What is the value of DER relative to the grid?

May 15, 2015
How can we build an economic framework to support sustainable integration of these new technologies?

Rapid change is occurring in the electricity industry, due in part to robustly expanding distributed PV (DPV), emerging grid parity, and surging maturation of many other distributed energy resources (DER) technologies, especially automated, aggregated load control (automated demand response or ADR) and behind-the-meter storage. DPV and DER have started a wave of regulatory conversation and debate around the country, evidenced by the dozens of states with ongoing or impending reviews of net energy metering (NEM) policies, DER integration, and related rate design topics. The conversation is centered on the core questions: what is the value of DER relative to the grid, and how can we build an economic framework to support sustainable integration of these new technologies? Fundamentally, much of the value of DER comes from its potential to defer distribution investments, which means the value of a unit of DER is necessarily tied to the unique characteristics of the local distribution area in which it is deployed and to the unique characteristics of the DER which influence its ability to meet that need.

Many states have undertaken to identify the value of DER specifically for DPV—the “Value of Solar”—producing a plethora of studies estimating average values for a list of benefits in a certain geographic area (usually a state). This is commonly driven by the evaluation of NEM policies. In New York and California, however, regulators are taking a broader view, albeit through somewhat different avenues. In California, there are over a half dozen open proceedings which together are focusing on NEM, residential TOU rates, DER integration, battery storage, electric vehicles, etc. In New York, the REV proceeding is seeking to transition the role of the utility into a Distribution System Platform Provider (DSPP) responsible for managing the distribution grid by integrating DER, potentially by setting up transparent markets which enable the efficient integration of DER.

There is an important common thread between these approaches on either side of the country. Both take a more holistic approach to understanding the value of a variety of DER and how they can work together to supplement the grid in tangible ways. As a first step in New York, for example, regulators have asked utilities to use an RFP process to identify suites of DER that can work together to defer substation build outs (like in the case of the ConEd BQDM). They are selecting DER portfolios that combine DPV, storage, ADR, EE, etc. to effectively reduce the peaking needs that strain the distribution system (and ultimately trigger the need for upgrades). In practice this means sculpting peak loads so they flatten out (or, in the case of DPV, so loads align better with daytime solar production), accomplished most effectively when a DER matches that peaking load.

The implication is that the value of DER as an alternative to building out distribution infrastructure will only be realized to the extent the DER is available to resolve peaking or ramping problems WHEN (time of day, day of week, season) and WHERE (substation, feeder) the need occurs. DER will only be developed in that fashion under a framework of economic incentives that properly reflect temporal and locational value. This is what the New York and California Commissions ultimately intend to foster.

The details of how this economic framework will be implemented are still a work in progress, and the interim outcome is likely to look quite different in the two states as a result of both the regulatory approach and starting state (California has largely built out the AMI infrastructure necessary to deploy temporal and locational price signals while New York has not, though plans are in the works). The policy concept of establishing an economic framework which aligns DER and grid value may even be gaining traction at a national level. Last week 17 bills were submitted to the Senate energy committee; many touch on the topic including one from a US senator from Maine focused on establishing federal rules to “consider just and reasonable rates for DER in an unbundled manner” to “incentivize rational behavior in the energy market and better account for the two-way value of DER to the grid and the grid to DER.”

Notwithstanding implementation differences, the goal is the same—and the risks of failing are the same as well. If developers, customers, and utilities are not given the economic metrics with which to measure DER and grid investments against each other, we may end up with a best case in which investments are made inefficiently and a worst case in which the system is strained by extreme scenarios such as CAISO’s (in)famous duck curve.  In this duck curve, load peaks are exacerbated and valleys are deepened, leading to high costs or reliability risks. With the right economic signals though, we could end up with more efficient use of the electric grid thanks to DER that shaves peaks and fills in valleys while maintaining a more reliable, resilient grid.

In retail electricity markets as with any other market, economic incentives are the key to signaling that a certain investment or decision is valued or encouraged and another is relatively discouraged. The ultimate goal is to align utility rates with net value, meaning there is a cost to provide grid services which is more driven by peak load than by net kWh usage. The net distribution value of DER (or negative value in the cases where DER incurs peak load or voltage impacts) is its ability to defer or drive down those investment costs. This means the cost of serving peak loads and system reliability needs to be felt by customers with the goal of incentivizing load shifting (away from peak) and a more efficient usage of GT&D assets.

The table below summarizes the key rate design pricing tools being debated and considered across the country, highlighting pros and cons of each from the perspective of aligning electricity pricing with DER and T&D infrastructure value (especially peak load shifting, energy conservation, and T&D fixed cost recovery). Note that only TOU rates and demand charges serve as price signals to incentivize peak load shifting, something necessary if DER are to deliver on promises such as avoided GT&D capacity and reduced strain on the T&D system. To capture both temporal and locational DER value, either type of price signal could be rolled out with geographic components as well, such as a lower demand change in areas with lower peaking risk and TOU peak windows that align with local peaks (not just system peaks).

Table 1: Retail Electricity Pricing Toolkit



Notable examples



Time of use energy rates

Charge per kWh that varies by time of day and season to reflect higher peak energy costs

Currently available in many states but no widespread residential adoption. California will be defaulting residential customers in 2019.

Moved toward aligning energy charge with time-varying

would incentivize alignment of distributed generation with system peaks

Need AMI to implement. Need research to determine most effective peak hours and peak rate differentials. Might need granular geographic differentiation to reflect local differences peaking windows. Relatively new concept for most residential customers.

Fixed customer charges

Flat charge applied each billing cycle to reflect the fixed cost of operating the transmission and distribution system and administrative costs of providing service

Approved in a 2013 Arizona proceeding and in several other recent state proceedings including Wisconsin, Connecticut, and Kansas. California plans to eventually adopt as well.

Aligns bills with fixed cost causation.

If set too high (resulting in a much lower energy charge) could dampen conservation incentive.

Does not encourage peak load shifting (driver of “long term” fixed costs).

Minimum bill

A floor to a customer’s monthly bill (as opposed to a fixed charge). Assures that very low energy users (or NEM customers which offset all or most of their energy usage) pay some amount towards fixed costs

To be implemented in Massachusetts. Currently exists for some California IOUs and would be expanded and raised as part of the transition to TOU rates

Ensures all customers pay something toward utility fixed costs.

Preserves conservation incentives for most people (by keeping a higher energy charge).

Does not encourage peak load shifting.

Energy demand charges

Charge per peak kW usage, commonly used in rates for large non-residential customers, increasingly being considered for residential customers

currently available in Arizona; recently proposed in Illinois legislation and rate case proceedings in Kansas, Wisconsin, and Hawaii

Provides a price signal for reducing peak load, aligned with cost causation

New concept for most residential customers, would need education and perhaps supporting technology to enable people to actually respond to the signal (this is the business model of companies like Stem, though they only serve the commercial market)

DG specific charges

DG specific flat charge or charge per kW of installed DG to reflect integration costs and distribution system usage

Some utilities in Arizona and Kansas have structured their rate options so a DG customer can choose between a higher fixed charge or a demand charge but cannot choose a rate that eliminates both or provides a low fixed charge with a high energy charge.

Recently rejected in New Mexico.

Ensures DG owners contribute to any incremental costs for connecting their system to the grid

Provides a price signal which defavorizes DG without differentiating between high and low value DG (where high value means locations where peak is better aligned with solar production and / or penetration is low)


Pricing signals through rate design are a key tool for cost-effective implementation of the policy goals such as cost-effective investment in DER and remuneration for grid services. However, establishing the market signals which incentivize the right behaviors means fully understanding the locational, temporal value of DER in the context of the local T&D needs they can address.  This is a complex and new problem. The upside: the New York and California proceedings are focused squarely on this, and there are a growing number of utilities which have been able to take the first step in the direction of solving the myriad problems that surround the creation of such pricing.

Nexant will discuss how to measure and understand temporal and locational value—including how to identify where, when, and which DER can provide the most value—at an upcoming workshop: “How to Align Distributed Energy Resources with Grid Value” ahead of the ADS National Town Meeting.  We will also be talking about how to design programs, markets and pricing to align DER with grid value. The workshop will feature a panel with Commissioners from many of the states that are at the heart of DER policy (such as New York, California, Arizona, and Minnesota). The ADS National Town Meeting will have a DER track that will include tangible case studies from across the country, including a discussion of how we can use DER to deal with the duck curve.

This workshop is a great opportunity for anyone (DER advocates, utilities, policymakers) to better understand how to unlock the value of DER as a complementary asset to the grid. Ensuring a stable grid, sustainable DER industry, and cost-effective provision of clean, reliable energy depends on getting it right.