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Managing Loads: Supply- Or Demand-Side?

Fereidoon P. Sioshansi, Ph.D.'s picture
President, Menlo Energy Economics

Dr. Sioshansi is President of Menlo Energy Economics, a consulting firm based in San Francisco, California, advising clients on the rapid transformation of the electricity sector and emerging...

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  • Sep 1, 2020

The question of what is the best way to manage consumer load has occupied some of the best and brightest for many years. Supply-siders are convinced that the best approach is for retail customers, large and small, to contract with aggregators or intermediaries who can add up their demand flexibility, distributed generation and/or storage to be scaled and packaged into useful products or services which can be dispatched as a virtual power plant (VPP) by the grid operator such as the California Independent System Operator (CAISO). Some observers say California’s recent outages could have been avoided had CAISO had more demand response capabilities.

Demand-siders are not convinced, pointing that such approaches have not worked well to date and suspect that any top-down approach will ultimately run into limitations. They believe in a bottom-up approach, using time-of-use (TOU) retail tariffs which typically come in 2 or 3 different prices for blocks of time during the day to provide the necessary signals to millions of individual customers directly or their behind-the-meter smart devices, who can automatically respond. They say that delivering smart-prices-to-smart-devices will lead to smart outcomes – be it load, distributed generation or storage. It is a more elegant solution, leaving individual customers – or perhaps their designated intermediaries – to do the legwork based on price signals – which could conceivably be real-time or dynamic prices. During the recent power shortages in California, wholesale prices spiked to $1,500/MWh but the signals never reached individual customers or their devices.


Which approach works best and delivers better outcome in the real world with real customers is no longer an academic curiosity. The future of many an electrical networks with increasing renewable generation in the mix will depend on it.

California, among a number of states and countries, has an aggressive law, Senate Bill 100 or SB100, mandating that 100% renewable and zero-carbon energy resources supply all retail electricity sales by 2045. Other laws including Senate Bill 350 require improvements in energy efficiency and the electrification of buildings and the transportation sector to reduce carbon emissions. The net result of these and a myriad of other regulation is an economy powered by variable renewable generation, primarily solar and wind complemented with decentralized generation – mostly rooftop solar PVs, and distributed storage including millions of EVs.

Presently, most customers in California and elsewhere, do not get useful price signals – even though most already have smart meters – and have no means to manage how much and when they should heat or cool their buildings, charge their EVs or storage battery if they have one, pump water, and use appliances when clean, renewable electricity is abundant and cheap, and use less when it is scarce, not renewable and expensive.

These issues were not front and center in the past. They are today and will become more pressing with the passage of time. Retail Automated Transactive Energy System (RATES), a study funded by the California Energy Commission (CEC), examined how an automated system providing dynamic prices to individual customers and/or their devices could help them self-manage their electricity consumption, generation, and storage. The key words in the RATES are the automated and transactive, the brainchild of Ed Cazalet, the project’s principal investigator.

Cazalet is convinced that customer self-management of electricity must be coordinated with other retail and wholesale generation in real-time throughout the day. He notes that such coordination with millions of customers is increasingly difficult as more distributed generation and storage are added to the network. In the case of California, there is also the additional complexity of dealing with community choice aggregators (CCAs) while many customers and communities are contemplating semi-independent microgrids given the increasing numbers of wild fires, which result in more frequent power outages.

According to Cazalet, a transactive energy guru, “The supply-side approach is complex and unable to completely capture the full customer use, distribution, retail energy, and wholesale transmission and energy benefits of distributed assets. And many customers may not want to turn over the control of their electrical devices to aggregators, or to the CAISO, thus limiting their participation.”

Moreover, the TOU tariff, even if widely implemented, cannot adequately capture the full range of prices experienced in the wholesale and retail markets, which range from negative to thousands of dollars per MWh (visual).

TOU rates, he says, “Would not provide a sufficiently granular variable and locational price signal for distributed storage, electric vehicle charging, and heating, ventilation, and air conditioning (HVAC) to adequately respond.”

In markets with or without an explicit capacity mechanism, measuring the contribution of renewable generation, batteries or flexible demand, for example, is difficult because the definition of capacity – resource adequacy in California – is typically fixed over time. Moreover, highly dynamic prices could lead to market and grid stability concerns, including potential over-reaction to sudden price spikes or dips, as well as customer bill and utility revenue volatility.

Finally, Cazalet notes that “The operation of devices to shift and shape usage to increase the use of midday solar generation and reduce evening fossil generation requires real-time hourly and sub-hourly prices, and hourly prices for at least the next 24 hours, with prices often changing during the day as weather and supply and demand change.”

Making matters worse for California, the progress toward retail real-time pricing (RTP) has stalled for decades. Cazalet is convinced that recent advances in information & communication technology (ICT), Internet of Things (IoT), and low-cost off-the-shelf smart devices currently used by customers for convenience, entertainment, and security can now be leveraged for automated and optimized management of electricity use in response to dynamic retail electricity prices

The pilot project with customers of Southern California Edison Co (SCE), employed a subscription transactive tariff that combined a subscribed stream of hourly kWhs shaped to the customer's typical or forecasted hourly usage over a year or more at a fixed monthly cost. Using the secret sauce – transactive energy – day-head hourly and real-time sub-hourly buy and sell prices were transmitted to automated devices in customers’ premises enabling them to optimally operate and adjust the load, distributed generation, storage, EVs – if available – in each metering interval. The committed and actual net load and bills for each premise were continuously reported to the utility, SCE.

The scheme was similar to the proven “block and index” contracts used for large customers by some power marketers and utilities, except that the subscription transactive tariff implementation was tailored to support automation by all and not just the large customers – who typically have dedicated energy managers.

Both the subscription transactive tariff and the block and index contract combine bill stability with actionable, dynamic real-time pricing. The real-time price provides operational efficiency in managing the operation of devices without the complexity of supply-side demand response (DR) programs and counterfactual baselines to measure the DR response.

Cazalet points out that the ‘’fixed bill” tariff – covered in the August issue of the newsletter (see Readers Write below) – is only fixed for perhaps a year. Based on the actual bill for a year, the bill for the next year may be increased or decreased – only delaying but not eliminating the variability of the fixed bill.  The described “fixed bill+” tariff requires customers to participate in DR programs to reduce peak loads but there are no actionable dynamic prices for optimized device operation. For example, in systems with high penetration of renewables it may make sense to increase load by charging EVs or storage when the price is very low and the opposite when the price is high.  It is not clear how the fixed bill+ with DR programs can do this simply and efficiently.

Cazalet notes that no single vendor, utility, or agency has been able to implement a practical solution that can be scaled either on the supply or demand-side to date. He believes that larger deployments are needed, and no private entity has the scope or funds to support such an endeavor. It sounds like he is seeking industry partners and funding to expand his prior pilot project. The recent close call experienced by CAISO should give his idea a boost.


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Fereidoon P. Sioshansi, Ph.D.'s picture
Thank Fereidoon P. for the Post!
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