If we don’t also get electricity rates right, closing one perverse incentive may just increase another.
I want to begin this week’s blog by saying how great it is to be writing about energy policy with a renewed feeling that such discussions matter. I realize that serious, thoughtful people can have honest disagreements about the most effective and equitable response to the climate crisis and other energy issues. Lively, challenging and respectful debate is critical to finding the best course forward, especially if that debate is undertaken with the humility and open-mindedness that allows one to change their mind when new evidence warrants it. I’m optimistic that this sort of debate will be more welcomed by federal policymakers now than it has been during the last four years.
OK, on to today’s topic:
Last fall, the California Public Utilities Commission (CPUC) began a new regulatory process to revisit the state’s net energy metering (NEM) policies for rooftop solar and other behind-the-meter generation. Since it was adopted in the 1990s, NEM has been a big factor driving residential solar adoption. For every kilowatt-hour (kWh) that a customer injects into the grid, NEM reduces one-for-one the kWhs of electricity the customer has to pay for at retail rates. Effectively, the utility is buying power from customers at the full residential retail rate, rather than the much lower wholesale market price that other suppliers are paid.
This amounts to a very large subsidy in California, because the residential prices that customers face are many times higher than the wholesale price of power and other costs that the utility saves when a rooftop solar array pumps power back into the grid. For example, for every kWh that a PG&E solar household exported into the grid in 2019, it saved more than 26 cents, on average, while the utility’s costs only declined by about 8 cents or less. The 18 cent difference pays for costs that don’t change with variation in a household’s consumptions, like much of the transmission and distribution system, energy efficiency programs, subsidies for low income customers, and other fixed costs. It has to be made up somewhere else, typically by raising retail rates. That cost shift has been a significant factor in pushing up residential electricity prices in California.
The history of NEM in California is similar to other regulatory policies meant to benefit a new technology or activity: they start as small programs, sometimes with legislated limits, and the early adopters benefit. Then interest grows, business models are built that rely on program mandates or subsidies, and market participants develop a keen interest in keeping the program alive. In response to their strong advocacy, limits get raised or eliminated and the program gets extended.
Unfortunately, that often happens even if the program no longer makes good policy sense. The benefits are concentrated and the costs are diffuse, a classic political economy recipe for poor policy outcomes.
But if the costs of the program balloon too much, regulators face a reckoning. With nearly 200,000 wealthier-than-average California customers now installing solar every year, and the state even mandating them for new homes, that reckoning has arrived. The CPUC is stuck between the inequity rock of generally-poorer ratepayers continuing to subsidize rooftop solar adopters and the political-blowback hard place of phasing out NEM, which would mean paying the solar households something much closer to the wholesale price for their exports to the grid.
That may sound bad, but the situation is actually worse. Recent advances in storage technology mean that phasing out NEM for new solar installations may not even end the spiraling cost shift. With battery costs declining, solar homes can now “self-NEM” by storing their power on-site and keeping it behind the meter. That’s a problem, because storing electricity in order to avoid paying the retail price for later consumption isn’t creating value; it’s just shifting fixed costs to other customers.
My own calculation is that the retail prices that are way above marginal cost in California give customers an extra reward of over $648 per year from installing batteries and storing power rather than exporting (calculation below [i]). That’s not quite enough to pay for the batteries on its own, and the majority of new solar systems are still being installed without batteries. But as battery costs fall and more households – particularly wealthy suburban ones – respond to wildfire-induced power shutoffs, the trend is clear.
These customers aren’t about to go completely off-grid. For years or decades to come, they will still use the grid nearly every day in order to maintain reliable service and balance their daily supply and demand without the massive battery installations it would take to cut the cord entirely. But with relatively small storage capacities, they can greatly reduce exports. That will still save the homeowner money, because they just need to beat the retail price, which averaged about 26 cents per kWh for PG&E in 2019 (a bit more for SDG&E, and a bit less for SCE). But it will only save the system around 8 cents per kWh, because we will all still need the transmission and distribution grid, vegetation management to prevent the wires from starting wildfires, energy efficiency programs, R&D to push low carbon technologies forward, and all of the other things that our rates pay for above the marginal cost of supplying more electricity.
Looking at it from this angle, it’s clear that the fundamental problem isn’t NEM. It’s the perverse incentives created by the huge gap between the retail price and the utility’s cost of supplying additional power to the customer, the same issue that will impede electrification of buildings and transportation. If the utility were charging an incremental price per kWh that reflects its true cost of incremental supply (including pollution costs), then a customer choosing to self-supply more of its energy would leave little or no revenue hole behind. (Of course, if the utility were charging the true marginal cost for incremental supply, rooftop solar wouldn’t be a financial winner for nearly as many customers.)
The CPUC has also scheduled a separate public meeting in February to examine trends in retail electricity and gas rates, including the potential for anticipated rate increases to erode incentives for electrification and building decarbonization. But the same rate trends that risk inefficiently undermining electrification are also inefficiently promoting behind-the-meter generation that is compensated at retail price ahead of grid-scale generation that only receives the wholesale price. The solution to both problems is better alignment between the volumetric electricity price and marginal cost of supply. As I wrote in November, income-based fixed charges can potentially be a way to make that happen and still equitably cover costs.
If history is any guide, some people will respond to my concerns about incentives for behind-the-meter generation with “Severin, you just hate rooftop solar.” It’s simply not true. I don’t hate or love any technology. I do love being part of a community that is researching and debating how to solve our immense energy and environmental challenges in the lowest cost and most equitable way. Right now, I think that incentives are excessively tilted towards rooftop solar compared to grid-scale renewable solutions, leading to a higher cost and less equitable approach to decarbonization. But, if the evidence warrants, I am very much open to changing my mind.
I’m back to mostly tweeting energy news/research/blogs @BorensteinS . What a relief.
Keep up with Energy Institute blogs, research, and events on Twitter @energyathaas
Suggested citation: Borenstein, Severin. “Can Net Metering Reform Fix the Rooftop Solar Cost Shift?” Energy Institute Blog, UC Berkeley, January 25, 2021, https://energyathaas.wordpress.com/2021/01/25/can-net-metering-reform-fix-the-rooftop-solar-cost-shift/
[i] Here’s my calculation: a typical CA solar customer is putting in about a 6 kW system these days according to the LBNL Tracking the Sun project, which at a 20% capacity factor is generating (8760 x 6 x 0.2=) 10,512 kWh per year. I assume that covers about 80% of the household’s gross demand, based on Borenstein, Journal of the Association of Environmental and Resource Economists, 2017, Table 3, and assuming slight growth in gross demand since 2007-2014. If so, according to Darghouth et al, Energy Policy, 2011, figure 6, that implies at least 50% of the electricity flows into the grid. I assume 50%, and assume that with batteries that would be reduced to 10%, that is, the batteries would allow the customer to hold 40% of the solar output behind the meter for use at another time. (This seems reasonable given that a Tesla battery holds 13.5 kWh and the daily output of this solar system is 28.8 kWh of which 40% is 11.5 kWh.) According to Tesla, the battery would lose 10% of the electricity in the round trip (thanks to Paul Chernick for pointing this omission out in the original post). If the customer faces a retail price of $0.26 and under the NEM replacement would be paid an “avoided cost” compensation of $0.08 for injections into the grid, then the payoff to the battery is (10512 x 0.36 x $0.26)-(10512 x 0.4 x $0.08)=$648 per year. By the way, I say over $648 in the post, because this assumes that a solar home would otherwise be an average consumption home. In reality, their gross consumption is above average, so due to the increasing-block pricing, the average avoided price with solar is higher than $0.26.
Note: the battery might also be creating real value to society by shifting energy from lower price to higher price hours. My point is that on top of that real value (which also exists when grid-scale batteries are used to store electricity), the private compensation to owners of behind-the-meter batteries is enhanced by $648 or so due to the gap between retail price and social marginal cost. This amount is just a cost shift, not real value to society.
Severin Borenstein is E.T. Grether Professor of Business Administration and Public Policy at the Haas School of Business and Faculty Director of the Energy Institute at Haas. He has published extensively on the oil and gasoline industries, electricity markets and pricing greenhouse gases. His current research projects include the economics of renewable energy, economic policies for reducing greenhouse gases, and alternative models of retail electricity pricing. In 2012-13, he served on the Emissions Market Assessment Committee that advised the California Air Resources Board on the operation of California’s Cap and Trade market for greenhouse gases. He chaired the California Energy Commission's Petroleum Market Advisory Committee from 2015 until its completion in 2017. Currently, he is a member of the Bay Area Air Quality Management District's Advisory Council and a member of the Board of Governors of the California Independent System Operator.