California is already breaking ground in attempting to properly value the distributed technologies hitting the grid. So far, that’s been done through large-scale capacity contracts, demand response auction mechanisms, and utility pilots. Now the state is opening another front in distributed energy integration: tariffs.
Over the next year or so, the state’s investor-owned utilities are under regulatory pressure to create specially designed, optional tariffs available to homeowners or businesses that want to invest in solar PV, batteries, EVs or on-site energy controls.
These rates would change from hour to hour, but with drastic price differentials between on-peak and off-peak times than the mass-market time-of-use (TOU) rates being rolled out across the state over the next four years. Such extreme price differentials could punish customers who can’t shift energy use.
But they could also provide the financial incentives to cover the costs of adding a battery to a new or existing solar PV installation, to charge up when prices are low and discharge when they’re high. And unlike mass-market TOU rates, they could include different measures of real-time value — price changes based on wholesale grid power costs, for example, or demand charges or distribution grid values aimed at getting customers to change energy-use patterns to mitigate local grid congestion needs.
All of these options are now on the table in the general rate cases being put forward by Pacific Gas & Electric, Southern California Edison and San Diego Gas & Electric. PG&E’s rate case is coming first — and we’ve already seen new tariff proposals come out from the utility and from the Solar Energy Industries Association (SEIA), two parties that have clashed before over solar-friendly rate design.
Two different approaches to solar-storage tariff design
This week, SEIA filed testimony (PDF) with the California Public Utilities Commission asking the regulator to reject PG&E’s proposed solar-storage rate schedules for residential and small commercial customers, and to go instead with an SEIA-designed set of rates. The solar group has also proposed a new “Option S” rate for large commercial and industrial customers to encourage solar-storage systems, something that PG&E hasn’t yet considered in its rate cases.
SEIA lays out two main reasons why it doesn’t like PG&E’s rate schedules for residential and small commercial customers, called E-DMD and A1-DMD, respectively, and why it wants to replace them with its own E-STORE and A1-STORE rates instead.
PG&E’s rates would include a “significant non-coincident demand charge based on the customer’s maximum 15-minute demand each month, whenever it occurs.” And as we’ve seen from debates around the country, while some utilities have supported adding demand charges to solar net metering customers, solar industry groups have universally opposed them.
“We’re categorically opposed to residential demand charges,” SEIA’s Brandon Smithwood said in a Wednesday interview, making PG&E’s idea of adding demand charges to its residential rate a non-starter.
And while SEIA isn’t opposed to demand charges for small commercial customers, it would like to implement them in a different way. Instead of basing them on any single 15-minute spike over the course of a month, it’s proposing “daily demand charges,” imposed on customers only during the day’s peak demand hours.
The difference, Smithwood explained, is that “with a monthly demand charge, it’s just that one 15-minute interval.” If a customer fails to prevent it, they’ve “blown [their] savings for the month.” With a daily demand charge, by contrast, “We could shape that demand charge so that it really sends a better price signal. We would be moving demand charges toward something that actually works better for customers, and makes more sense for a public policy standpoint.”
California hasn’t used daily demand charges before, making SEIA’s proposal a novelty in the state’s utility policy. Here’s how it describes the concept in its testimony: “The daily demand charge of $0.6390 per kW/day applies each and every day to the highest 60-minute demand during the 3 p.m. to 8 p.m. peak period. This rate element provides the storage user with a strong incentive to use storage both to reduce and to flatten their delivered load from the utility during the peak period, and to discharge storage when the stored power provides the greatest system benefits.”
The second big problem SEIA has with PG&E’s proposal is that it doesn’t believe the differences between on-peak and off-peak prices are significant enough. “It just won’t pencil out,” he said. “Even if you could manage your non-coincident residential demand charges, there’s not enough differential there.”
SEIA’s rate differentials, by contrast, are quite high — as much as 40 cents between the 52 cents per kilowatt-hour on-peak price and the 12 cents per kilowatt-hour off-peak price for residential customers under its E-STORE rate.
But this is the kind of “spicy” differential needed to cover the extra costs of adding batteries to solar, which SEIA has estimated at 33 cents per kilowatt-hour. “You need the big — ‘spicy’ is the word commission staff like to use — more ambitious, more technology-focused, time-of-use rates, with that big differential between on-peak and off-peak,” Smithwood said.
SEIA’s testimony backs this up with its own analysis of how a 10-kilowatt-hour battery, cycling daily between the off-peak and peak periods, would fare over a year’s time under both proposed rates. Under the E-STORE rate, that system would realize $1,062 per year in benefits — “economic if such storage units have reliable lives of 10 years and costs below $10,000. Such units appear to be commercially available soon, for example, the Tesla Powerwall 2.”
In contrast, “We estimate that [PG&E’s] E-DMD rate will provide annual benefits of just $509, assuming optimistically that the storage can reduce the customer’s non-coincident demand charge by 50 percent of the unit’s output capacity.”
At present, PG&E hasn’t provided an alternative analysis of its own rates. The utility recently testified to the CPUC that it “did not perform any analysis to determine the point at which the solar plus on-site battery storage would become economic under the proposed E-DMD and A1-DMD residential and small commercial rates.”
The intricacies of creating, and comparing, never-before-seen DER tariffs
These are only two sets of multiple DER tariffs being proposed in California, and it can be hard to parse out the complex differences between all of them. At GTM’s California’s Distributed Energy Future 2017 conference held last week in San Francisco, we heard a debate between SEIA’s Sean Gallagher and Environmental Defense Fund senior economist James Fine over another proposal coming from SDG&E, specifically for EV charging.
EDF’s Fine pointed out that SDG&E’s experimental tariff for its Vehicle-to-Grid Integration pilot would be based on day-ahead forecasts of hour-by-hour prices the next day, with some adjustment for day-of changes. That will give EV drivers — or the EVs themselves — the data required to avoid high-price hours and take advantage of low-price hours.
EDF is also asking PG&E and Southern California Edison to consider what it calls a “smart home rate,” which would expand the scope of customers beyond single-technology categories like solar-storage or EVs, to include demand response via smart thermostats, grid-responsive loads and other behind-the-meter controls.
The basic concept includes some sort of monthly service fee (albeit one that’s as low as possible); a grid charge that allows customers to benefit by managing their load profile; and day-ahead hourly price signals that accurately reflect a broad range of costs and values.
Gallagher previewed SEIA’s E-STORE proposal in his CDEF talk, but also provided a critique of what SDG&E and EDF have proposed. In his view, hour-by-hour prices that change daily might push too much risk onto the customers and provide “too much certainty for the utility,” he said.
Fine agreed that “the concern is that this is maybe too risky for many customers.” On the other hand, he acknowledged that “there’s also an attractive, profitable opportunity for customers who want to take on that risk” — or perhaps are willing to hire a DER provider or aggregator to do it for them.
Given all the uncertainty over how these kinds of rates will work in the real world, both Gallagher and Fine agreed that it’s important to have a number of options available to customers.
Both also promoted tariffs that don’t just compel people to reduce energy at moments of high costs and high demand, but that also offer incentives to actually increase energy use during negative pricing events when demand is low and renewable energy supply is high — such as during the midday belly in California’s “duck curve.”
SEIA’s concept for this is called “discount days,” which would work along the lines of the critical peak pricing days widely used by California utilities (only in reverse), while EDF’s concept would embed these discounts in day-ahead pricing.
The debate over DER-based tariffs is just beginning, but this will be the year that helps set the terms for rollouts across the state. PG&E’s general rate case will likely take until the end of 2017 to complete, SDG&E’s is set to close it in the third quarter, and Southern California Edison’s will conclude in 2018.
This article was originally featured on greentechmedia.com.