How Much Is An Intangible Like Electric Grid Reliability Worth?

It comes down to another set of intangibles: risk tolerance vs cost. 

But as extreme weather events become the norm, it is apparent that the bases for those calculations are evolving. The question is whether policy makers can get ahead of changing public perceptions. JL

Jinjoo Lee reports in the Wall Street Journal:

Recent failures serve as a warning for all electricity markets. Since the 1970s, unusually hot days have become more common, and tropical-storm activity has increased. The answer might not be an overhaul of power-market design, but a re-evaluation of risk modeling. Can electricity grids be better prepared for extreme weather? The harder question is: How much are we willing to pay? Different households have different tolerance levels for risk and cost. The more risk policy makers incorporate into scenarios before setting market prices and rules, the safer the grid can be.

Can electricity grids be better prepared for extreme weather? Absolutely. The harder question is: How much are we willing to pay?

Grid reliability is getting more attention as extreme cold in Texas caused days of rolling blackouts for its residents. Last summer, a historic heat wave in California led to power shortages in the state. Many are left wondering how electricity grids, such an essential component of a functioning society, could be left so unprepared.

It is tempting to try to come up with a neat answer: A certain type of energy source might be to blame—whether wind, solar or natural gas—or the power market design might be responsible. Neither of these is satisfying on its own. A full autopsy will be required to figure out what exactly went wrong in Texas, but at a broad level the issue comes down to cost and risk assessment.

The decisions an American family has to make every year about health coverage aren’t all that different than the ones facing electricity planners. One family might prefer cheap insurance with less coverage, knowing full well that an emergency room visit will cost dearly. Another might prefer high fixed payments in exchange for peace of mind.

The electricity system is similar, and both Texas’ and California’s deregulated markets have little built-in insurance compared with others. Both are energy-only markets that rely on price signals to make sure enough power is on the grid. Other markets such as ISO-New England and PJM Interconnection, which covers 13 states and the District of Columbia, have capacity markets that offer power plants incentives to be on standby just in case the grid needs it. And then there are states with fully regulated markets where a utility owns or controls the total flow of electricity. In such a market, a utility has an incentive to invest as much as possible in the grid because it can raise the price it charges customers—as long as the state’s utilities commission approves.

Would a different market structure have prevented failures in California and Texas? It may have helped, but it would not have been 100% foolproof. Let us assume Texas had a fully regulated market. True, the state’s utility might have had more financial incentive to weatherproof its grid—but it would base those investment proposals on assumptions about future supply, demand and risk levels. Crucially, the state utilities commission would need to agree that the costs—which would ultimately be passed on to households—are justifiable.

“At the end of the day, there’s always someone that’s making a judgment call on how much is worth it,” says Jesse Jenkins, an assistant professor of engineering at Princeton University who focuses on electric-power systems.

It would be the same kind of inconclusive answer if Texas had a capacity market, a system where some generators are paid for being on standby. In such a system, capacity price signals are based on the worst-case scenario the grid operator can imagine. Even a capacity market could be left short in the face of extraordinary weather conditions. PJM Interconnection, for example, tweaked its capacity market rules after the polar vortex of 2014 left up to 22% of power generation unavailable to customers. The rules raised the stakes for power plants, penalizing underperforming plants heavily and rewarding those that exceed expectations during emergency hours. PJM notes that these changes helped ensure enough power was available during the extended cold snap in 2018, when forced outages peaked at under 12%.

Even these investments can cause a backlash if deemed costly. Ratepayer advocates have criticized capacity-market pricing models for adding too much onto utility bills for power that might never be used. The American Public Power Association estimates that in 2019, capacity prices in PJM added $119 a year, or $9.92 a month, to the electric bill of a homeowner on average, representing 9% of the total bill.

The ultimate answer might not be a complete overhaul of power-market design, but rather a re-evaluation of risk modeling. The more doom and gloom the policy makers incorporate into their scenarios before setting market prices and rules, the safer the grid can be. California regulators knew since at least 2017 that the state could face a capacity shortfall before the blackouts occurred in 2020, but failed to act. Likewise, Texas got tastes of how freezing temperatures could hold up power supply in 2011 and 2014.

Recent failures serve as a warning for all electricity markets given that extreme weather events are becoming more frequent, rendering historical weather data useful only up to a certain point. Since the 1970s, unusually hot summer days have become more common across the U.S., and tropical-storm activity has increased over the past 20 years, according to the U.S. Environmental Protection Agency.

On average, American homes paid $115.49 a month for electric bills in 2019, according to the U.S. Energy Information Administration. On an annual basis, that works out to about 2% of U.S. median household income. Price per state varies depending on fuel mix and market structures, and can be very different even within a state. Texas as a state had lower average retail rates per kilowatt-hour compared with the U.S. average in 2019. However, a Wall Street Journal analysis found that from 2004 to 2019 Texans serviced by traditional utilities paid 8% lower, on average, compared with nationwide rates, while those with retail providers paid 13% more than the nationwide rate. Not only is Texas’ wholesale power market deregulated, but its retail market is also competitive, which means nearly 60% of consumers are required to buy electricity from one of many retail power companies that compete against each other rather than a local utility.

Consumption levels matter too. While Texas has lower-than-average prices per kilowatt-hour, homes there use more electricity, resulting in a higher-than-average monthly bill of $134.07, according to EIA data. California’s residents are charged 1.6 times more than Texans per kilowatt-hour but actually end up with a smaller bill, on average, because they use less electricity. That shows solutions could come from both electricity supply and demand.

If we want grids to be nearly 100% reliable, such a future is possible. The tricky part is that different households have different tolerance levels for risk and cost. Determining how much we are collectively willing to shell out for safety is more art than science. It could take more trials, and more costly errors, to arrive at the right balance.