Duke Energy’s options for reaching net-zero carbon by midcentury will look a lot different than those being pursued by utilities in the sun-soaked Western U.S., or the wind-rich Great Plains, or even those sharing the same Atlantic coastline.
That’s a key point that Glen Snider, director of integrated resource planning and analytics, wants to make about Duke’s 2020 integrated resource plan for its Carolinas utilities. Duke’s new IRP presents six very different pathways toward greening its energy mix over the next 15 years, all of them reaching at least 50 percent carbon reduction by 2030.
Some of those pathways move more dramatically toward closing coal plants or halting construction of new natural-gas power plants. Others rely on options like offshore wind that are untested in the U.S., or next-generation modular nuclear reactors which have yet to be proven in any market.
Duke’s IRP underscores the diverse needs of its collective 3.2 million customers across the Carolinas and the mix of 4.6 gigawatts of new resources it will need to add over that time to meet their needs.
Charlotte, North Carolina-based Duke faces “very distinct” circumstances that make its net-zero carbon options much different than those of utilities pursuing similar goals in California and Arizona, Colorado and Minnesota, or New York and New Jersey, Snider said.
Duke’s specific challenges
To begin, the Southeast and Atlantic South regions have almost double the electricity usage per customer, due to two factors, Snider said: “the climate and the appliance saturation.”
While most U.S. utilities have to plan for an electricity peak driven by summer air conditioning and cooling demand, Duke and other Southeastern utilities face an equally daunting winter peak driven by a reliance on electric heating and unpredictable cold snaps, as this U.S. Energy Information Administration data illustrates.
This difference is mainly due to the Southeast’s reliance on electricity rather than natural gas for heating air and water in buildings, Snider explained. That puts the Southeast ahead of other regions of the country in terms of transitioning heating loads from fossil fuels to electricity, but it also puts a strain on the power grid to meet peak heating needs.
The heat pumps used by many Duke customers are very efficient when temperatures are above or near freezing, Snider said. But when they drop lower, “that electric heat pump switches off and you go into electric resistive heating mode. […] You can have sustained periods of really high loads.”
That’s given Duke a “dual-peaking” system, with both summer and winter demand spikes to deal with.
Solar energy’s winter doldrums
For several reasons, such a dual-peaking profile doesn’t lend itself nearly as well to clean-energy-based solutions as does the more typical summer-only peak, Snider said.
First of all, unlike summer cooling electricity demand that can be met by growing solar generation in hot and sunny climates, these winter peaks coincide with short and cloudy days. That limits the ability of North Carolina’s solar fleet, which is second only to California’s in terms of nameplate generation capacity, to solve the problem.
Summer’s bounty of solar generation can increasingly be stored in batteries to shift capacity into the evening hours after the sun goes down, when energy demand for air conditioners remains strong. While California’s recent heat-wave-driven grid emergencies indicate it doesn’t yet have enough battery capacity to cover these post-sundown peaks, it is technically possible to solve summer peak needs that way.
But Duke’s winter cold snaps can last for weeks during periods when solar generation remains weak, Snider said. “There are weeks and weeks that we’ll get 20 to 30 percent of our solar output” compared to nameplate capacity.
That reality leaves batteries a less-than-ideal option for meeting winter peaking capacity over the long haul unless there’s some alternative resource to charge them up day after day.
Why offshore wind is no slam-dunk for Duke
To make up for those gaps, Duke will need a diverse array of resources that can provide reliable wintertime energy generation, as well as capacity to cover the gaps in generation. Wind power can certainly help, but onshore wind farms aren’t as reliable in the Southeast as offshore wind, which can capture far more consistent winds to serve through the cold winter season.
Similar considerations are behind New York’s reliance on offshore wind to meet its ambitious clean energy goals. But while New York City, Boston and many other big Eastern cities are on the coast, Duke’s major load centers of Charlotte and Raleigh-Durham lie far inland, which means transporting that offshore wind power will require a major investment in transmission on land as well as across water — about $7.5 billion over the next 15 years, compared to between $1 billion and $3 billion for most of its other IRP scenarios, according to Duke’s estimates.
Likewise, the gigawatts of energy storage that would be required for Duke to accomplish its more aggressive carbon-reduction plans while maintaining system reliability would have to include a significant portion of longer-duration storage, compared to the 4-hour durations now supplied by state-of-the-art lithium-ion battery installations.
Pumped hydro storage, but how much?
Pumped hydro storage is the most reliable long-duration storage available, and Duke is planning to upgrade its 1,000-megawatt Bad Creek facility to add 300 megawatts more of storage capacity over the next few years.
The new IRP calls for up to 1,600 megawatts of new pumped storage to meet its long-term needs under its more aggressive carbon-reduction pathways. But siting, planning and building that expanded capacity would take more than a decade, Snider said.
In other words, pumped storage is one of many examples of how decisions being made today will have major impacts on Duke’s decarbonization journey years down the line.