Can Net Metering Reform Fix the Rooftop Solar Cost Shift?
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 View All
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.
If start charging customers their share of fixed costs as a fixed monthly service fee then low usage customers would face have few kwhs of electricity to spread out the fixed service fee. That will cause low usage customers who don’t need much battery storage to simply disconnect from the grid and leave fewer customers to pay for the fixed costs.
There is also an argument that rooftop solar reduces fixed costs because fewer transmission lines are needed when the power is being supplied by a neighbor than a distant power plant.
Regardless, in practical terms, a practical solution is to reduce NEM from 1:1 equal cost to paying the utility a competitive rate for what is conceptually a service of storing the electricity and delivering it later. That would be above the general cost of generation because this electricity is being generated among customers and not needing most of the transmission grid.
A good article. Home battery storage may also be affected by Vehicle to Grid (V2G) technology. Electric cars with batteries in the 35 kwh and up storage are now one of the cheapest battery storage devices. A used Nissan Leaf can be had for $4,000 still having 10-14 estimated kwh storage. For those of us working at home with an electric car plugged in most of the time V2G storage is viable. Presumably the technology will allow internet enabled electric cars plugged into the grid to charge and discharging as the price of power fluctuates during the day. An owner could program the car to require at least a 30 or 40% minimum battery capacity be available. If an owner is going on a long trip the next day they would just specify a100% full battery for the next day. Eventually If indeed the vehicle fleet is gradually replaced with electric vehicles then this may have a significant effect on storage. It will be important to get incentives correct for the lowest cost of CO2 reduction rather than the current situation with home solar.
V2G may be available in the US soon see: https://www.greencarreports.com/news/1127590_nissan-leaf-as-home-energy-device-wallbox-will-soon-enable-it-in-the-u-s
Presumably the price will come down as V2G systems are developed.
We should talk of comparisons and costs with actual use trends. If property values factors in energy efficiency we might start seeing change. When people understand that they can be quite comfortable at 74deg in the summer and 65 in the winter usage growth may slow.
Residential users should also have a fixed factor of peak use in their billing. So there is a permanent fixed charge of [say] $10-50 pm based on MAX draw ever, like the diameter of a water pipe sets max flow rate. Then there is a ‘variable fixed’ peak usage during the month. Finally the actual kwh usage. A+B+c. If someone drops off the grid, the utility can disconnect the related power lines, and save at least on maintenance.
This will mean that the utility must be ‘willing’ to shrink its customer base, revenue, and profit. But that is contrary to the expectation of ‘always growth’. Until then, we are just talking and shifting the shells around.
First I wholeheartedly agree with Jim Lazar’s analysis and those who pointed out that shrinking the utility system may be the more appropriate response. (More on the latter below.) Economists are universally guilty of status quo bias in which we (since I’m one) too often assume that changing from the current physical and institutional arrangement is a “cost” in an implicit assumption that the current situation was somehow arrived at via a relatively benign economic process. (The debate over reparations for slavery revolve around this issue.)
There are several issues to be considered in this analysis.
1) In looking at the history of the NEM rate, the emergence of a misalignment between retail rates that compensate solar customers and the true marginal costs of providing service (which are much more than the hourly wholesales price–more on that later) is a recent event. When NEM 1.0 was established residential rates were on the order of 15 c/kWh and renewable power contracts were being signed at 12 to 15 c/kWh. In addition, the transmission costs were adding 2 to 4 c/kWh. This was the case through 2015; NEM 1.0 expired in 2016. NEM 2.0 customers were put on TOU rates with evening peak loads, so their daytime output is being priced at off peak rates midday and they are paying higher on peak rates for usage. This despite the fact that the difference in “marginal costs” between peak and off wholesale costs are generally on the order of a penny per kWh. (They also pay a $10/mo fixed charge that is close to the service connection cost.) Calculating the net financial flows is more complicated and deserve that complex look than what can be captured in a simple back of the envelope calculation.
2) If we’re going to dig into subsidies, the first place to start is with utility and power plant shareholders. If we use the current set of “market price benchmarks” (which are problematic as I’ll discuss), out of PG&E’s $5.2 billion annual generation costs, over $2 billion or 40% are “stranded costs” that are subsidies to shareholders for bad investments. In an efficient marketplace those shareholders would have to recover those costs through competitively set prices, as Jim Lazar pointed out. One might counter those long term contracts were signed on behalf of these customers who now must pay for them. Of course, overlooking whether those contracts were really properly evaluated, that’s also true for customers who have taken energy efficiency measures and Elon Musk as he moves to Texas–we aren’t discussing whether they also deserve a surcharge to cover these costs. But beyond this, on an equity basis, NEM 1.0 customers at least made investments based on an expectation, that the CPUC did not dissuade them of this belief (we have documentation of how at least one county government was mislead on this issue in 2016). If IOUs are entitled to financial protection (and the CPUC has failed to enact the portfolio management incentive specified in AB57 in 2002) then so are those NEM customers. If on the other hand we can reopen cost recovery of those poor portfolio management decisions that have led to the incentive for retail customers to try to exit, THEN we can revisit those NEM investments. But until then, those NEM customers are no more subsidized than the shareholders.
3) What is the true “marginal cost”? First we have the problem of temporal consistency between generation vs. T&D costs. Economists love looking at generation because there’s a hourly (or subhourly) “short run” price that coincides nicely with economic theory and calculus. On the other hand, those darn T&D costs are lumpy and discontinuous. The “hourly” cost is basically zero and the annual cost is not a whole lot better. The current methods debated in the General Rate Cases (GRC) relies on aggregating piecemeal investments without looking at changing costs as a whole. Probably the most appropriate metric for T&D is to calculate the incremental change in total costs by the number of new customers. Given how fast utility rates have been rising over the last decade I’m pretty sure that the “marginal cost” per customer is higher than the average cost. (And with static and falling loads, I’m not even sure how we calculated the marginal costs per kwh.) (I may have the data over the last two decades to make this calculation.) So how do we meld one marginal cost that might be on a 5 minute basis with one that is on a multi-year timeframe? This isn’t an easy answer and “rough justice” can cut either way on what’s the truly appropriate approximation.
4) Even if the generation cost is measured sub hourly, the current wholesale markets are poor reflections of those costs. Significant market distortions prevent fully reflecting those costs. Unit commitment costs are often subsidized through out of market payments; reliability regulation forces investment that pushes capacity costs out of the hourly market, added incremental resources–whether for added load such as electrification or to meet regulatory requirements–are largely zero-operating cost renewables of which none rely on hourly market revenues for financial solvency; in California generators face little or no bankruptcy risk which allows them to underprice their bids; on the flip side, capacity price adders such as ERCOT’s ORDC overprices the value of reliability to customers as a backdoor way to allow generators to recover investments through the hourly market. So what is the true marginal cost of generation? Pulling down CAISO prices doesn’t look like the primary source of data.
We’re left with the question of what is the appropriate benchmark for measuring a “subsidy”? Should we also include the other subsidies that created the problem in the first place?
Hawaii is a little bit ahead of California in addressing this issue, in part because a higher percentage of customers (about 17%) in Hawaii have PV systems. Like California, they have moved in stages, first ending traditional NEM (as California did about five years ago.
But they used different approaches. California simply made solar customers pay about three cents/kWh for “nonbypassable” costs, but otherwise left NEM in place. Hawaii first imposed a moratorium on new NEM. That resulted in hundreds of customers installing solar plus storage, and discontinuing utility service entirely. So Hawaii moved next to “customer self-supply” where export to the grid was prohibited, but customers could install and use solar for on-site usage; most of these systems also have batteries, but customer can pay a $25 per month “minimum charge” and still access the grid for additional power as needed, at non-discriminatory rates. Now Hawaii has moved to a “smart export” policy, where the utility controls when power may be sent to the grid, and the solar customer receives a payment only equal to the costs avoided by the utility during those hours.
The pricing challenge as electric utilities have a new competitor is an interesting one for regulation. The primary role of regulation is to prevent the exercise of monopoly pricing power. Others are to ensure the adequacy of supply, and to achieve other defined societal goals.
In competitive markets, you normally don’t pay a fixed fee for service. Whether at the supermarket, the hardware store, the clothing store, or a furniture store, the cost of the production, transmission, distribution, and customer service is all built into the selling price. If you buy a basket full of groceries, you pay a much bigger share of the cost of the supermarket, the parking lot, the electric bill, and the staffing than you pay if you just pick up a jug of milk and a loaf of bread. Volumetric electricity pricing is the non-discriminatory equal of that. Fixed charges are only justified for the customer-specific costs: the costs of connection to the grid, not the cost of the grid itself.
Yes, Costco is an exception to that principle that you don’t pay fixed charges in the competitive world…except that their membership fee is only about 1-2% of their revenue; the electric equivalent would be a fixed charge of $1 to $2 per month. And, as a Costco Executive member, my annual rebate (2% of purchases) is usually about equal to my annual membership fee ($120), so it’s really a net-zero membership fee. Cellular service plans have high fixed charges, but include all-you-can-eat talk and text, and a substantial serving of data as well; prepaid cellular plans, like Tracfone, are available for as little as $4/month.
If solar customers are subjected to high fixed charges, an increasing number will choose to pull the plug (or, as has happened in Hawaii, consolidate their service with an adjacent dwelling into a single meter). If, instead, they are subjected to fair terms and conditions — and paid no more for their export to the grid than any other power supplier would be paid (an amount much smaller than the retail rate credit under NEM), they may stick around. The latter is better for non-solar customers than having them leave, as Hawaii has discovered. We non-participants get the benefit of a low-cost supply of clean, reliable power, for which we pay no more to our neighbor (who keeps some of the money in our community) than we would pay to a distant corporation. We also gain reliability, because it’s local, and avoid the line losses of long transmission distances.
The utility line extension policy is an important piece of this. Most utilities only extend service to a new area if there is enough business to justify the expansion. They usually measure that by the “distribution margin” expected from the sales that will occur. With volumetric pricing, that “margin” is driven by expected kWh sales. Because the cost of the grid expansion is justified by expected volumetric sales, and the grid costs are built into volumetric prices, it does not matter if the circuit is expected to have 2 Wal-mart stores, 20 smaller office buildings, or 200 residential customers; any of those will generate enough business to justify building a new circuit. More important, with volumetric recovery of distribution costs, if the costs are billed by usage, any combination of small, medium, and large customers will justify the grid expansion, and each will pay a ratable share of the cost, with the big customers paying more and the small customers paying less (just like in a supermarket).
For more discussion of these issues, please see three publications I worked on while at the Regulatory Assistance Project:
Smart Rate Design for a Smart Future: http://www.raponline.org/featured-work/smart-rate-design
Electric Cost Allocation for a New Era: https://www.raponline.org/knowledge-center/electric-cost-allocation-new-era/
Designing Distributed Generation Tariffs: http://www.raponline.org/document/download/id/6898
I also co-authored a paper on Distribution Pricing with DERs, with Ryan Hledik of the Brattle Group, in a project sponsored by Lawrence Berkeley National Labs. This was an interesting series of paper, where LBNL paired up experts with very different perspectives, and forced us to prepare a cooperative project. We identified several different approaches (of which NEM is NOT one of them) to provide fair compensation to DER owners. It’s not just a little bit on the esoteric side — I call it “the paper that will be little noted nor long remembered.”
Click to access LBNL-RAP-Hledik_Lazar-DRPricing-2016-May-23.pdf
My basic opinion is that we have many preferences and subsidies in electricity rates. NEM is one of them, but it is not larger than these other rate preferences:
1) Urban customers (close together) cost less to serve than rural and suburban customers (farther apart); on most systems, they pay the same rates. That’s a huge subsidy.
2) Customers served by overhead lines (cheaper) cost less to serve than customers served by underground lines (more expensive, more reliable, and less visual pollution). That’s a huge subsidy.
3) Multi-family customers (up to 100 customers per transformer and service drop) are cheaper to serve than single-family customers (often only a few customers per transformer, and each has a dedicated service drop). This is where California’s inclining block rates have produced some “rough justice” by allowing smaller-use customers (who mostly, but not entirely, are apartment dwellers) to pay lower average costs than larger-use (mostly single-family) customers. Nevada Energy, Burbank, Riverside, and a few other utilities have addressed this directly, with lower rates for multi-family customers; the CPUC has not.
Smart Rate Design for a Smart Future presented policies to address each of these, and to address NEM as well. The solution includes:
a) a monthly “site infrastructure” charge that is computed to fully recover the costs of connecting customers to the grid;
b) time-varying pricing, which has oodles of benefits.
c) time-varying credits for customers providing power back to the grid, and appropriate credits for DER customers providing other grid services, like frequency regulation and voltage support.
That combination ensures that a solar customer with a big connection to the grid pays an appropriate site infrastructure charge, and also ensures that a solar customer that pumps power into the grid at low-cost hours and takes power from the grid at high cost hours is charged a significant amount for “using the grid as a battery.” What it does not do is to discriminate against the solar customer by making them pay a disproportionate share of the cost of the distribution circuit itself, since that investment is controlled by the line extension policy that only runs circuits where there is enough business to justify the investment.
Bottom line: I agree with Dr. Borenstein that there is a problem. I disagree on the optimal solution.
Thanks Severine: These are important issues.
Note that the marginal cost of supply (or the marginal cost savings of decreased demand) is not determined by a single unitary formula. If utilities and engineers structure their supply system to take advantage of new cost savings opportunities from decreased demand many of the “fixed cost” overheads can be reduced.
Distribution and transmission infrastructure can be downsized. Low income programs can give low income households solar and batteries. Utility-based efficiency programs can be downsized, as can research and other overhead costs.
Your assumption that all of these overhead costs are fixed–along with the current structure of the utility business model is a bias.
Hopefully, future discussions can be less biases by mentioning and considering the possibility that many if not most of the overhead costs associated with retail electricity can potentially be downsized in proportion to electricity demand.
Maintaining a focus on decreasing all electricity-related costs in tandem with decreasing solar and battery costs just may reveal the true least-cost solution to electricity supply in California.
Of course,downsizing is a business strategy that utilities and public energy professionals certainly don’t like. But it may yield the greatest value to consumers in aggregate over the long term.
The long term technical trends are clear. For many-if not most-households, off-grid power supply will be the least-cost power supply in 10 to 20 years as billions of people globally adopt such technologies. Technological learning and economies of production scale are likely to produce further dramatic cost reductions.
Rather than resisting this long-term transition, from a public interest perspective we should facilitate it. Let’s focus on reducing all categories of costs for everybody, rather than promoting a biased assertion that some subset of costs have to be fixed, thus we should erect barriers against non-utility solar and battery-based cost reductions.
Consider the possibility that maybe, just maybe, key aspects of the utility business model are becoming obsolete, and the whole institutional infrastructure of utility-based electricity supply may inevitably need to shrink: Including perhaps, some of the research performed by Haas.
Now I finally understand your point about subsidy… but, what if the fixed costs and variable costs were correctly accounted for, and people paid their true fixed costs (maybe total fixed costs paid by KW??)…. and that the variable cost of PV was “net metered”….
One factor you did not address is conservation incentive…. the electrons produced by my PV system have the same value to me whether or not they displace my purchase from the grid or I send them to the grid. I have the same incentive to conserve my electricity consumption. If I only got wholesale for the electrons my PV system produces and sends to the grid, then maybe I would let my A/C run more, and “pre-chill” my house???
I think of the grid (SMUD, for me) as a “battery that stores my electrons until I use them”…. I haven’t felt compelled to install any batteries at my house… the payback period (just from time shifting) wasn’t worth it, according to my calculations.
Severin, you forgot the losses in the battery. The battery value to the customer (at 80% efficiency) is more like:
10512 x 0.4 x $0.26 – 10512 x 0.32 x $0.08 = $538.
Also, I think you are dismissing the benefit of the additional energy being shifted into the peak costing period, which starts as the solar output trails off. The $538 would be offset by the timing benefit; it is not in addition.
Similarly, you are incorrect in asserting that ” 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.” True, fixed costs are shifted, but that is not the only effect.
thanks Paul. Good point on the losses, though Tesla claims the round trip efficiency of its battery is 90%, not 80%, which would put the savings somewhere around $648. At the end of my extended footnote, I do recognize the social value of storing and implicitly assume that the time varying retail rates will reflect that, but still with the $0.18 adder to recover fixed costs.
Re: “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.”
Maybe the answer is to pay for all of those necessary things you list here not out of electricity rate revenues but rather out of the State-wide budget since the benefits from (most of) those programs are diffuse and not directly related to personal consumption.
Yes!! See my previous blog, https://energyathaas.wordpress.com/2020/11/16/reinventing-fixed-charges/
Thanks for the note Severin. Several comments on it-which I’m sure you’ve thought about and welcome your responses.
How accurate are the assumptions you used in your calculations? I hope utility folks or others can chime in and confirm or improve them with the data they have. Household electricity use (see RASS or other State data) varies mostly between ~ 4-5 MWh/yr to slightly above 10 MWh/y – depending on whether you live in apartments near the coast or further inland, where a/c use in the Summer leads to higher use. Most customers in the Bay Area use 5 to 7 MWh/y. Again-hope utility folks can offer more details. A 6kW system appears to be oversized-and likely is for folks who have an EV.
You also talk about social cost–alas, there I think we really do NOT include the full social costs in both wholesale and retail prices. What are the social costs if we include the full impacts of climate change?
I’d like to see more analyses of externalities and more importantly, to see them reflected in the prices we customers see.
Some studies have shown fossil fuel subsidies to be enormous–yet we often pay these in our taxes and not at the point-of-sale.
In the long run, what is cheaper for society–distributed rooftop/community systems or ongoing reliance on a central (or even micro) grid based system? Unclear at this point.
NEM and other policies are intended to help bring to maturity technologies and markets that are perceived to offer more social benefits (some of which are hard to quantify – e.g., better health due to reduced air pollution). They are considered less competitive (often because their immature markets have significant higher initial transaction costs), but if we did better accounting and internalization of externalities, and prices reflected these, their value to society would be easier to compare with that of incumbent technologies and then we would also have to hope that customers would behave as “Rational, Economic Consumers” and chose accordingly.
Although somewhat tangential to the theme of this article, the quest for sound energy policy in California is badly hobbled by the multitude of conflicting social and economic policies the CPUC is attempting to address, in large measure due to pressure from interest groups that seem to have tunnel vision. To the extent affluent ratepayers are being subsidized by the less wealthy, it’s also true that policies intended to reduce the economic burden on low income customers (and however inadvertently at one point, producers of a certain agricultural product that has since been legalized) have been subsidized by wealthier customers, thereby creating the economic headroom for solar. Maybe others can untangle the mess but I can’t, at least not without upsetting lots and lots of people.
There’s an old saying that goes, “when everything is a priority nothing is a priority”. The problem Severin highlights is likely not only going to stay with us but get much worse until and unless a group of adults makes some tough decisions to focus on a very few policy priorities and then has the intestinal fortitude to stand by them.