State of Green Business
Fixed energy charges won’t fix grid integration
Fixed energy charges won’t fix grid integration
Solar power, battery storage and other distributed energy resources are becoming cheaper by the day.
However, solar-plus-battery economics are not just about what you pay for the system. They’re also about what you’d otherwise continue paying to your utility, as well as what you do and don’t pay for on your monthly bill.
That’s where pricing structures come into play, and they matter — not just for the timing of cost-effective solar-plus-battery economics, but also how investment in solar-plus-battery systems might evolve and what the future electricity grid could look like.
In our recently released report, The Economics of Load Defection, we modeled the dominant electricity rate structures for most customers in the U.S. — a volumetric rate for residential and a three-part rate that included a demand charge for commercial. In both cases we assumed no export compensation, although we considered net metering as a special case in the analysis.
The result suggested that solar and battery systems would be an economic supplement to grid-supplied electricity within the next decade for millions of customers, and ultimately would be economic as the primary source of electricity, with the grid as a backup resource.
Indeed, these economics might be realized even sooner than we forecast, given recent announcements of battery prices that are five years ahead of our projections. This has profound implications for customers, service providers, utilities and regulators.
Evolved electricity pricing needed
Among these implications is a clear need for electricity pricing structures to evolve. Today, for instance, residential customers typically pay for electricity on block-volumetric rates (by the kilowatt-hour), along with, historically and typically, a modest fixed charge of a few dollars a month.
The benefits of this structure are that it is simple to administer and understand, and it encourages customers to conserve energy. However, the rapidly improving economics of solar and battery storage substantially amplifies a customer’s ability to conserve (or, more accurately, to supply energy for themselves rather than buy it from the grid).
If the pay-by-the-kilowatt-hour model of today is projected into the future, our analysis shows that customers simply will buy very few kilowatt-hours from the grid — the customer won’t defect from the grid, but the load will (to solar-plus-battery systems); the resulting energy sales erosions could look to utilities like an extreme form of energy efficiency. Clearly, in order to maintain a reliable and healthy grid, utilities need to evolve to a new pricing model.
But what should the pricing model of the future look like, and how should we begin to implement it? Even with the advent of economic solar PV and battery storage, we expect the pricing model to consist primarily of a rate structure for electricity sales and purchases.
Contentious debates about the future of net metering, proposed and actual demand charges for utility customers with solar PV, and proposed increases to residential fixed charges make this an important conversation to be having now. That’s because we expect solar PV and batteries will play a central role in the electricity system of the future, but how such technologies are or aren’t integrated into the grid could vary tremendously.
Why fixed charges aren’t the answer
One strategy many U.S. utilities have been pursuing is to substantially increase the fixed charges that customers pay.
For instance, Wisconsin Public Service proposed a 140-percent increase in the fixed charge for all customers (from $10.40 per month to $25, with an eventual outcome being a charge of $19). On the surface it’s an understandable move from utilities.
If you don’t want to lose revenue, take away some customer control over that revenue. Have customers “just pay up.”
No matter how much you do or don’t use the grid, everyone kicks in some money and shares in the cost — like the ante in a round of poker. Except that utilities are taking a big gamble: by attempting to create revenue stability, they lose the bigger opportunity to control costs through smart use of distributed resources.
Our analysis does show that these fixed charges can create delays in the parity dates for solar-plus-storage: even a small fixed charge can delay the economics by several years. But this delay comes at a cost, both of customer good will and the opportunity to align the interests of solar and storage owners with those of the grid at large.
And although higher fixed charges have become one of the more commonly pursued ways for utilities to move away from reliance on the pay-by-the-kilowatt hour model of today, they are not the only way. We see at least three important reasons why fixed charges aren’t the way to go:
1. Customers lose incentive to conserve energy
Shifting revenue collection away from volumetric charges to fixed charges diminishes the widely valued and longstanding electricity ratemaking principal of encouraging customers to conserve energy when and where they can.
Under scenarios with higher fixed charges, customers likely will consume more energy and have significantly reduced incentive to adopt innovative DERs such as solar or battery storage.
2. The grid defection whiplash effect
Perhaps more important is the eventual whiplash we believe could occur.
Eventually, if fixed charges become substantial enough, and the economics of solar and battery storage follow the trajectories we believe they will, it is plausible that it will become attractive enough for customers to entirely defect from the grid: to altogether drop the traditional power company just as millions of Americans have altogether dropped the traditional phone company.
3. A giant missed opportunity
Perhaps most important of all, it represents a giant missed opportunity.
DERs can contribute to significantly decreased costs for the grid: they can reduce peak demand, contribute to increased reliability and resilience, defer new infrastructure upgrades, compete in ancillary services markets and provide local balancing of electricity consumption.
But in order to capture these benefits, pricing structures need to evolve towards compensating DERs for these services: it’s an alternative way of thinking about the old saying “you get what you pay for” — or don’t pay for.
Pricing for integration
In August, RMI and collaborators from the Electricity Innovation Lab (eLab) released Rate Design for the Distribution Edge, which offers insights on how pricing structures should evolve in light of the growth in adoption and capabilities of DERs.
We made the case that rates need to evolve along three spectrums: temporal, attribute and locational. That call for evolving rate structures along those lines — rather than simply increasing fixed charges — is more important now than ever in a here and/or coming-soon era of cost-effective solar-plus-battery systems.
Here are three ways to evolve rate structures to better price electric service to encourage more optimal DER investment and grid integration:
1. Account for time
For instance, rather than establishing a higher fixed charge, utilities could expand offering customers time-varying rates, such as time-of-use (TOU) or hourly pricing structures.
Because they reflect the fact that the cost to produce and deliver electricity is much higher during peak hours than off-peak hours, this represents a powerful incentive for customers and DERs to reduce peak loads — thereby capturing savings not only for themselves, but also delivering value to the utility and the entire customer base.
In the case of solar and battery systems, time-varying rates further can encourage adopters to configure their systems to deliver maximum benefit to the grid during peak hours, including different orientation of solar panels and battery systems that can either export or soak up generation at the appropriate times.
By way of comparison, under block volumetric rates, solar and battery systems can lower overall demand and sometimes system peak, but customers aren’t incented to optimize their systems to do so.
2. Break apart some attributes of electric service
Another option is for utilities to move towards rate structures that price services separately, such as including demand charges.
Whereas time-varying rates motivate customers to help a utility reduce costs that are driven by system peak loads, demand charges motivate customers to smooth their own usage and reduce costs associated with individual peak loads, because a very erratic or “spikey” individual load profile is more challenging to serve. Solar PV, battery systems and a host of other DERs can be useful to help customers mitigate demand charges, which in turn provide significant cost reductions to utilities and, by extension, all customers.
This technique unleashes, rather than mutes, deployment of innovative DERs. And unlike a fixed charge, the customer still can manage a demand charge by taking actions or making investments that alter their load. Similarly, utilities could provide a price signal for frequency regulation services. This exists in various forms in wholesale markets, such as PJM. Many battery technologies are taking advantage of this price signal.
3. Account for location
The cost to provide reliable grid service varies from place to place on the grid. Some locations may be costly to serve due to grid congestion, for instance.
In these cases, utilities and regulators should consider how packages of DERs could provide congestion relief, or defer or mitigate the need for investments in traditional grid infrastructure at a much lower cost.
The Brooklyn-Queens Demand Management program by New York utility ConEd is a great example of this model being put into practice. Importantly, this model is based on incentives for DERs that pay for themselves, as opposed to charges that more accurately reflect grid costs.
Technologies such as solar PV and battery storage are becoming more economical every day, and customers are eager to embrace them. Utilities and regulators can embrace them, too, by instituting pricing structures that motivate their deployment and fully leverage their capabilities, rather than raising fixed charges that remove some measure of customer bill control in an era of increasing customer choice.
This article originally appeared at the Rocky Mountain Institute's RMI Outlet.