Demand for electricity grows even as supplies become less predictable

Over the past 10 years, more than 40 new data centers have been built in Minnesota with several more in the works.

Many belong to Minnesota corporations with growing computing needs. But, in recent years, out-of-state firms such as Meta and Microsoft have been drawn to the state by the availability of affordable, renewable electricity that can help reduce their carbon footprint.

“We’re seeing it all the time with the companies that we’re talking to—they’re asking us, ‘Can we get 100 percent renewable energy?’” said Kevin McKinnon, deputy commissioner at the state’s Department of Employment and Economic Development. Newer data centers tend to be larger and require more electricity, he said.

Demand for electricity is rising rapidly throughout the Ninth District, and the growing number of data centers is one of the reasons why. The supply of electricity is also rising in response. But this is complicated by the utilities sector’s ongoing shift from coal to natural gas, wind, and solar, which are less expensive and less polluting, but also less predictable.

In its most recent forecast, the North American Electric Reliability Corp. (NERC) warned that wholesale electricity markets serving the Ninth District are at elevated or high risk of shortfalls in electricity supply over the next 10 years; NERC’s mission is to reduce the risk of power outages, and it does so by regulating utilities on the government’s behalf. Many utilities rely on markets when extreme heat or cold unexpectedly drives up demand or when power plants suffer equipment failure.

Not everyone agrees the situation is as dire as NERC depicts it, but the group’s assessment is a reminder that over-reliance on the market can be costly.

For example, during a week-long cold snap in Montana in January 2024, NorthWestern Energy was forced to buy electricity when the market was short on supplies and long on demand from other utilities. The utility told regulators that “customers incurred about a net $40 million liability over this event.”

This has been a recurring issue for the utilities sector in recent years, prompting many utilities to invest in more power generation.

Xcel Energy plans to increase generating capacity by more than 10 percent over the next 10 years in its Upper Midwest service area, which stretches from western North Dakota to Michigan’s Upper Peninsula. One of the goals, Xcel spokesperson Theo Keith said, is “ensuring we can meet customers’ needs without relying on the … market for energy.”

Demand growing and becoming less predictable

The way the grid works today, electricity supply must match demand at every moment to avoid the risk of outages and damage to generating equipment. Utilities have little trouble matching normal day-to-day demand. The challenge is matching peak demand when electricity usage spikes. This typically occurs on very hot or cold days when large numbers of customers crank up their air conditioning or heating.

Peak load is expected to increase significantly for some major utilities in the Ninth District and for the electricity markets they participate in. These markets include the Midcontinent Independent System Operator (MISO), Southwest Power Pool (SPP), and the Western Electricity Coordinating Council’s northwest area (WECC-NW) (Figure 1. For maps of markets and utility service areas in this article, see figures 2 and 3.).

The specific drivers of day-to-day demand are slightly different for different utilities.

In Xcel’s Upper Midwest service area, the drivers include new data centers, new electric vehicles, and consumers shifting from natural gas appliances to electric, according to Bria Shea, regional vice president for regulatory policy in Minnesota. “All three of those are really changing what we see and what, in general, electric utilities are seeing across the board for an increase in demand.”

Because they have such a voracious appetite for electricity, data centers can make a significant impact. For example, a new cryptocurrency mining facility in southeastern North Dakota is expected to consume an amount equivalent to a quarter of Montana-Dakota Utilities’ generating capacity, the utility told investors. The mine’s owners have already started constructing a new facility for training artificial intelligence.

On the western end of the Ninth District, in NorthWestern Energy’s Montana service area, demand is driven primarily by population growth, the utility said in plans filed last year. Spokesperson Jo Dee Black said demand from EVs and large commercial and industrial customers, such as data centers, has not increased significantly and isn't included in forecasts.

While data centers, EVs, and appliances, once in use, are likely to be predictable in their day-to-day electricity demand, they contribute to peak demand. As day-to-day demand grows, it will likely drive up the total amount of electricity needed during peak demand.

Peak demand is less predictable because it’s largely driven by weather, especially temperature extremes. For example, some of the highest prices on the Mid-Columbia Hub, NorthWestern’s electricity market, have occurred in the last five years, mostly during heat waves or cold snaps (Figure 4).

That’s what happened to NorthWestern in January. The utility paid as much as $930 per megawatt-hour, six times more than the average in the same month in 2023. NorthWestern told regulators the event was “nearly impossible to adequately model.”

But, as NERC and others have recognized, extreme weather has become more common and is expected to be even more common in the future.

Reserves are shrinking

Like demand, supply is also becoming less predictable.

Traditionally, large “base load power plants” fueled by coal supplied the electricity for day-to-day demand. Natural gas, hydropower, and nuclear power also provide base load power. All can produce a large, steady amount of electricity at relatively low cost. For peak demand, utilities rely on smaller “peaker plants,” usually powered by natural gas, that can ramp up quickly.

But this is changing. Many utilities are retiring older coal power plants. That’s partly because of stricter regulations, such as mandates to reduce carbon emissions in some states. Coal is also less able to compete with natural gas and renewable energy. The advantage of renewable resources is they’re cheap when the wind is blowing and the sun is shining. In such a situation, a power plant that must pay for fuel would, ideally, power down, and its owner would take advantage of the cheaper renewable energy. Most natural gas plants were designed to ramp up and down this way, but coal plants, which tend to be older, were not.

New natural gas, wind, and solar power plants also cost less to build and operate. Utilities are investing more in them and retiring old coal plants. As a result, more of the base load is being carried by renewable resources with peaker plants for backup.

“We’ve already had periods when wind energy handled most of our Upper Midwest customers’ energy demand during nighttime hours when demand is lower,” said Xcel’s Keith. “Those instances will increase as we add more renewable resources to our energy mix. This is incredibly beneficial for our customers because wind and solar do not have fuel costs.”

One of NERC’s concerns is utilities committing to retiring base load plants without firm plans to replace them with similar capacity. For example, within MISO, fossil fuel and nuclear plant capacity is expected to drop by 24 gigawatts by 2033. Electricity from other resources, including those not traditionally used for base load, is expected to grow by just seven gigawatts; a gigawatt was enough to power about 1 million Ninth District homes in 2023.

The key metric is “reserve margin.” This is the capacity for producing electricity in excess of normal peak demand. Reliability authorities typically set a target margin high enough to ensure supply does not fall short by more than a day every 10 years.

Based on generating resources currently available or in planning, NERC’s forecast shows capacity falling below target margins over the next 10 years in MISO and WECC-NW. Based on the same criteria, Montana-Dakota Utilities followed the same trend. For some other markets and utilities, capacity will still exceed the target but not as much as before (Figure 5). This reflects the expectation that demand will grow faster than supply.

But these figures are based on plans, which can change over 10 years. Concerns about shortfalls in the supply of electricity have been raised before, including by NERC, and utilities have changed their plans in response. Some have reversed plans to retire base load plants. On the other hand, a lot of uncertainty is involved in the transition to renewable energy, which may complicate utilities’ planning.

For example, NorthWestern has said it’s concerned about the fate of the coal plant in Colstrip, Montana, which it currently owns with four other utilities. Montana doesn’t have a carbon-free mandate, but three partners in Washington and Oregon do. When those partners exit in a few years, far fewer customers will bear the cost of maintenance and repairs.

“Colstrip is the largest single resource in NorthWestern’s portfolio,” the utility told Montana regulators. “A significant amount of capacity contribution towards NorthWestern’s load obligation will be lost if Colstrip retires early.”

Supplies becoming more “variable”

Besides replacing base load power plants, NERC is concerned about the mix of generating resources. Wind and solar are what the industry calls “variable resources,” meaning they do not generate a predictable amount of electricity like base load plants.

All power plants are rated by their generating capacity under optimal conditions and by their accredited capacity, a measure of how much they actually generate. For coal and natural gas plants, the gap between the two measures is narrow, reflecting the occasional downtime for maintenance or repairs. For wind and solar farms, the gap is wider, reflecting the longer periods when the wind doesn’t blow or the sun isn’t out.

But that gap may widen further as utilities gain experience using large amounts of variable resources. Several electricity markets, including MISO and SPP, have proposed reducing the accredited capacity of wind and solar farms. For example, solar is currently accredited at about 50 percent of its optimal capacity by MISO. The proposed changes would reduce this to 32 percent and possibly even less.

There is considerable debate over this proposal. Critics, such as environmental groups, argue that MISO and other market organizations overstate the unreliability of wind and solar and understate the unreliability of coal and natural gas.

Researchers at the National Renewable Energy Laboratory have found that sunshine usually accompanies heat waves, and strong winds usually accompany cold snaps. That means solar and wind energy should be at their peaks when demand for electricity is at its peak.

Natural gas power plants, however, have proven to be very vulnerable to cold weather. A recent government investigation into outages caused by 2022’s Winter Storm Elliott noted that it was the fifth time such outages have occurred since 2011. All of them involved natural gas equipment failure.

Asked if MISO’s proposed downgrading of renewable resources would affect Xcel’s plans, Keith said that the utility is working with MISO and other utilities on the matter.

Utilities planning for uncertainty

To cope with so much uncertainty, utilities are adopting a variety of strategies.

Some are preserving their traditional base power plants instead of retiring them.

NorthWestern, for example, expects to receive more power from the Colstrip plant after agreeing to increase its stake from 11 to 55 percent when two of its partners exit.

Conservation is expected to play a bigger role as well. Montana-Dakota Utilities’ contract with the North Dakota cryptocurrency mine, for example, allows the utility to cut power for many hours each year.

Utilities are adapting to variability as well. Xcel plans to diversify its geography by contracting with utilities in other parts of the country. The idea is that even if the wind doesn’t blow in the Upper Midwest, it likely is blowing somewhere else. The utility is also investing in peaker plants and battery storage, which will provide nearly half of its power during peak summer demand in 2033. Batteries are expected to play a much bigger role, providing in 2033 about three-quarters of the power that coal does in 2024.

“We recognize it’s not always sunny, it’s not always windy. But that’s why we have nuclear, which is always available, or that’s why we still have gas, which can react quickly and come online,” said Shea, the Xcel executive. “As we do have increasing wind and solar, what’s the resources that can be paired with them to make sure that, on all hours of all days, we can meet our customer needs?”