It’s time to make critical peak pricing more flexible.
For meteorological reasons that I don’t pretend to understand, the same weather phenomenon that brought the devastating hurricane Harvey to Texas and the Gulf Coast played a role in last week’s record-breaking heat wave in California. It was so hot in Northern California that for the first time our local utility, PG&E, called a critical peak pricing (CPP) day on a Saturday, as well as last Thursday and Friday.
Critical Peak Pricing programs (which go by different names at each utility…PG&E’s residential CPP is called Smart Days) are the most common way in which utilities in the US charge higher prices when demand is straining the system. In a May 2014 blog, I discussed why an alternative approach to reducing peak demand – paying customers to reduce their consumption – creates perverse incentives and is much less effective.
Traditional Design of Critical Peak Pricing
The structure of CPP programs is pretty standardized: over some set of summer months (June-September for PG&E), the utility has the option to call up to X days as critical peak days (15 for PG&E), typically making the announcement in the afternoon of the previous day. On those peak days, the utility charges a much higher price for electricity during the high-demand period (2 PM-7 PM for PG&E).
To date, residential CPP programs have been implemented as optional tariffs, as I blogged about in November 2015. The inducement to sign up for a program where you pay more for electricity on hot days is that you pay less for electricity on the other summer days. PG&E’s program, for example, charges an extra $0.60/kWh during those designated 75 CPP hours (15 days X 5 hours), but charges $0.024/kWh less during the other 2853 hours of those summer months.
Because the CPP price is set before the summer begins, and the total number of CPP days is limited, CPP programs are viewed as simpler and less risky for customers than full-blown real-time pricing, which changes the retail price hourly to reflect changes in the wholesale price of electricity. But the simplicity and risk mitigation of current CPP programs also reduces their effectiveness.
Guessing the Future to Call CPP Today
One of the big barriers to using CPP programs effectively is the limited number of days on which peak prices can be called. It’s easy to see one problem with a fixed number of CPP days: there will be some mild summers where the grid is never strained and no need for CPP days, and other harsh summers where the limit prevents the utility from sending appropriate price signals on all the scorching days, especially towards the end of the summer.
A more subtle problem is that each time it considers calling a CPP day, the utility has to try to guess the weather for the rest of the summer in order to know the right threshold. If the summer turns out to be hotter than normal, the utility is going to regret some of the CPP calls it made in the beginning.
That’s the sort of summer we’re having this year. The California ISOs highest demand ever was 50,270 MW in summer 2006. Most annual peaks since then haven’t cleared 47,000 MW and none had cleared 49,000 MW, until last Friday. And then Saturday’s peak was over 47,000…on a Saturday!
With its CPP call on Saturday, PG&E used the 14th of its 15 days. So it has one bullet left to shoot with more than one-fifth of the program days left to go for this year, a period during which it has called 22% of all its CPP days over the last six years. (We have hot Septembers in California).
A More Flexible CPP Design
So is there a way to keep CPP programs relatively simple and low risk while allowing more flexibility in the number of days called? Yes! An approach that I studied in a paper back in 2013 (see section 7) would allow complete flexibility in the number of days called, but would still largely protect customers from the bill volatility that price spikes can cause.
The problem with the current structure is that it balances all of the additional revenue earned from a small number of CPP hours against a uniform price reduction during all other hours. That approach means that the utility has to stick to the planned number of CPP days — regardless of how stressed the grid actually is — or it will collect too much or too little revenue. To minimize customer bill volatility and utility profit volatility, typical CPP programs sacrifice pricing efficiency, which was the original point of the program.
But there is a way to reduce the risk to buyers and utilities and still call CPP events when and only when the system is stressed — as many or as few as is appropriate each year. Each time a CPP event is called, the utility also cuts prices by an approximately offsetting amount in the adjacent off-peak hours. Rather than balancing CPP revenues over the entire summer, this approach balances revenues within a day or two.
One question is whether a utility really could cut prices enough during surrounding hours to make each CPP call approximately revenue neutral. I examined that question in the 2013 paper and found that the answer is yes. The utility would have to cut prices to just a few cents per kWh in the non-CPP hours of the CPP day, and in some cases it would need to extend the “super discount” hours to off-peak times of adjoining days, but that would do it. And those super discount hours would help to further encourage timeshifting of some activities — such as running the dishwasher or washing machine — away from the CPP hours.
Making each CPP event revenue neutral would also make it easier to focus calls on the smaller number of days in which the system capacity is truly strained. In Josh Blonz’s paper from last year, which I blogged about in November, he showed that CPPs should only be called on average less than 10 days per year, more in some years, fewer in others. Josh also showed that on the CPP days that are called, the CPP price should be much higher than is used in most programs. That sort of implementation is a lot more difficult when a utility has little flexibility in the number of CPP days it can call each year.
The Growing Need for Demand Flexibility
Recent research — including a paper published by Max and co-authors just this week — shows that as the planet warms, demands on electricity systems will change, often in hard-to-predict ways. Ramping up intermittent renewables will also increase the premium on being able to dynamically alter consumption of electricity. The emergence of a significant PV-driven “duck curve” years sooner than anticipated is just one demonstration of the value of being able to adjust demand at different times of the day.
Flexible pricing should be one of the primary instruments used to address changing stresses on the grid due to higher renewables penetration, increased A/C use, expansion of the electric vehicle fleet, and other trends in electricity supply and demand. The current CPP programs were a fine first step in that direction, but we need to keep innovating in pricing structures, just as we need to keep innovating in technologies. Revenue-neutral CPP days would be an excellent next step as we move towards a system that integrates new technologies, reduces carbon emissions, and controls costs.
I tweet energy articles/research/opinions most days @BorensteinS
Severin Borenstein is Professor of the Graduate School in the Economic Analysis and Policy Group at the Haas School of Business and Faculty Director of the Energy Institute at Haas. He received his A.B. from U.C. Berkeley and Ph.D. in Economics from M.I.T. His research focuses on the economics of renewable energy, economic policies for reducing greenhouse gases, and alternative models of retail electricity pricing. Borenstein is also a research associate of the National Bureau of Economic Research in Cambridge, MA. He served on the Board of Governors of the California Power Exchange from 1997 to 2003. During 1999-2000, he was a member of the California Attorney General's Gasoline Price Task Force. In 2012-13, he served on the Emissions Market Assessment Committee, which advised the California Air Resources Board on the operation of California’s Cap and Trade market for greenhouse gases. In 2014, he was appointed to the California Energy Commission’s Petroleum Market Advisory Committee, which he chaired from 2015 until the Committee was dissolved in 2017. From 2015-2020, he served on the Advisory Council of the Bay Area Air Quality Management District. Since 2019, he has been a member of the Governing Board of the California Independent System Operator.