Rate designs for distributed energy resources (DERs) remains a hot topic. States are taking different approaches, but some are better than others. Some states are making adjustments (typically reductions) to flat kilowatt-hour rates, such as net metering and buy-back rates, or adding/raising fixed charges that often focus exclusively on utility revenue without looking at DER from a total value perspective. DER can impose costs on the system, but it can also provide value, both to the utility and more broadly to the public, and rates and compensation should take both into account. In its continuing effort to comprehensively assess the value of DER and design rates accordingly, New York recently made some landmark adjustments that should provide fairer treatment for customers that have significant distributed generation facilities, such as combined heat and power (CHP) systems. The improved rate is also available as an option for all customers, including residential customers without DG, and is likely to be a good choice for customers with electric vehicles and certain types of DER.

AEE has long advocated for thoughtful consideration of rate design changes that support evolving DER markets and technologies and that can be applied to a broad range of technologies and applications. In order to value DER appropriately and encourage competition, we should use the same measuring stick to value all DER. That means providing compensation for wholesale energy and capacity, any relief the DER provides to the transmission and distribution systems, reductions in system losses, and avoided emissions. DERs that are able to perform on those measures ultimately reduce the cost of serving a particular customer and can also reduce the costs of serving other customers.

Net energy metering (NEM) is a simple rate design that has been critical to the development of distributed generation (DG), mainly solar. Its success is due to its simplicity—it is easy for customers to understand—and it works with the limited metering technology that was available prior to smart meters, which are now in use in many states. However, NEM doesn’t work for all technologies, particularly technologies like storage that can vary its output in conjunction with periods of system need and should be paid for the flexibility that it provides. NEM is also not suitable for DERs that just manage load and do not export power to the grid. While NEM continues to be a good method of encouraging the deployment of solar, small-scale wind power, and some other DG options, it may over- or under-compensate DG for the value it provides. 

When a state is trying to get its DG market off the ground, some of the limitations of NEM can be overlooked since it is a proven, effective method of supporting the development of a DG market. At some point, though, all DERs should be compensated on a level playing field based on the system value they provide, which requires rate design options beyond net energy metering.

New York has been at the forefront of this issue since it opened its Value of DER proceeding in 2015. While the VDER proceeding still a work in progress, the New York Public Service Commission is utilizing a deliberative, collaborative approach to exploring successor tariffs to NEM as well as other rate design changes. At the same time, the state updated its standard interconnection requirements to include energy storage, either as a stand-alone system or coupled with distributed generation. 

While much of the effort to date has been related to community solar, a recent order begins to fulfill the broader objectives of the VDER proceeding by making improvements to rates – mandatory for large C&I customers with DG but now optional for all other customers – that are likely to benefit utility systems and  a wider range of DER technologies and customers. Importantly, the order will improve the alignment between system costs and how DER customers make use of the grid, which we think will ultimately improve the prospects for DER deployment.

Under the order, the Commission directed utilities to make changes to rates used by commercial & industrial (C&I) customers that have DG systems but are not eligible for NEM, such as customers with combined heat and power (CHP). These customers are charged standby rates, which compensate the utility for the obligation to meet the customer’s demand in the event that its DG is not working, and instead of being compensated for exports via NEM or the newer VDER tariff, they are paid for exports at so-called buyback rates, which differ from full retail by a range of costs attributed to the DG customer. The changes ordered by the Commission will improve the way customer-specific and shared system costs are allocated in these rates. 

In comments, AEE Institute argued that customers are being overcharged for the customer-specific components of the rates, which are assessed as a monthly fixed charge based on a customer’s historical non-coincident peak demand – the greatest amount of electricity consumed from (or exported to) the grid, whether or not that peak coincides with peak demand on the overall system. This acts as a disincentive to the adoption of  distributed energy resources subject to these charges. 

The current allocation of costs, which was put in place back in 2003, reflects not a detailed cost-of-service study, but values reached during settlement discussions. Proper allocation of costs between customer-specific and shared system costs should produce fairer rates for these customers, and also allow them to make use of their DER in a way that benefits themselves and the power system overall. Shared system costs assessed through coincident-peak demand charges – based on the level of customer demand at the time of system peak demand – should provide customers with more opportunity to avoid consumption or increase their exports of power at peak times and lower their bills. 

The order is also significant because the Commission decided that similar rates should be made available to residential and small commercial customers on an opt-in basis. This will give these customers additional options for managing their energy use and costs. For example, if a customer purchases an electric vehicle, these rates may help reduce costs for EV charging. 

While we continue to argue against mandatory demand charges for mass-market customers (especially non-coincident peak demand charges), making such rates available on an opt-in basis provides one more option for these customers to deploy DER technologies and use demand management strategies to manage their costs. This should also result in behavior that benefits all customers, such as a reduction of demand during system-wide peak periods when energy prices are high and the system is most stressed. To the extent these rates become more granular over time, they could also help defer or avoid upgrades on parts of the network that are nearing capacity.

There is still much work to be done on rate design for DER. As DERs continue to improve in cost and performance, and the grid becomes more intelligent and flexible, this will afford greater opportunities to use DERs for system benefit. It will also facilitate higher levels of DER penetration that are essential to achieving the increasingly ambitious advanced energy policies of states like New York. New York continues to show leadership on the critical issue of rate design.

AEE’s issue brief, Rate Design for a DER Future: Designing rates to better integrate and value distributed energy resources, as well as five other regulatory issue briefs, is available for download.