The Western Electricity Coordinating Council, which oversees
electricity grids throughout the Western U.S. and Canada, estimates Nevada,
Utah and Colorado could have a power shortfall equivalent to 34 days this year
without power imports from other states. Arizona and New Mexico could be short
enough hours to total 17 days. Washington and Oregon could face a shortfall of
hours totaling nine days.
There are two reasons behind the power shortfall: Climate
change is making it more difficult for utilities and grid managers to forecast
demand for electricity, while states aren’t shifting to clean energy fast
enough, according to a report by Bloomberg.
Thanks to the region’s surplus of hydroelectric power,
Washington and Idaho aren’t facing the blackout risk this summer, but demand is
anticipated to increase how much utility companies could pay for electricity.
That’s because Washington is part of the Western
Interconnection, a power grid consisting of 136,000 miles of transmission lines
that carry power from hydroelectric resources in the Pacific Northwest to California
and other states. Utilities routinely import power from out of state, sourcing
electricity to where it’s needed across the transmission lines.
“We are basically tied to what happens in the Western
electric grid. It’s a big machine. It stretches a lot of distance,” said Ben
Kujala, director of power planning for the Northwest Power and Conservation
Council, a regional organization that develops and maintains a regional power
plan, as well as a fish and wildlife program. “There can be small local issues
that have very limited effects. But, if it becomes a shortage or they’re
looking for energy around the entire West, it’s something that will have
impacts. Now, those impacts are not that the lights are going to go out.
Generally, it’s that the power is more expensive.”
At the Palo Verde hub in Arizona, prices have nearly
quadrupled since last summer’s outages, while prices have tripled at the
Pacific Northwest’s Mid-Columbia hub, one of eight electricity trading hubs in
the Western U.S., according to Bloomberg.
“People are kind of anticipating similar challenges (to last
year) and so there’s some very high prices showing up in the summer right now …
If (utilities) have to go out and buy power in the market, they’ll be looking
at a premium for that power,” Kujala said. “Because there’s a lot of people in
California that are buying power, hoping to not have a repeat of the
circumstances they saw last time.”
Jason Thackston, senior vice president of energy resources
at Avista Corp., echoed that prices for the summer are higher compared to prior
years.
“We’re already seeing market prices for the summer higher
than we would normally expect to see them as a result of a couple of things,”
Thackston said. “One is the drought conditions that California and the
Southwest are experiencing. And we’ve seen a drier than normal spring, so we’re
seeing less hydro generation predicted across the Western U.S. Then, what we
saw happening in California last year with rolling blackouts is probably having
an impact on prices, power this summer as well.”
Nearly two-thirds of Washington’s power is generated from hydroelectric
resources.
“I look at how much hydro generation we are looking at this
year, and we’re seeing kind of average-ish, fairly normal stuff,” Kujala said.
“So this is not a year that I would be waving a flag around saying, ‘we’re in
deep trouble in the Northwest.’”
Avista is constantly evaluating snowpack over the winter to
forecast hydroelectric generation for the summer. If there’s a predicted
shortfall of hydroelectric generation, it will supplement it with other types
of power, Thackston said.
“For example, we might increase our expectations around our
natural gas generation that’s available to serve our customers. We will, at
times, go into the market to fill a need that we have if that’s more economic
in serving our customers,” Thackston said. “But we do that in advance. We’re
looking out into the future months and buying power, or increasing our
generation expectations, or adjusting our generation expectations based on the
conditions that we’re forecasting so that by the time we get to the month, we
really have taken all that into consideration and are ready for serving our
customers.”
Inland Power and Light Co., a cooperative that purchases
power from Bonneville Power Administration, serves 12 counties in Eastern
Washington and North Idaho and is anticipating enough supply for its customers,
Inland Power spokesman Andy Barnes said.
“It’s a low water year so far, but we have no alerts saying
we have a power supply shortage,” Barnes said. “Washington state is fortunate
because we have such a megasupplier and producer in the hydrosystem, which is
really beneficial.”
Kieran Connolly, vice president of generation asset
management for Bonneville Power Administration, said there’s a long history of
interregional supply and demand in the Western Interconnection.
“In general, we still expect California to import power this
summer, though the volumes from the Northwest will likely be lower due to
reduced surplus hydropower arising from lower-than-average water supply,”
Connolly said in an email.
The Bonneville Power Administration is a federal nonprofit
agency that markets power generated by 31 hydroelectric projects in the
Northwest, one nonfederal nuclear plant and several small nonfederal power
plants.
Connolly added power shortages elsewhere in the Western
Interconnection should have minimal impact on Northwest customers.
“While each situation is unique, reliability standards and
Bonneville’s operating procedures are designed to limit the risk that
challenges elsewhere in the grid would spill onto the Bonneville system,” he
said.
Planning for the Future
In the Northwest, each utility creates its own load forecast
and is responsible for its own resource needs, according to a report from the
Pacific Northwest Utilities Conference Committee’s 2021 forecast.
The Northwest PowerPool Corp., a voluntary association of
Pacific Northwest-based utilities, is developing a regional resource adequacy
program to evaluate future capacity needs and pool resources to serve demand
during stressed grid or market conditions. The program is slated to launch in
late 2023 or early 2024.
The majority of Northwest utilities’ generating resources
acquired last year and those under development are wind and solar projects.
Biomass, hydropower, batteries and imports make up the rest.
More than 2,000 megawatts of coal-fired generation have been
retired in the Pacific Northwest. By 2029, only four coal units will remain in
operation in the region.
For a variety of reasons, including meeting power demand as
well as the state’s decarbonization policies and goals, utilities are exploring
adding nearly 7,500 megawatts of potential new supply-side resources over the
next decade, in addition to 1,800 megawatts of resources slated to be in
operation in the next few years, according to PNUCC’s forecast.
Avista has started in “a really good place with respect to
clean energy,” with more than half of its power generation already carbon-free.
The company’s power generation is mostly hydroelectric but also includes wind,
solar and biomass, Thackston said.
Avista, a co-owner of Units 3 and 4 at the Colstrip, Montana
coal-fired plant, is planning to exit ownership by 2025.
Avista and other utility companies in the state will no
longer be allowed to distribute electricity from coal-fired generation after
2025 due to the Washington Clean Energy Transformation Act.
“Two years ago, we announced aspirational goals to serve our
customers with 100%, clean electricity by 2045 and a carbon-neutral supply of
electricity by the end of 2027,” Thackston said. “We believe that as the costs
of renewable generation and storage technology continue to drop, and the
technologies continue to mature, that we can move toward those goals in a way
that for sure balances, affordability and reliability.”
The NPCC, which was created in 1980 after Congress passed
the Pacific Northwest Electric Power Planning and Conservation Act, is
releasing a draft of its 2021 Northwest Power Plan in August, followed by a
public hearing. The 2021 power plan will include a 20-year electricity demand
forecast and a portfolio of resources to meet anticipated demand.
Kujala, of the NPCC, said the organization is examining how
the power system is adapting to solar resources in the West as utilities are
retiring more thermal resources. Some utilities are looking at adding storage
into renewable projects to meet demand, he added.
“I guess the question is, ‘are plants actually capturing the
sort of investments you need to make to make sure that is a reliable system?’
We are definitely in the process of exploring that, and a lot of work is about
that exact question,” Kujala said.
Looking to the future, there might be short periods or hours
when electricity is stretched thin, but outages spanning days are not likely in
the Northwest, barring some event outside of normal operations, Kujala said.
Kujala emphasizes the power outages that occurred in
California and Texas last year were different in the cause and impact.
In a report released in January, California utility
regulators determined the Golden State’s rolling blackouts last year resulted
from inadequate supply and demand planning, as well as market issues.
The Texas Interconnection is maintained as a separate grid –
a key difference compared with the Northwest, which is part of the Western
Interconnection.
“I think a lot of people look at what happened in Texas, and
that’s their fear. But we have a lot of advantages being tied to that larger
grid,” Kujala said. “The costs can impact us, and if something happens in the
desert Southwest or California, it can impact our utilities. But it also helps
us be able to ride through circumstances like that in a much different way than
what happened in Texas.”
