I just got back from an annual conference put on by the Center for Research in Regulated Industries. It brings together many of the applied economists and policy analysts working in California’s electricity industry. I presented a paper on reconsidering rate design.
Customers are often left out of the conversation about how to move forward into the new energy future, as they were at the recent CAISO Symposium where not a single customer representative was included in the “Town Hall Meeting.” Current retail rate tariffs seem to be designed with little thought about how customers would prefer to pay for their energy, and what might best encourage consumer energy management. And when customers are asked to take on more risk or cost to address energy needs, their revenue responsibility is often unchanged.
How should utilities align their rates and tariffs to fit customers’ preferences? Utilities both face a rapidly evolving energy marketplace and have available to them a larger portfolio of technologies to provide more services and to measure usage across different dimensions. One important step that utilities could take is to offer customers the same variety of contracts as the utilities make with their suppliers, so that rates mirror the power market.
Customers have a range of preferences, and some prefer to be more innovative or risk takers than others. To better match the market, should utilities offer a range of tariffs, and even allow customers to construct a portfolio of rates that allow a mix of hedging strategies? How should the costs be allocated equitably to customers to reflect the varying risks in those portfolios? How should the benefits of lower costs be allocated between the active and passive customers? The new metering infrastructure also provides opportunities for different billing strategies.
How should time varying rate (TVR) periods be structured to adapt to the potential shift over time when peak meter loads occur? Should the periods be defined by utility-side resources or the combination with customer-side resources? Is the meter an arbitrary division for setting the price? What is the balance between rate stability to encourage customer investment versus matching changing system costs? Should the utilities offer different TVR periods depending on the desired incentives for customer response?
In developing costs, how should utilities and commissions consider how resources are added, and in what capacity? Renewables are now part of the incremental resources for “new” load, and we can no longer rely on the assumption that fossil fuels are the marginal resource 100% of the time.
The “super off-peak” rate offered by Southern California Edison (SCE) to agricultural customers is one example of how a rate can be constructed to encourage customer participation in autonomous ongoing energy management. Are the incentives appropriate for that rate? Over what term should these rates be set given customer investment?
If you’re interested in this paper, drop me a line and I’ll send it along.
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PG&E just implemented a rate design change for the residential market (on August 1, 2014). The changes are noted below:
Rate Design change for PG&E effective August 1, 2014
Tier Price/kWh July 2014 Price/kWh August 2014 % Change
1 .1323 .14707 +7.93
2 .1504 .1703 +9.93
3 .31916 .259 -18.93
4 .35916 .31859 -11.38
5 .35916 .31859 -11.38
1 .08565 .09484 +10.73
2 .09850 .1063 +7.92
3 .13974 .15081 +7.92
4 .13974 .15081 +7.92
5 .13974 .15081 +7.92
Baseline levels down 10%+/-
Source: PG&E rate schedules crunched by M. Miller 8/22/14, PG&E verified by phone that the rate design change was revenue neutral- the 5.9% rate increases scheduled for later this year are NOT include in the table above. The TOU rate schedules also changed. E-7 Summer schedule Off peak changes= Tier 1 +12.9%, Tier 2+14,9%, Tier 3 -22.7%. Tier 1 Peak change= + 3.25%.
Hi Richard. Thanks for this – I too would enjoy seeing the paper. I have thought for several years that we would soon need to get to rate design, and indications are that this is beginning. I am involved in a case in Wisconsin in which the utility is proposing a fairly extreme rate re-design. I am sure we will see more. Unfortunately, these looks are likely to occur in too narrow a context, without thought of the growing diversity among energy end-users or of differences in use of the electric system that could make a difference if utilities stopped planning for just 3 “model” accounts: one residential, one “commercial” and one industrial. It’s nice to know someone else is out there thinking about rate design in non-traditional ways and willing to ask questions that don’t have easy answers.
I’ll send it to you. Look forward to further discussion. Thank you.
I’d love to have a copy of the paper- Thanks for noting it above.
I’ve been a TOU electrical energy customer of PG&E’s for 8.5 years, and I can confirm that we adjust our behavior in response to peak time pricing. Our electric dryer does not get used during peak times. We have a legacy TOU rate, E-7 with net metering as we have a small PV system.
Over the years I have come to understand why PG&E, SCE, etc. have moved from a TOU rate design based on peak and off peak to the three intervals per day (peak, partial peak and off peak) rate structure.
I haven’t spent much time to figure out how the big three (and CASIO) are allocating the costs associated with the new transmission infrastructure (to provide a conduit from the utility scale RE projects put, and being put, in place to the grid).
Over time the allocations on my true up bill from PG&E have changed to allocate more costs for my kWh usage to transmission. Which on the face of things seems reasonable, until one looks at our actual grid supplied usage which isn’t using grid powered RE resources or the infrastructure needed to get those resources to the grid. We are in for some interesting times in the coming years as we figure out how to optimize the rate designs.
On a separate subject: water and who pays how much for it- EID on a 3-2 vote approved keeping the small farm rate in place. The amount of new plantings in the rural part of the county are more than likely going to survive. It will be interesting to see if NASA will be able to detect the improved greenness of the area the next time they do an evaluation like the one noted below
..”The researchers found that the magnitude of changes in plant growth over the 29-year study period was different depending on the size of nearby population. Near areas defined as dense settlements – with about 500 people per square kilometer – the vegetation index increased by 4.3 percent. That’s less than near villages, where the vegetation index increased by almost 6 percent.”
The administrative efforts that the Ag department in our area are required to put in to ensure folks are following the rules don’t seem to painful. As the Ag department is going to have a lot of data on how many trees, vines, etc., are being planted one can envision the data leading to some carbon credits ending up going to someone in the future.
As EID’s water conveyance (or Georgetown’s, etc.) systems are the enabling technologies, and they are a public entity, I could envision the new greenness benefits rolling up to them and the Ag department. It’s not a lot of benefit individually, but if one did some carbon counting it would likely offset each of the small farms carbon footprint from their residential HVAC needs/useage and for many their transportation needs as well.