On July 23, the National Association of Regulatory Utility Commissioners (NARUC) – a non-profit organization focused on issues of importance to state public utility commission that regulate gas, electric, telecommunications, water, and other public services – hosted a town hall discussion of its draft Manual on Distributed Energy Resources Compensation (Manual).
NARUC’s Staff Subcommittee on Rate Design was created in November 2015 in response to electricity sector evolution – for example, as the grid transitions from a system built to deliver power from large, central station power plants, to a system that incorporates smaller, distributed supply and demand side resources – and the proliferation of rate design proposals intended to respond to these changes.
The Manual is intended to assist public utility regulators in identifying distributed energy resource (DER) related issues in their jurisdictions, raises key questions related to these issues, and describes compensation methodology options for DERs.
Defining DERs – The Manual notes there is no universal definition of DERs, though definitions typically include: distribution-level (not transmission-level) grid connection, relatively small size resources (under 10 MW) that are generally not individually dispatched by regional transmission organizations (RTO) or independent system operators (ISO). Regulators will need to identify what resources can qualify as DERs, for example, supply resources (e.g. solar, storage), demand side resources (e.g. demand response, efficiency), other services (e.g. microgrids, Volt/VAR, and locational ramping). Lastly, environmental attributes such as renewable or low-carbon resources may be considered as a qualifying characteristic for DERs.
DER Impact on Utility Costs – An overview of the various potential costs imposed on a utility from DERs are presented, including how supply and demand side DERs can erode revenues (i.e. sales) to the utility, reducing the ability for the company to cover its costs and remain profitable. DERs can also result in cost shifting between and/or within customer rate classes. This happens as reductions in payments from DER customers are eventually shifted to non-DER customers in the form of higher costs, in order to cover utility outlays. The physical and technical impacts of DERs – for example, intermittent generation quickly coming on and off of the grid – can negatively impact reliability and may require new utility investments.
DER Benefits – The Manual maintains DERs can also result in benefits or avoided costs to the utility system and states that a study of these values is likely to be necessary. These benefits and avoided costs – for example, avoided distribution, transmission, line losses, and energy or fuel costs – can be difficult to quantify, especially because these values may differ based on location, resource type, and time of day.
Ownership and Control –DER’s are often promoted by third party developers based primarily on energy price signals and not grid benefits. As a result, utilities often don’t know where DERs are located and when they are dispatching, potentially exacerbating technical and physical grid problems or failing to maximize grid benefits. Issues have also been raised about third party predatory lending, the need for consumer protection regulations, and ensuring that DERs can be available to low-income communities.
Key Rate Questions
What are the Goals of Rates? The Manual advises that regulators consider whether rates can be incrementally changed to achieve goals (e.g. through imposition of a new rate class, or fee on DERs) or if the entire rate structure needs to be revised. Regulators also need to consider if the rate structure provides appropriate price signals to incent economically efficient consumption.
How are Different Customers Impacted? DERs have the potential to reduce or avoid utility costs, or increase costs. The way (e.g. generation or distribution side) in which costs increase or decrease and the timeframe (i.e. long or short term) over which these costs or savings are experienced will impact rates and rate design. The cost and equity impacts of cost shifting, intra-class cost allocation, peak grid dependency (i.e. when the customer only relies on the grid at times of peak costs) and grid defection (i.e. when a customer self-supplies and exits the grid completely) also need to be factored into rate design. Regulators need to be aware that the lifespan of DERs is typically shorter than utility distribution and transmission investments, creating complications for system and reliability planning.
Impacts on Utilities? DERs have the potential to complicate utility planning and reduce investment opportunities on which utilities earn a rate of return. Utilities recently are focusing on how DERs impact non-DER consumers and are advocating for increases to fixed charges. However, the Manual notes utilities have been trying to increase fixed charges for a century and any increase in fixed charges in response to DERs should be accompanied by an evaluation of authorized rate of return.
The Manual maintains that net energy metering (NEM) was appropriate when analogue meters and high-cost solar prevailed. As solar costs have dropped and deployment of advanced meters increases, Value of Resource (VoR) in limited DER penetration areas, and Value of Service (VoS) in high DER penetration areas, methods may be more appropriate.
The VoR method separates out the cost of utility service and DER project benefits – for example, avoided energy or fuel costs, line losses, utility administration costs, avoided emissions – and assigns positive and negative values to each. Since these costs and benefits change over time (e.g. due to local DER penetration, price of natural gas, price of renewables), regulators using this method should set up a process that periodically adjusts values. Regulators can develop VoR tariffs for different DER resources and pair them with an appropriate rate (e.g. real time, time of use). The downsides with VoR include the subjective and contentious nature of quantifying values, avoiding double counting (e.g. excluding renewable energy credits that are separately traded), the need to regularly re-evaluate values, and other factors related to measurement and tracking.
The VoS method treats the distribution grid as a network, with each DER project potentially offering a service to the utility. Regulators would be required to unbundle distribution rates to make this method viable. The utility would then identify value added and needed services that DERs could provide, and procure these services from DER providers. This system would allow DER’s to be developed in a manner that maximized distribution grid value and visibility, and could increase value streams to DER projects beyond just avoided generation or demand. The downsides to VoS include some areas of the grid being less attractive than others for DER investments, increased technological investments are required by utilities, and adjusting the utility’s cost recovery model.
Transactive Energy is a less developed methodology that relies heavily on technology and communications equipment to enable customer-sited DERs to interact and provide value to the distribution grid. On the other side of the spectrum, use of traditional Demand Charges for residential DERs could also be used to incent DER owners to shift demand to less costly periods, benefitting customers and the grid. However, the Manual goes into great detail discussing demand charge considerations. The Manual also discusses the role of other traditional rate methods including fixed charges, minimum bills, standby and backup charges, and interconnection and metering fees.
Regulators will need to constantly monitor distribution technology advancements and costs – for example, advanced metering infrastructure, advanced distribution management systems, feeder hosting capacity analysis – to inform rate design choices.
Finally, the Manual’s maintains determination of policy reforms needed to respond to DERs, if any, should be driven by the level and pace of DER penetration as guided by data, analysis, and service area-specific study.
Feedback on the draft Manual is due by September 2.