Tag Archives: DER

Why are real-time electricity retail rates no longer important in California?

The California Public Utilities Commission (CPUC) has been looking at whether and how to apply real-time electricity prices in several utility rate applications. “Real time pricing” involves directly linking the bulk wholesale market price from an exchange such as the California Independent System Operator (CAISO) to the hourly retail price paid by customers. Other charges such as for distribution and public purpose programs are added to this cost to reach the full retail rate. In Texas, many retail customers have their rates tied directly or indirectly to the ERCOT system market that operates in a manner similar to CAISO’s. A number of economists have been pushing for this change as a key solution to managing California’s reliability issues. Unfortunately, the moment may have passed where this can have a meaningful impact.

In California, the bulk power market costs are less than 20% of the total residential rate. Even if we throw in the average capacity prices, it only reaches 25%. In addition, California has a few needle peaks a year compared to the much flatter, longer, more frequent near peak loads in the East due to the differences in humidity. The CAISO market can go years without real price deviations that are consequential on bills. For example, PG&E’s system average rate is almost 24 cents per kilowatt-hour (and residential is even higher). Yet, the average price in the CAISO market has remained at 3 to 4 cents per kilowatt-hour since 2001, and the cost of capacity has actually fallen to about 2 cents. Even a sustained period of high prices such as occurred last August will increase the average price by less than a penny–that’s less than 5% of the total rate. The story in 2005 was different, when this concept was first offered with an average rate of 13 cents per kilowatt-hour (and that was after the 4 cent adder from the energy crisis). In other words, the “variable” component just isn’t important enough to make a real difference.

Ahmad Faruqui who has been a long time advocate for dynamic retail pricing wrote in a LinkedIn comment:

“Airlines, hotels, car rentals, movie theaters, sporting events — all use time-varying rates. Even the simple parking meter has a TOU rate embedded in it.”

It’s true that these prices vary with time, and electricity prices are headed that way if not there already. Yet these industries don’t have prices that change instantly with changes in demand and resource availability–the prices are often set months ahead based on expectations of supply and demand, much as traditional electricity TOU rates are set already. Additionally, in all of these industries , the price variations are substantially less than 100%. But for electricity, when the dynamic price changes are important, they can be up to 1,000%. I doubt any of these industries would use pricing variations that large for practical reasons.

Rather than pointing out that this tool is available and some types of these being used elsewhere, we should be asking why the tool isn’t being used? What’s so different about electricity and are we making the right comparisons?

Instead, we might look at a different package to incorporate customer resources and load dynamism based on what has worked so far.

  • First is to have TOU pricing with predictable patterns. California largely already has this in place, and many customer groups have shown how they respond to this signal. In the Statewide Pilot on critical peak period price, the bulk of the load shifting occurred due to the implementation of a base TOU rate, and the CPP effect was relatively smaller.
  • Second, to enable more distributed energy resources (DER) is to have fixed price contracts akin to generation PPAs. Everyone understands the terms of the contracts then instead of the implicit arrangement of net energy metering (NEM) that is very unsatisfactory for everyone now. It also means that we have to get away from the mistaken belief that short-run prices or marginal costs represent “market value” for electricity assets.
  • Third for managing load we should have robust demand management/response programs that target the truly manageable loads, and we should compensate customers based on the full avoided costs created.

Relying on short term changes diminishes the promise of energy storage


I posted this response on EDF’s blog about energy storage:

This post accepts too easily the conventional industry “wisdom” that the only valid price signals come from short term responses and effects. In general, storage and demand response is likely to lead to increased renewables investment even if in the short run GHG emissions increase. This post hints at that possibility, but it doesn’t make this point explicitly. (The only exception might be increased viability of baseloaded coal plants in the East, but even then I think that the lower cost of renewables is displacing retiring coal.)

We have two facts about the electric grid system that undermine the validity of short-term electricity market functionality and pricing. First, regulatory imperatives to guarantee system reliability causes new capacity to be built prior to any evidence of capacity or energy shortages in the ISO balancing markets. Second, fossil fueled generation is no longer the incremental new resource in much of the U.S. electricity grid. While the ISO energy markets still rely on fossil fueled generation as the “marginal” bidder, these markets are in fact just transmission balancing markets and not sources for meeting new incremental loads. Most of that incremental load is now being met by renewables with near zero operational costs. Those resources do not directly set the short-term prices. Combined with first shortcoming, the total short term price is substantially below the true marginal costs of new resources.

Storage policy and pricing should be set using long-term values and emission changes based on expected resource additions, not on tomorrow’s energy imbalance market price.

The 20-year cycle in the electricity world


The electricity industry in California seems to face a new world about every 20 years.

  • In 1960, California was in a boom of building fossil-fueled power plants to supplement the hydropower that had been a prime motive source.
  • In 1980, the state was shifting focus from rapid growth and large central generation stations to increased energy efficiency and bringing in third-party power developers.
  • That set in motion the next wave of change two decades later. Slowing demand plus exorbitant power contract prices lead to restructuring with substantial divestiture of the utilities’ role in generating power. Unfortunately, that effort ended up half-baked due to several obvious flaws, but out of the wreckage emerged a shift to third-party renewable projects. However, the state still didn’t learn its lesson about how to set appropriate contract prices, and again rates skyrocketed.
  • This has now lead to yet another wave, with two paths. The first is the rapid emergence of distributed energy resources such at solar rooftops and garage batteries, and development of complementary technologies in electric vehicles and building electrification. The second is devolution of power resource acquisition to local entities (CCAs).

Electric industry tries the “big lie”


The Edison Electric Institute has floated the idea that demand charges should be renamed as “efficiency rates.” Demand charges measure the maximum use in a month, and once a customer reaches that demand level in a month, a portion of the usage is free below that demand level. Providing power for free encourages more use, not less, which is the opposite of what “efficiency rates” should do.  Apparently this proposal is part of a larger effort to relabel everything that utilities find objectionable, such as distributed energy resources.

Demand charges can have a place in rate making, but the best such tool, made feasible by the rollout of “smart meters,” is daily demand charges that reset each day.


Commentary on CPUC Rate Design Workshop


The California Public Utilities Commission (CPUC) held a two-day workshop on rate design principles for commercial and industrial customers. To the the extent possible, rates are designed in California to reflect the temporal changes in underlying costs–the “marginal costs” of power production and delivery.

Professor Severin Borenstein’s opening presentation doesn’t discuss a very important aspect of marginal costs that we have too long ignored in rate making. That’s the issue of “putty/clay” differences. This is an issue of temporal consistency in marginal cost calculation. The “putty” costs are those short term costs of operating the existing infrastructure. The “clay” costs are those of adding infrastructure which are longer term costs. Sometimes the operational costs can be substitutes for infrastructure. However we are now adding infrastructure (clay) in renewables have have negligible operating (putty) costs. The issue we now face is how to transition from focusing on putty to clay costs as the appropriate marginal cost signals.

Carl Linvill from the Regulatory Assistance Project (RAP) made a contrasting presentation that incorporated those differences in temporal perspectives for marginal costs.

Another issue raised by Doug Ledbetter of Opterra is that customers require certainty as well as expected returns to invest in energy-saving projects. We can have certainty for customers if the utilities vintage/grandfather rates and/or structures at the time they make the investment. Then rates / structures for other customers can vary and reflect the benefits that were created by those customers making investments.

Jamie Fine of EDF emphasized that rate design needs to focus on what is actionable by customers more so than on a best reflection of underlying costs. As an intervenor group representative, we are constantly having this discussion with utilities. Often when we make a suggestion about easing customer acceptance, they say “we didn’t think of that,” but then just move along with their original plan. The rise of DERs and CCAs are in part a response to that tone-deaf approach by the incumbent utilities.

Fighting the last war: Study finds solar + storage uneconomic now  | from Utility Dive

“A Rochester Institute of Technology study says a customer must face high electricity bills and unfavorable net metering or feed-in policies for grid defection to work.”

Yet…this study used current battery costs (at $350/KW-Hr), ignoring probably cost decreases, and then made more restrictive assumptions about how such a system might work. It’s not clear if “defection” meant complete self sufficiency, or reducing the generation portion (which in California about half of electricity bill.) Regardless, the study shows that grid defection is cost-effective in Hawaii, confirm the RMI findings. Even so, RMI said it would take at least 10 years before such defection was cost-effective in even the high-cost states like New York and California.

A more interesting study would be to look at the “break-even” cost thresholds for solar panels and batteries to make these competitive with utility service. Then planners and decision makers could assess the likelihood of reaching those levels within a range of time periods.

Source: A study throws cold water on residential solar-plus-storage economics | Utility Dive

And then this…Trump’s energy plan doesn’t mention solar – The Washington Post

After the release of a study showing solar now employs more than oil, gas and coal combined.

Source: Trump’s energy plan doesn’t mention solar, an industry that just added 51,000 jobs – The Washington Post

Cheap energy storage may be parked in your garage

One of the key questions about how to bring in more renewables is how do we provide low-cost storage? Batteries can cost $350 per kilowatt (kW) and pumped storage somewhat lower. Maybe we should think about another potential storage source that will be very low cost: automobiles.

California has about 24 million autos. The average horsepower is about 190 HP which converts to about 140 kW. Let’s assume that an EV will have on average a 100 kW engine. Generally cars are parked about 90% of the time, which of course varies diurnally. A rough calculation shows that about 2,000 GW of EV capacity is available with EVs at 100% of the fleet. To get to 22 GW of storage, about 1% of the state’s automobile fleet would need to be connected as storage devices. That seems to be an attainable goal. Of course, it may not be possible for the local grid to accommodate 100 kW of charging and discharging and current charging technologies are limited to 3 to 19 kW. So assuming an average of a 5 kW capability, having 20% of the auto fleet connected would still provide the 22 GW of storage that we might expect will be required to fully integrate renewables.

The onboard storage largely would be free–there probably are some opportunity costs in lower charging periods that would have to be compensated. The only substantial costs would be in installing charging stations and incorporating smart charging/storage software. I suspect those are the order of tens of dollars per kW.