How Duke’s Unique Energy Landscape Dictates Its Path to Net Zero

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

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
 (IRP) for its Carolinas utilities.
Duke’s recently published 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 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 Carolinas customers, and the mix of 4.6 gigawatts of new
resources it will need to add over that time to meet their

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
 and Arizona,

Colorado and Minnesota
, or
New York
 and New
, 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 (EIA) data

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 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,†and “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
value 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 heatwave-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 while 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

Why offshore wind is no slam dunk for Duke

To make up for those gaps, Duke will need a diversity 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
is 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
four-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. 

Source: FS – GreenTech Media
How Duke’s Unique Energy Landscape Dictates Its Path to Net