A Cost-Allocation Win in New York for Distributed Energy Resources

Posted by Danny Waggoner on Apr 28, 2022 9:30:00 AM

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On March 16, the New York Public Service Commission quietly adopted a significant advancement in rate design. It did so as a result of a long proceeding on standby and buyback rates, in which AEE argued that owners of distributed generation not eligible for net metering (such as standalone storage facilities and institutions with combined-heat-and-power systems) were being overcharged for the customer-specific components of those rates. While the PSC action seemingly addressed a technical matter, the impact is a big win for advanced energy in New York, as it will lead to new rates much more favorable for a range of distributed energy resources (DERs).

At issue in the PSC proceeding (part of a broader docket on Value of Distributed Energy Resources) was a methodology for determining what usage-related distribution costs are associated with serving the needs of a specific customer versus infrastructure that serves multiple customers. Cost allocation is an essential element of rate design, but often gets less attention than how costs are charged, such as by fixed, volumetric, or demand charges. Getting cost allocation right (i.e., how big will those fixed, volumetric, and demand charges be) is just as important to achieving fair rates as the makeup of the charges themselves.

A clear example of this is New York’s standby and buyback rates, which, theoretically, were designed to closely align with cost-causation, but because of problems with cost allocation, failed to do so.

The rates, established by the PSC in 2002, were intended to recover the costs associated with commercial customers that partially rely on distributed generation or storage for their power needs but need their distribution utility for backup. Charging these customers based on normal demand rates for distribution costs would likely recover too much or too little from these customers. For example, a customer with large demand but reliable DER that falls back on utility service only once a year would pay distribution rates for only one month of the year. On the other hand, a customer with DER that undergoes maintenance overnight once a month might have distribution charges that look similar to a customer that relies on a utility 24/7, since the charges would be based on the monthly maximum demand peaking during the maintenance periods.

Trying to create a rate that more closely resembles the costs to serve these partial requirements customers, the PSC split the demand charge into two portions (the rate also has a customer charge, which is fairly typical). The first demand component, a contract demand charge, is meant to recover the costs associated with serving a specific customer (or as the PSC calls them, “local costs”). This charge is based on a customer’s historical peak demand, and once that peak demand is set, it is very difficult for a customer to ever lower the charge. This is intended to recover the “sunk” costs associated with connecting a customer to the grid and installing fixed equipment designed to meet the maximum capacity needs of the particular customer, regardless of their usage in any given month. These costs are also caused by bidirectional power flows, since a connection to the grid needs to be able to handle the charge flowing over it, regardless of direction.

The other portion of the demand rate is a daily “as-used demand charge,” which is a tiered, time-of-day charge that is only assessed on days that a customer uses the utility system. This charge is meant to recover the shared costs of the system, such as distribution facilities that serve the demand of multiple customers and are unlikely to go unused if a customer stops using them. (As-used demand charges are only for consumption-related demand, as a power injection offsets the demand of other customers and reduces the load distribution systems need to carry.)

When put together, the contract demand charge was supposed to limit the cost of serving a customer with infrequent usage from being shifted to other customers (the customer pays for their customer-specific costs regardless of month-to-month usage), while the daily as-used demand charge would prevent occasional-use customers from being hit with a full distribution rate.

Because of its precision, this approach held a lot of promise for improving the economics of DERs – storage, EV charging, and other beneficial electrification uses. In reality, however, the standby and buyback rates based on this method have had the opposite effect. That’s because the cost allocations for customer-specific and shared costs were developed by negotiation between stakeholders and utilities rather than based on any sort of rigorous methodology.

Many costs that should have been classified as “shared” instead got classified as customer-specific and recovered in the nearly immovable contract demand charges. For a reduction in demand at peak, the impact on a shared distribution facility should be to lower the need for future shared capacity and therefore avoid or reduce the need for future shared costs. However, the value of that shared cost reduction is not reflected because it is recovered in a static contract demand charge rather than an as-used demand charge. For an injection of power, the result could be an increase in contract demand charges even though the injected power helps serve the load of other customers and offset the need for more upstream infrastructure (such as transmission and substations). In essence, the misallocation of costs causes some power exporters to pay more for shared costs (since they are included in contract demand charges) even though power injections reduce the costs for those shared facilities. As a result, in New York City, it could cost a customer with storage roughly $90,000 to $120,000 per year in contract demand charges (depending on service characteristics) to inject 1 MW of power into the grid, even during peak hours when it is vitally needed.

After the PSC recognized that negotiations were not sufficient for defining customer-specific and shared costs, the Commission ordered the utilities to conduct a study to determine what costs were local and what costs were shared. But after the studies yielded lackluster results, staff developed a decision tree for utilities that, in short, looks at the impact of an individual customer’s demand and how it might affect a specific category of distribution costs under different scenarios. (For detailed discussion of the decision tree, see AEE’s initial and reply comments and in our response to an alternative utility proposal). In the end, the PSC adopted the staff proposal along with recommendations from AEE and others, such as storage organization NY BEST, citing AEE’s comments over 140 times in the order.

While utilities still need to develop new rates based on the cost allocations that result from the decision tree, we expect a significant improvement in the economics of standalone storage and combined heat and power (both of which are required to use standby and buyback rates). We also expect the new standby rates to be a good option for electric vehicle charging. The daily as-used demand charges do not apply at night, so there are no additional distribution charges (beyond the base contract demand charges) for charging vehicles overnight. The daily nature of the demand charges may also be attractive to HVDC chargers in low-use areas.

What started as a troublesome rate that held back the growth of DERs is likely now to become an opportunity for all customers in New York seeking to make the most of DERs and demand management options. While initially developed for larger commercial and institutional entities, standby and buyback rates are also offered on an optional basis to all customers, including residential customers, and DER providers may be able to develop new offerings that take advantage of the newly developed rates for a broader set of applications.

Application of this new methodology for cost allocation may also have implications beyond the state’s borders, as it provides some clarity around a contentious issue of rate design: what costs are avoidable (or sensitive to changes in behavior) and what are not. Many utilities, and not just those in New York, argue that their distribution costs are fixed and therefore should be recovered predominantly in fixed charges. The results in New York are likely to provide ammunition against those assertions, as the body of costs that are considered fixed is likely to shrink substantially. That evidence could shake up rate structures elsewhere, to the benefit of advanced energy technologies and those who would like to choose them.

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Topics: State Policy, PUCs, Utility, Regulatory, New York



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