The Cost of Filling Up the Tank with Electricity
Why Californians are getting gouged at the plug.
The summer driving season is underway. We’re hearing a lot about the high cost of gasoline, nationally and in California. In relative terms, electricity to charge electric vehicles can look like a bargain. But if you dig into the numbers, utilities’ rates may be much higher than they need to be. Getting the rates right needs to be an important part of the state’s plan if consumers are to meet the California’s zero-emission vehicle target by 2030.
To start with let’s compare electricity and gasoline prices today using a recent briefing note from the International Council on Clean Transportation (ICCT). An electric vehicle owner in southern California who charges at home and has signed up for a time-of-use rate plan pays 12 cents per kilowatt-hour at night. The ICCT argues that the cost to fuel an electric vehicle should be compared to the sort of highly efficient gasoline vehicle that the driver most likely would have purchased. Following their guidance, the southern California electric vehicle owner is paying the equivalent of just $1.85 per gallon. Things are looking pretty sunny for this driver.
While it may look like California electric vehicle drivers are getting a great deal, they aren’t necessarily. The prices paid by California’s electric vehicle drivers are higher than they should be. This is likely slowing electric vehicle adoption.
The California Public Utilities Commission Tackles Rates
The state’s utilities regulator, the California Public Utilities Commission (CPUC), is not traditionally an agency focused on transportation policy. However, the agency is taking a turn behind the steering wheel to help the state accelerate towards an electrical transportation system. The CPUC is starting by focusing on charging infrastructure. Last month the CPUC approved utilities’ requests to invest over $700 million in electric vehicle charging infrastructure.
The CPUC is now taking a look at the prices that consumers pay to charge up their vehicles in their homes and at commercial facilities. This review kicked off at a forum earlier this month, starting a process that will be very important to watch, for consumers and the power system more broadly.
Forum presenters described how the prices that households and businesses pay for electricity are set through decades-old, complex regulatory processes overseen by state utility regulators. The recipe involves financial analyses, equity considerations, policy priorities and politics, which are all stirred and mixed until, voila, out comes a set of retail rates. Economic principles are sometimes sprinkled in during the process, but are hard to discern in the final concoction. Most troubling, the process results in a wide gap between the prices that households pay for electricity and the cost to produce the electricity.
According to data reported in June by the California Independent System Operator (CAISO), wholesale electricity prices averaged a just $43 per megawatt-hour ($0.66 per gallon equivalent) in 2017. Nighttime prices were even lower, as shown below in a chart from the CAISO. That means southern California electric vehicle drivers were paying at least triple the cost of producing electricity.
Illuminating new research by Severin Borenstein and James Bushnell, presented at the Energy Institute’s 2018 POWER Conference analyzes the gap in detail across the entire US. They point out that a full comparison between wholesale and retail prices needs to also consider the environmental damage caused by power generation. California’s power plants are not very polluting, so this doesn’t add much to the wholesale costs. They emphasize that the analysis also needs to account for electricity that is lost during the electricity delivery process. These costs are important, but aren’t big enough to justify the existing large gap.
The gap is actually much larger than triple for many consumers. At the forum, we heard that an estimated three-quarters of electric vehicle owners haven’t even enrolled in a time-of-use rate that lets them pay lower prices at night. Instead they are on the standard residential pricing plan. For customers of the two largest utilities these standard plans charge between 25 and 28 cents per kilowatt-hour, that’s equivalent to $3.85 to $4.35 per gallon. It’s even more extreme in San Diego where households that use more than 130% of a baseline amount could be paying as much as 48 cents per kilowatt-hour or the equivalent of $7.42 per gallon. The low adoption of the less expensive time-of-use rate shows the downside of depending on optional rates.
How California Sets Rates
Why are retail prices so much higher than wholesale electricity prices? At least two reasons. First, the utilities collect a lot of revenue to pay for all of their costs. These include the costs to build, operate and maintain its infrastrastructure, interest to lenders and a rate of return to shareholders. The costs of state-mandated programs — such as energy efficiency, subsidies for low-income households, and some early investments that were made in new renewables technologies — are also significant in California.
Second, California’s policymakers have decided that for residential customers, virtually all of the revenue will be collected from each customer in proportion to their electricity use. The alternative would be to collect some of the revenue through a fixed monthly fee.
Many other services that households depend on such as garbage and recycling collection, home internet and streaming music take the opposite approach. Customers pay a fixed monthly fee for a certain size garbage bin or level of service, but aren’t charged per pound of garbage, per Gigabyte downloaded or per song listened to. Curiously, policymakers have taken the opposite approach for electricity.
Electric vehicles highlight the downside of the way California sets residential electricity rates. Households are paying far more to charge their vehicles at home than it costs to generate and deliver the incremental electricity, even when the additional pollution is priced in. This disconnect has the potential to slow electric vehicle adoption or, at the very least, raise the cost of meeting the state’s electric vehicle goals.
Closing the Gap
Broadly speaking there are two ways to close the gap between retail and wholesale prices. One is to lower the utilities’ revenue needs. The other is to restructure rates by increasing fixed monthly charges and lowering the amount collected for each kilowatt-hour consumed. Both would be difficult.
Any move to restructure rates will need to pay attention to distributional impacts and fairness. As prior Energy Institute analysis has shown, subsidies for electric vehicles are heavily skewed toward the wealthy. Regulators should keep these considerations in mind.
While challenging, rate reform could generate big returns for the state’s environment and economy. It’s encouraging that the CPUC is looking at this issue.
Andrew G Campbell View All
Andrew Campbell is the Executive Director of the Energy Institute at Haas. Andy has worked in the energy industry for his entire professional career. Prior to coming to the University of California, Andy worked for energy efficiency and demand response company, Tendril, and grid management technology provider, Sentient Energy. He helped both companies navigate the complex energy regulatory environment and tailor their sales and marketing approaches to meet the utility industry’s needs. Previously, he was Senior Energy Advisor to Commissioner Rachelle Chong and Commissioner Nancy Ryan at the California Public Utilities Commission (CPUC). While at the CPUC Andy was the lead advisor in areas including demand response, rate design, grid modernization, and electric vehicles. Andy led successful efforts to develop and adopt policies on Smart Grid investment and data access, regulatory authority over electric vehicle charging, demand response, dynamic pricing for utilities and natural gas quality standards for liquefied natural gas. Andy has also worked in Citigroup’s Global Energy Group and as a reservoir engineer with ExxonMobil. Andy earned a Master in Public Policy from the Kennedy School of Government at Harvard University and bachelors degrees in chemical engineering and economics from Rice University.
Can you please share the calculation of how 25-28 cents/kWh translates to $3.85-4.35 per gallon? Is it based on a comparison of miles driven or energy content? Thanks
Following the ICCT’s example, I calculated the cost to travel a mile in a 2017 Nissan Leaf, which has an efficiency of 30 kWh per 100 miles >> $0.25/kWh * (30 kWh/100 miles) = $0.075 per mile. Then I assumed that if the driver had purchased a gasoline vehicle it would have been a 2017 Toyota Prius with a fuel economy of 52 miles per gallon, and calculated the equivalent gasoline price that would have cost the driver $0.075 per mile >> $0.075 per mile * 52 miles per gallon = $3.90 per gallon. In short, for the Leaf-Prius comparison to convert the electricity price in $/kWh to a gasoline price, one can multiply the electricity price by 15.6. Other likely car comparisons yield similar conversion factors.
One question is whether to compare EVs to hybrids or to the fleet average. Also, an important consideration is the difference in maintenance costs. One EV owner told me that all he does is change his wipers and fill his tires (he hasn’t owned it long enough to change the brake shoes). According to AAA, the maintenance for conventional cars is almost the same as for fuel. See https://newsroom.aaa.com/tag/driving-cost-per-mile/
Another consideration: EVs can also be revenue sources to owners who sell storage services or avoid retail purchases. That is a more complicated calculation, but can’t be ignored.
First, the CPUC uses a well vetted economic theory to set rates, called “Ramsey pricing”. It allows for full volumetric pricing in a manner that conforms with economic efficiency. http://regulationbodyofknowledge.org/tariff-design/economics-of-tariff-design/ramsey-pricing/
On the other hand, it’s not clear how a regulator would come up with the “lump sum” payment that would allow for the most economically efficient monopolistic pricing scheme. Anything other than the same lump sum for everyone, from those in affordable housing to Apple, will deviate from the efficient outcome. And we know that once we deviate, it’s not possible to determine which system is the most efficient. (Look up the theory of the second best.)
Second, the short run imbalance prices from the CAISO that you are claiming are representative of California’s marginal costs are in fact NOT the marginal costs. I’ve repeated this criticism on at least two previous UCEI blogs, and I still haven’t seen a response. The CAISO prices are used solely to balance loads at the edges after the large long-term transactions that fill 95%+ of the energy demand have already been completed and scheduled. This is like saying that the housing market price is reflected in the AirBnB bedroom rental rate. We all know that’s a fallacious metaphor. The true marginal costs are a combination of long-term contracted energy purchases, the hedge values in those purchases, and the costs of other services that are currently embedded in the utilties’ rate bases and not considered in scheduling costs at the CAISO. You can read the CalCCA testimony in the PCIA OIR for more detail on this issue.
If you want to lower electricity costs, you need to look at the mismanagement of the portfolio by the utilities. They have failed to dispose of renewable contracts in a prudent. PG&E’s RPS Procurement Plan implies a hedge value of $33/MWH (above a market value of $61/MWH) because PG&E continues to hold those contracts against a potential future “sellers market.”
You defend the CPUC ratemaking practices by asserting that they have applied Ramsey Pricing, in particular the application of the inverse-elasticity rule with respect to utility ratemaking. You also claim that LMPs do not represent the marginal costs of energy in the wholesale energy market. Let me address your second claim first as it is the easier one to explain.
An ISO dispatches all generators connected to the wholesale transmission grid, including those that have contracted to sell their energy at fixed prices. The dispatch order is determined by the generators’ hourly offer prices, which are determined by the variable running rates of each generator. These offer prices are unaffected by the terms of power contracts entered into by the generators. Why? Because the generator is always better off getting dispatched if the market energy price is higher than the its running rate and is always better off not running if the market energy price is lower than its running rate. Thus power contracts entered into in the past have no effect on generator price offers and therefore cannot determine today’s marginal costs so an ISO’s real-time LMPs ARE the marginal costs of delivering energy to a utility. Power contracts are merely financial transactions superimposed on the physical market.
Now let’s look at Ramsey pricing.
Ramsey pricing is typically treated as a constrained optimization technique in which all of the monopoly supplier’s costs must be recovered on a volumetric basis. What gets ignored is that utilities can (and should) recover a large portion of their costs through fixed monthly customer charges and demand charges.
Customer charges are typically highly inelastic because almost all customers (at least today) cannot viably disconnect from their utility system. Obviously, when battery and/or other storage technologies get cheap enough, going off-grid will be a viable option and the utility will lose its monopoly power. When that happens retail electricity prices will no longer be regulated and will be determined by competitive market forces. But that’s a topic for discussion at a later time.
Returning to the present situation, a near-optimal rate structure is one consisting of a fixed monthly customer charge, one or more peak demand charges and a dynamic energy charge that varies from hour-to-hour (or even at shorter intervals) and is indexed to the ISO wholesale market real time LMPs.
The customer charge is designed to fully recover the cost of billing the customer connecting the him/her to the distribution grid. This includes a capital carrying charge to recover the utility’s investment in all of the physical assets that are solely dedicated to serving that customer (e.g., the line drop and the last step-down transformer). These costs do not vary with the customer’s volumetric usage, therefore should not be recovered through volumetric rates.
Each peak demand charge is designed to recover the customer’s share of the capital carrying charges (and O&M charges) of the upstream assets that serve multiple customers. These charges are allocated to the customer based on his usage during the time of peak load served by those assets. Because most distribution system loads peak at different times than the whole market loads, there is a rationale for using two demand charges to separately recover the capital costs of wholesale power system and and utility’s retail distribution system.
Lastly, the volumetric energy charge is set equal to the marginal cost of delivering energy to the customer’s meter. This is equal to the ISO’s hourly (or ideally, the 5-minute) LMPs at the utility’s off-take node on the transmission system grossed up for marginal distribution losses, which vary with load and can be as high as 20 percent during the peak hours of retail demand.
All of these rates are readily calculated, though not necessarily easy to do.
Ahmad Faruqui has done a great job describing this rate structure in multiple rate proceedings. Google his work to learn more.
There is actually a more efficient way to set rates than that advocated by Ahmad but his methodology is more practical. This method utilizes scarcity pricing, rather than demand charges to recover the O&M and capital carrying costs of assets serving the customer. It does this by applying a surcharge to the customers energy rate when the loads reach the point where one of the upstream assets (eg., transformers, lines, generators, etc) serving the customer approaches its maximum load carrying capacity. The purpose of the surcharge is to price the marginal loads off the system so that the existing system capacity can be utilized to serve only the highest-valued loads. By responding to the elevated energy price signals customers voluntarily ration the available system capacity by empirically revealing how much they value their marginal loads. The attractiveness of this scheme is that it strictly adheres to basic economic principles, whereas the demand charge approach is inherently a cost allocation approach, which is not economically efficient (though certainly better than volumetric pricing alone).
Finally, let me just point out that prior to the recent rate design changes the IOU fixed customer charges were less then $1 per month, which didn’t even cover the cost of preparing the customer’s bills! I think that speaks volumes about the CPUC’s competence (or lack thereof). Reply
On wholesale pricing, you’re describing an imaginary market that economists would hope exists, But in the CAISO, the LSEs schedule in much of their contracted resources at a price of zero. So these resources that are contracted or ratebased do impact the CAISO DA/RT price because many resources are dispatched earlier in the stack then they would be if done on pure fuel merit basis. For example, Diablo Canyon is prescheduled at a price of zero (PG&E doesn’t shut it down during negative priced hours or during periods when the average is below DCPP fuel costs), not at its marginal fuel costs. Cogen QFs are similarly scheduled at zero, not at the incremental short run energy price in the PPA. (You are ignoring the “must run” resources that are acquired at the prescribed prices.) The only resources dispatched in at fuel cost (and only momentary incremental fuel costs largely excluding commitment costs) are dispatchable fossil fuel plants. Hydropower is scheduled differently, using the opportunity cost of the resource (PG&E uses a LP called TESS to estimate the shadow price.) Natural gas and hydro are longer meeting incremental load growth, and load growth is what determines marginal costs, not load balancing and transmission scheduling which is the service those resources provide today. No significant natural gas resources have been added since 2010 in California. All resources since then have been renewables–it is those long term resource acquisitions that define the true marginal cost. Taking your description to its logical conclusion, as fossil fuels are pushed off the system and only renewables with zero fuel costs are running, then the marginal cost is zero. Of course, that’s a silly notion. (And if you’re going to claim price will be set by “opportunity cost” you need to show how that will work in the current regulatory world with price caps.)
As to ratemaking, all of your points have been and are debated ad nauseum in many, many, many CPUC ratemaking proceedings. Faruqui’s work is well known at the CPUC in this debate. The point of my comment is that Campbell had not acknowledged that the CPUC already uses a recognized economic method of allocating revenues to rates, and that his proposed method is radically different, and is at the heart of an existential debate at the CPUC. If Campbell wants to be a valid contributor to this debate, he should put his rate proposals in the context of the ongoing policy debate and NOT as though its a brand new academic contribution that adds something that has not ever been considered before. (By the way, the Regulatory Assistance Program (RAP) has been extending this discussion across many other states as well.)
As for using “scarcity” pricing in retail rates–it’s never happening, at least in California, after the 2001 disaster. It’s simply not politically feasible. Just look at the price caps on wholesale prices in the CAISO.
So all of this gets us back to the fact that it is long-run resource acquisition prices that set the marginal costs in the new electricity markets, and not hourly short-run imbalance energy prices.
Long-run resource acquisition prices do not set marginal costs for the reasons that I have already stated. This is true despite the fact that many resources are offered in at zero prices in order to ensure that they get dispatched. These units do not affect the marginal price because they are inherently infra-marginal resource.
Diablo Canyon is one example (as you noted). Its variable running rate is close to zero because nuclear fuel is very cheap. But more importantly, the unit can’t be shut down for a few hours a day when market prices turn negative because it would take many hours to come back on line. The cores of US nuclear plants designs get temporarily “poisoned” when they shut down preventing them from sustaining a chain reaction. Even repeated backing off the plant causes stress and adds to its operating costs. Thus, the best practice is to run Diablo Canyon full out at all times other than when it has to be taken down for routine maintenance or refueling.
Qfs are treated as “must-run” units because their contracts typically are “take-or-pay,” so from the utility’s perspective these are zero-marginal cost resources. For obvious reasons run-of-river hydro are also zero-marginal cost resources.
Storage hydro resources are economically dispatched based on the opportunity cost of the water, which is forecasted using stochastic dynamic programming techniques.
That leaves the gas-fired units that don’t have take-o-pay contract, which are offered in at their variable running rates and thus set the marginal price in most hours, along with storage hydro.
The bottom line is that all generators are economically dispatched by the ISO – even those offered in at zero prices. And the resulting real-time LMPs ARE the marginal cost of producing energy. Day-ahead LMPs are merely short-term forecasts of the real-time LMPs and are also contractual commitments that have no effect on how generators are dispatched in real time.
“…all of your points have been and are debated ad nauseum in many, many, many CPUC ratemaking proceedings.” Maybe so. but those debates have not produced rational, economically efficient rate structures. The fact that the CPUC is only now endorsing TOU rates is an indication of just how far behind it is. TOU rates were first introduced in the late 1970s! They are static rates but were cutting edge at the time because the metering technology didn’t exist to support dynamic rates. We have that technology today and many utilities across the US have implemented dynamic rates.
“As for using “scarcity” pricing in retail rates–it’s never happening, at least in California, after the 2001 disaster. It’s simply not politically feasible.”
You may be right here. But you should never say “never.” The 2001 disaster was not created by scarcity pricing – it was created by the lack of such pricing – again a gross failure of the CPUC in not lifting the price cap on retail rates when wholesale market prices were soaring. We can thank the CPUC for supporting the high whole market rates, the blackouts, the bankruptcy of PG&E and the near-bankruptcy of SCE. Also for Governor Gray Davis being recalled.
“Just look at the price caps on wholesale prices in the CAISO.”
But just look at the $9,000/mWh energy price cap in ERCOT, which depends on scarcity pricing to keep the lights on. ERCOT does not have a capacity market and none of the generation is rate based. ERCOT is way ahead of California.
Your disagreement seems to be about whether or not generators doing self scheds and $0 (and negative bids) are “in fact” inframarginal. Clearly, the people entering those bids think they are, and are willing to take the hit of operating below (what mcubed thinks is) their marginal cost. To a first approximation shouldn’t that end the discussion? Their owners would bid them differently if doing so would earn them more money, right?
You can make an argument that policy constraints, operating rules, and perhaps even stupidity, are artificially forcing certain kinds of units lower in the stack than they “ought” to be, but I’d argue that the counterfactual “first best” marginal cost is the one that is a fiction. All the complications that make someone bid lower than what you estimate their marginal costs to be are real enough to them. Some of those complications exist for good reason, and some maybe not, but you can’t hand wave it all away.
I agree with all you say.
I also submit that generators are not stupid (at least most of them) and do submit offer prices that are in their best interests. They are in the best position to know what their marginal costs are. If the costs are low enough for the generator to consider its unit to be infra marginal, and is willing to take the risk that it may not be in some of the hours of the day, then more power to him.
The more important point I was making is that contracts entered into in the past do not affect offer prices made today – with one exception: contracts that are take-or-pay and the party buying the energy also decides the offer price. In this situation mcubed is correct; past contracts do affect the dispatch and may affect the LMP.
The misconception, that LMPs do not reflect marginal costs because most of the energy sold through long-term contracts, is a common one. A generator that has fully contracted the energy from a unit can always fulfill that contract by purchasing energy from the spot market. It the spot market price is lower then the unit’s running cost the generator can pocket the difference.
“…with one exception: contracts that are take-or-pay and the party buying the energy also decides the offer price.” Well, the one “exception” describes the vast majority of power transactions in California. And that’s why those contract transactions define the market value, not the short term imbalance market that affects a small, decreasing share of transactions.
David Jacobowitz, My point is that these other resources are self scheduled or bid at $0 (which is the vast majority in California) because the true market value is represented by market transactions that take place outside of the CAISO imbalance market. In other words, the CAISO market is not the relevant market place to derive those values. (And in fact, it was never intended to be so–the defining market value transactions were to take place in the Power Exchange, now defunct.) That may be consistent with your point.
First, if short-run energy prices represented the long-run market values, then the California utilities would have never built any of the fossil plants that were authorized between 2002 and 2010. The CAISO Annual Market Performance Reports between 2001 and 2017 show that the CAISO markets have NEVER produced sufficient revenues to justify a new entry power plant, CCGT or CT. (See http://www.caiso.com/market/Pages/MarketMonitoring/AnnualQuarterlyIssuesPerfomanceReports/Default.aspx) There are reasons why the CAISO market prices have underperformed relative to true market values that have justified adding these resources, arising from both in-market distortions (e.g., side payments for commitment costs) and early addition of resources that suppress imbalance market prices.
I know exactly why Diablo, the QFs and the other resources you list continue to run despite NOT being economic run within the CAISO merit order stack. You even highlight the contradiction with this list and then saying “Day-ahead LMPs are merely short-term forecasts of the real-time LMPs and are also contractual commitments that have no effect on how generators are dispatched in real time.” You’ve just described how the operational and contractual commitments drive MOST of the effect on the LMPs! It’s exactly those operational constraints that distort the CAISO market so much that it is NOT a useful metric for the long-term value. What you describe is a load balancing exercise (and the European transmission schedulers use these markets in this way and not as somehow being representative of energy trades) that does not reflect the true power value that is being transacted. Again, you haven’t answered why we don’t do the same in the housing market by using the nightly rental rate on AirBNB for a spare bedroom to value a house? The answer is obvious for the same reason it’s obvious that the CAISO imbalance market fails to provide the full value of the power asset.
As to revenue allocation and rate design, California has had TOU rates for non-residential customers for decades. I don’t understand your statement about the CPUC only endorsing them now. It’s only for residential that they are introducing them now, and only because smart meters enabled doing this cheaply. I’m not aware of any other states getting ahead of California on residential rate design, and SMUD is being lauded nationally for moving to default TOU (and not real time or dynamic).
But you again missed my point–California has already moved down a path of setting rates based on economic theory. You might not like Ramsey pricing, but you (and Campbell) must put your arguments in the context of the economic analysis that has already been going on since the 1980s here. You are not working with a blank slate, and just because you say it will be better by claiming its consistent with economic theory is not sufficient–we already have a rate design process consistent with economic theory (at least in the eyes of policymakers who are the intended audience)
“The 2001 disaster was not created by scarcity pricing – it was created by the lack of such pricing – again a gross failure of the CPUC in not lifting the price cap on retail rates when wholesale market prices were soaring.” Again, the wrong lesson, (and spoken like a true shareholder advocate–either of the utilities or the merchant generators.) You lament, just if the utilities could have just passed through all of their exorbitant costs while doing nothing to mitigate those costs, it all would have been better (or at least the utility shareholders would have avoided bankruptcy), even if it would have ruined the state economy. That is just avoiding true responsibility for the crisis and the fact that the utilities signed a deal to accept those price volatility risks in return for other deals such as recovering Diablo Canyon investment costs a second time. (PG&E had recovered its full investment in DCPP by January 1998, which I calculated at the time.)
No, the real cause was the failure of the CPUC (and more importantly, the State Legislature in June 2000) to allow the utilities to sign long term bilateral power contracts and TO USE THOSE CONTRACTS TO SET THE MARKET VALUE FOR THE CTC! (Getting the point again?) If that had happened, all of the incentive to manipulate the market would have disappeared and the crisis never would have happened (and price spikes would have had minimal impacts on customer bills).
Low income subsidies and EEDR for sure… but I’ve heard a rumor that legal expenses are also considerable. It would be interesting to see a broad breakdown of costs. Quick pie/bar graph of energy-EEDR-staff-legal-taxes-fees-etc.
Also, I think things will change pretty quickly after TOU becomes the default residential rate next year. I couldn’t help cringing at the comment “That is actually a confusing combo for many users.” I am curious about the evidence for this statement. The field research I’ve seen shows that time varying rates are way easier to understand than tiered rates, since pretty much everybody knows what time it is, and almost nobody knows which day of their billing cycle it is. People already understand time, and soon will become accustomed to TOU, and after that, a fixed rate plus time-varying volumetric charge seems doable.
Finally, I drive a Volt. It is my only car. It runs on electricity for 50 miles – unless I ask it to use gas for some reason (e.g. during cruise control), or until the electricity runs out – which is almost never. Once the electricity is gone, the tiny efficient gas engine revs up to recharge the electric battery, and then it like a regular gas powered car. I could drive to NY and back without charging. This seems like the perfect transition technology. I’m not sure why it’s not touted as such.
There”s a lot of unpack in this piece. For one, is it obvious or clear that EVs are the best way for the State to lower emissions? EVs are already pretty heavily subsidized. How much subsidy is enough? I’m of the opinion that policy makers have not completely thought through the implications of mass EV adoption. For example, if an EV has 1/3 the range of a gas vehicle and takes 2 hours to charge instead of 4 minutes to fill, does that mean we need 90x as many charging stations as we have gas pumps? Even accounting for people charging home, that’s quite an infrastructure investment. We know a lot of people do not have SFH with private parking spaces, right?
As for rates, its easy to throw stones, but rate designers are dealing with political as well as economic constraints. They are also dealing with the conceptual limitations of their user bases. Spotify and Comcast have subscription models, but they do not have subscription PLUS volumetric charges. How about a fixed price plus a time-varying volumetric charge? That is actually a confusing combo for many users. And unlike most of the examples, electric service is kind of a must-have. I’m not saying don’t go there, but do plan on rough seas.
Another consideration is that the high marginal price of electricity drives (or justifies) a high level of energy efficiency and other consumption-reducing behaviors. You might make a compelling argument that the marginal price consumers see is way too high compared to real marginal costs and so we’re getting too little consumption but 1) enjoy having that conversation with environmentally minded policy makers and 2) if you switch to fixed + lower marginal costs, you can expect significant changes in consumer behavior. At the least, you’ll want to adjust all your DR and EE programs, and probably recalibrate your expectations. There are a lot of moving parts.
You’re absolutely right. Almost certainly California (and some other states like Massachusetts) have over-subsidized the sacred cow, energy efficiency. But why should we not tell the truth about this? To hell with placating the “…environmentally minded policy makers.” They have greatly exacerbated the exorbitant cost of living in California. Then they want to protect the low-income people from the high costs they have created by making the rest of the population subsidize the low-income people.
Consider the huge increase in the IOU’s electric rates that are coming down the pike. Then consider the CPUC mandates for installing large amounts of high cost energy storage. There is a clear cause and effect at work here.
I note that Pacific Gas & Electric (PG&E) provides multiple EV charging stations at its “Energy Education Center” at 6588 Ontario Rd, San Luis Obispo, CA 93405 with very competitive power rates. I wonder if other environmentally-minded employers are doing the same thing?
SCE’s TOU rates are much lower than mine here in San Diego – I have SDG&E’s EV-TOU-2 rate, as I charge 1 EV at home. The rate – super off-peak (12-6 am weekdays, 12 – 2 pm weekends and holidays) summer – is $0.22801/kWh. Except for during weekends and holidays I suppose I am charging when there is little by way of renewables on the grid. My super off peak rate is much higher than SCE’s. Do you have studies that assess the rate differences between utilities?
I haven’t seen a side-by-side comparison of rates, but this document from the CPUC includes many EV rates, residential and commercial. It doesn’t include the generally applicable household rates though.
Thanks, I’ll check it out – do you have the range for the wholesale prices?
Alberta government caps power prices at 6.8 cents per kilowatt hour – that’s 6.8 cents Canadian
Cost to run an EV for a year <$200
Sadly hardly anyone in Alberta knows this so few EV sales
The incompetence of the CPUC in setting retail electric rates has long been known among energy economists. Still, the revelation that the current rate structures are causing owners of electric vehicles to pay as high as $7.42 per gallon of gasoline-equivalent is startling. When are Californians going to wake up and take political action to rein in the CPUC?
I’m wondering if you have included the cost of taxes/fees, etc. that are on the electric bill and ofter tied to the number of kilowatts consumed (here in Maryland, to the net number of kilowatts used for those who have residential solar)? For us, these fees (and they include delivery costs) actually up the net cost per kilowatt used by almost 50% (and, of course, also up the savings from having residential solar). For the gasoline prices, you are presumably including taxes, so would this not be appropriate to do on the electricity side?