optimize resources.
Perez-Arriaga said the integration of intermittent sources affects the entire electricity chain, and the power industry needs far more advanced models to predict the effects of expensive decisions such as whether to upgrade long-distance transmission lines to high-voltage direct current. MIT professors and students are trying to develop such models.
Key to all decisions will be attracting investors, Perez-Arriaga said. On some systems in the US and Europe, he noted, prices have gone negative when supply exceeds demand. Prices also spike very high when demand peaks, but generating units must be maintained all the time.
Regulators need to move bidding periods as close to real-time as possible because renewables are difficult to predict, he said. However, regulators also need to price services like frequency and voltage regulation – which renewables cannot provide – at levels that ensure generators are available to provide those services.
“Every (generating) unit has to make a living,” he said.