Behind-the-Meter Incentives 101

BatteryBits
May 29 · 9 min read

This story is contributed by Rebecca Wolkoff, ChargeNet

  • Energy storage systems provide value by reducing the cost of electricity from the local utility, but the rules governing those utility bills are often complex.
  • Energy arbitrage is the process of buying energy at a low rate and selling at a high rate, and net metered energy sold back to the grid is valued at a lower rate.
  • Demand rates are based on the maximum power used during a set period of time, typically over a day or a month, and sometimes during specific hours of a day.
  • During demand response events, the utility or independent system operator sends a signal asking customers to curtail their energy usage and/or increase their energy generation for a set period of time, and the benefit is typically calculated against the customer’s baseline usage.

If you’re like most people, you get a bill from your local utility each month charging you for your electricity usage. You probably glance at it to make sure you’re being charged some amount similar to what you’ve seen before, pay it, and move on.

For companies selling and integrating behind-the-meter solar, energy storage with batteries, electric vehicle chargers, smart HVACs, and other controllable loads and devices, this electricity bill is the standard by which success is measured. Understanding this bill, along with other utility and government programs, is key to making your behind-the-meter business successful.

Every AI software on the market (Tesla’s Opticaster, Stem’s Athena, Enel X’s DER.OS, etc.) has been meticulously programmed with the rules dictating the charges that appear on that bill, and, if even one detail is not correct, that bill at the end of the month could be upsetting for the customer.

Unfortunately, the different tariffs, incentives, programs, and markets can be very complicated and may not be straightforward to access. Those same AI software providers often have a team in the company whose sole job it is to understand these rules, especially because they have been evolving quickly in recent years. Let’s break down some of the major types of tariffs, incentives, and programs available to your behind-the-meter device.

Energy Arbitrage

Energy rates appear on every utility bill. The line items that charge per kWh (kWh is a measure of energy) are your energy rates. Energy arbitrage is the process of buying energy at a low rate and selling it at a high rate. This is easily done with energy storage, but other controllable devices can take advantage of these rates as well. Consider an HVAC, for example — we can choose to turn it on when the price of energy is low instead of running it when the price of energy is high.

Southern California Edison’s 2021 energy rate schedule under tariff TOU-D-4–9PM [1].

While most energy rates are easy to understand, some change depending on the system or metering condition. With net metering energy rates, for example, energy sold back to the grid is valued at a much lower rate compared to using that energy to offset the customer’s electricity loads. Net metering energy tariffs typically incentivize exporting to the grid only when there are no other ways to take advantage of that excess electricity.

Demand Charge Management

Imagine you are filling several buckets with water from a hose. If the water in the buckets is analogous to energy use, then the speed at which you fill the buckets is power use. Energy rates charge you for how many buckets of water you fill, and demand rates charge you for how fast you fill them — or, in practice, the maximum speed at which you fill them.

Demand rates are common on both residential and commercial utility bills, although residential demand rates are typically so low that most customers do not pay attention to them. Demand is the measure of average power, and a demand rate is a charge per kW (unit of power). A demand charge line item on a customer’s bill is typically determined by the maximum average power used during a set period of time. There are many varieties of demand rates, so let’s review some of the most common types.

There are ‘daily’ demand rates, ‘monthly’ demand rates, and sometimes demand rates that apply for even longer periods of time. With a daily demand rate, the customer will be charged for the peak usage during specific hours in a day. A new peak (or multiple peaks if there are multiple applicable rates) is established for each day. SC-9 from Con Edison in New York is an example of a rate with daily demand charges [2].

A monthly demand rate indicates that for specific hours of a month, the customer will be charged for the peak usage during that time window. Typically customers are charged for their peak usage per billing cycle. E-19 from PG&E in California is an example of a rate with monthly demand charges.

Daily peaks vs. monthly peaks. On a daily rate, supposing the rate is active at every moment, the customer would be charged for the highest demand (average power) each day. On a monthly rate, again assuming a 24x7 rate, the customer would be charged for the highest demand over the course of the billing period (often a month in length).

Some demand rates can apply for longer periods of time, even years. ‘Contract demand’ from Con Edison, a demand rate that applies annually, is one such example. In some cases a peak power value can be chosen by the customer and in some cases it is based on historical usage.

In addition to how often utilities record peaks, demand rates fall under two different categories: ‘stacked’ or ‘independent.’ Stacked demand rates can be overlapping in time. For example, Con Edison’s SC-9’s summer tariff has one daily demand rate from 8:00 am to 6:00 pm, and another demand rate from 8:00 am to 10:00 pm. Both of these rates are active from 8:00 am to 6:00 pm. Independent rates have no time periods with overlapping demand rates. PG&E’s E-19 is an example of a tariff with independent demand rates.

Stacked rates vs. independent rates. The line represents the customer’s load profile, while the blocks represent when different demand rates are active and the value of those rates. The graph on the left is an illustration of Con Edison’s 2021 SC-9’s summer tariff, an example of stacked rates. In this example, the customer is charged: 100 kW x $1.092 + 100 kW x $0.056 because the peaks of both demand windows happen to be 100 kW at noon. The graph on the right is a fabricated example of what a rate similar to SC-9 might look like if it was independent, for the purposes of comparison. This rate has two separate, non-overlapping demand periods, and therefore the peaks for each period cannot occur at the same time. The customer in this example is charged: 62 kW x $1.092 + 100 kW x $0.056. The peak of the Summer High Peak rate period still occurs around noon, but the peak of the Summer Mid Peak rate period occurs around 6 p.m. in the independent rate example.

Other demand rate complexities can also make a big difference in the bill. Some demand rates, like the summer partial peak in E-19, have two periods of time where the rate is applicable. This means that if a peak in demand occurs in either of these time periods, the customer is charged the partial peak rate. Another complexity is the amount of time over which a utility is measuring demand. Most utilities, California utilities included, measure demand over a fifteen-minute window (average power is calculated by taking the total energy the customer consumes in fifteen minutes and dividing it by those fifteen minutes of time). However, other utilities might use demand averaged over five or thirty minute time windows.

Example difference between 15 minute and 30 minute demand measurements. The intervals represent average power over five minutes.

Demand can additionally be measured in blocks or on a rolling average basis, and the difference between these is depicted below.

Example showing the difference between 15 minute block demands vs. rolling demands. In this case, the rolling average occurs every 5 minutes, meaning that a new average is taken every 5 minutes over the previous 15 minute interval.

Demand Response

Demand response programs are those in which a utility or an independent system operator sends a signal to request that customers curtail their energy usage and/or increase their energy generation, typically for a set period of time. Returning to our water bucket analogy, the utility is requesting customers to turn off the hose or slow it down to a trickle for a certain period of time.

There are many flavors of demand response programs, but most of them involve comparing the customer’s average electricity load (average power) during a demand response event to a ‘baseline.’ Each program has its own rules for establishing how the baseline is calculated, but a typical baseline calculation involves averaging recent historical electricity loads during the same hours on similar days.

Coincident Peak Pricing

Some operators and utilities have programs that incentivize customers to curtail their energy usage and/or increase their energy generation during the highest utility demand peaks. These programs differ from Demand Response in that the utility will often not give a signal to customers as to when a peak is occurring; instead, customers need to forecast when the utility peaks will occur. Note that unlike Demand Charge Management rates, the customer must dispatch during the utility’s demand peak, rather than the customer’s peak load. Coincident peak programs try to address the ‘peaking’ issue that many utilities experience — that the top utility demand peaks are typically the most expensive (due to lack of generation available) and sometimes the dirtiest [3].

PJM has coincident peak pricing that can make up 20–30% of a customer’s bill. PJM will charge the customer based on the customer’s energy consumed in the top five highest peak hours over the summer. Ontario’s IESO has a similar charge, Global Adjustment, that can make up 70% of a customer’s bill. Coincident peak programs may differ in the number of peaks customers will be billed for, and whether these peaks are counted monthly, seasonally, or annually.

Tax Credits

Solar and solar-plus-storage projects often claim a solar investment tax credit, reducing the overall capital cost of building such projects. In the USA, there is a federal solar ITC (currently at 26% of the capital cost) [4]. This credit may be claimed on solar projects and storage paired with solar projects, where 75% or more of the energy used to charge the battery comes from solar. The higher the percentage of energy from solar feeding the battery, the higher the credit [5]. California also has a state solar ITC with similar rules.

Incentive Programs

There are other types of programs that allow for behind-the-meter devices to earn more value. One example is California’s Self-Generation Incentive Program (SGIP), which offers further incentives to storage projects already taking part in a solar ITC if the storage follows greenhouse gas pricing (discharges when the grid is dirtier and charges when the grid is cleaner) and cycles at least 104 times per year [6]. This incentive and other similar programs evolve frequently so it is useful to track rule-changes in green technology news.

Final Thoughts

I’ve only scraped the surface of tariffs and incentives available to renewables, storage, electric vehicles, and other behind-the-meter devices. I would love to see utilities make these tariffs and incentives more accessible and understandable to the public. I would also love to hear about other tariffs and incentives that encourage more alternative energy, storage, and smart technology to be deployed in the field. The more we share, the faster we can transition to a greener, more efficient future.

References

[1] https://www.sce.com/residential/rates/Time-Of-Use-Residential-Rate-Plans

[2] SC-9 in NYC. https://www.nyserda.ny.gov/-/media/Files/Programs/Energy-Storage/energy-storage-customer-electric-rates-reference-guide.pdf

[3]Peakers, https://www.cleanegroup.org/ceg-projects/phase-out-peakers/

[4] Solar ITC, https://www.energysage.com/solar/cost-benefit/solar-investment-tax-credit/

[5] Solar ITC, https://www.nrel.gov/docs/fy18osti/70384.pdf

[6] SGIP, https://www.selfgenca.com/documents/handbook/2021

Acknowledgements

Huge thanks to Tim Suen and Linda Jing for their excellent edits and suggestions!

Rebecca Wolkoff is the Chief Technology Officer at ChargeNet. ChargeNet is creating the charging stations of the future, powering DC-fast chargers with green technology at restaurant and retail locations. Rebecca leads the development of ChargeNet’s intelligent, user-friendly software to serve electric car owners and restaurant managers. She loves to learn and is currently interested in better understanding the nuances of the solar investment tax credit. In her spare time, she defends her beloved Cleveland sports and reads up on general relativity. Feel free to reach out to her on LinkedIn about any of these topics.

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