You purchased that spiffy new rooftop solar array and waited patiently in the queue to get interconnected to the grid. Now that you’re generating kilowatts-hours, you’ve decided to invest in a residential energy storage system to maximize your ability to avoid paying for peak priced power. There’s one hiccup, though: what do your state’s interconnection rules mean for connecting your new battery to the grid?
We’ve now arrived at a cutting-edge topic in interconnection, one that several states have recently addressed or are working on addressing, and which many more will need to address soon.
As IREC discussed in our recent report, Charging Ahead: An Energy Storage Guide for State Policymakers, energy storage promises to play a critical role at all levels of the electric system, from traditional, utility scale generation down to residential customer applications. It is also vitally important in accelerating integration of all types of distributed energy resources, or DER. Energy storage offers a broad suite of electricity services, including deferral of expensive transmission and distribution line upgrades, the regulation of voltage and frequency, and expanding consumers’ ability to control their energy use and costs.
Yet while energy storage is affected by many of the same interconnection issues we’ve discussed in earlier posts, it also raises new issues because of the technology’s unique characteristics — specifically, its ability to act as both energy “generation” (by injecting stored electricity onto the grid) and load (during its charging state), and its ability to be “controlled” so that it operates only when intended.
Just like traditional generators, energy storage needs a clear regulatory path to interconnection. And, like any other DER, delay caused by interconnection roadblocks can interfere with storage project financing and lead to higher costs for customers.
As energy storage is deployed at increasing scale, and technology development costs continue to decline, states like California, New York, Maryland, Nevada and others are working to address the following issues related to interconnection of energy storage.
The first step in clearing the path for interconnection of energy storage is determining whether or not a state has adopted interconnection standards and, if so, clarifying if and how these existing rules apply to energy storage. Most states’ existing rules say that they apply to “generating facilities.” But in defining what qualifies as a “generating facility,” these rules frequently omit mention of energy storage, creating some ambiguity about the ability of a storage system to apply under the rules.
In 2013, the Federal Energy Regulatory Commission (FERC) set an example for how to address this issue. In its small generator interconnection procedures (SGIP), FERC revised the definition of “small generating facilities” to explicitly include energy storage systems. The effect of this change was to resolve any ambiguity regarding the applicability of the rules to storage systems.
FERC’s example also sets a standard for states looking to revise their own interconnection procedures. In most cases, existing rules are often already broad enough to embrace new and evolving technologies, including the many battery types and mechanical devices referred to collectively as “energy storage.” Yet without a real evaluation of existing standards, especially the thornier questions we’ll encounter next, there is still a risk that an energy storage system will be hampered by rules that were written with different types of resources in mind.
Ensure rules for interconnection account for the “load” aspect of energy storage
Interconnection rules are typically written to address the impacts of adding new generation to the electric system. New sources of load, on the other hand, usually are not required to go through the same process. As a result there could be two separate processes that apply to energy storage, even though the technical review can usually be done simultaneously.
In particular, the rules around cost allocation for new load are typically quite different than those for new generation. Typically there is some rate-based allowance for new load facilities — that is, ratepayers pay these costs — while new generators are directly responsible for their interconnection costs. These differing approaches pose a conundrum for energy storage systems because these systems can act as generation and load simultaneously, and the same upgrades might be triggered by either function.
What is the appropriate process for these facilities? How should their costs be allocated?
To prevent this minor point from becoming a major delay, states should look closely at how their rules for interconnecting generation interact with rules governing new load. In California, for instance, the Public Utility Commission has set forth a revised process
for analyzing requests to interconnect behind-the-meter, non-exporting energy storage. The decision clarifies for energy storage projects how the rule for interconnecting new generation (Rule 21) interacts with rules for new load.
Among other things, the decision states that energy storage’s load aspect shall not be treated differently from other load increases arising from the installation of new appliances. In addition, the utilities have published helpful guides for storage interconnection that outline the steps in the review process to increase transparency and minimize disputes.
Ensure rules for interconnection properly consider energy storage systems’ generating capacity
The installation of energy storage and solar together, as in the scenario we began with above, warrants some special attention. The storage device’s role may be simply to capture electricity generated during the day for use in the evening, rather than injecting it back onto the grid (i.e., it may be non-exporting). Or it may be designed to export power back onto the grid for sale to the utility or into a wholesale market. In either case, interconnection procedures should require utilities to take into account how these systems will actually behave in practice, rather than assuming worst case scenarios.
For non-exporting storage systems, for example, it is appropriate to ensure that technical screens in the Fast Track process that relate to the amount of electricity sent onto the grid are not applied to projects which do not export any energy. Some states have also started to apply a more flexible definition to what constitutes a “non-exporting” system, recognizing that some minor amount of inadvertent export can be managed without damaging the electric system or requiring an overly onerous review process. While this change should be applicable to a wide range of inverter-based systems, it can be particularly important for co-located storage systems.
If a storage system will export electricity onto the grid, it is also important to properly define how that system will operate. Once again, FERC’s interconnection guidance can help states with this issue. Under standard interconnection rules, the utility studies the project’s effect on the system at the “maximum capacity that the particular device is capable of injecting” electricity on to the grid. But such a rule would be illogical for energy storage because rather than run at maximum capacity around the clock, storage systems are controlled, or “dispatched,” on an ongoing basis; charging when there is a surplus of energy, and discharging when there is a greater energy demand. And for co-located systems, it is highly unlikely that they would discharge at the same time that the on-site generator was also discharging to the grid.
Thus, FERC’s interconnection process directs utilities to assume less than the maximum capacity if the applicant can demonstrate that it can limit the export so as not to “adversely affect” the safety and reliability of the electric system. This more flexible approach accounts for storage’s unique ability among DERs to be dispatched minute-by-minute to ensure optimal performance. When dispatched properly, storage can minimize its impact on the electric system, thereby avoiding many interconnection concerns.
A foundation for energy storage market growth
Even in a state with assertive DER policies like California, including an energy storage incentive program and the country’s most progressive storage procurement mandate, the market would stall without a strong regulatory foundation in place, especially with respect to interconnection. Otherwise, interconnection could emerge as a significant blockade to the success of storage programs.
Fortunately, the list of states taking action to answer these questions continues to grow, with Iowa recently adopting some changes to their procedures to better accommodate storage systems, and Minnesota and Nevada are currently considering what changes to their rules might be appropriate to better facilitate energy storage interconnections.
In our next, final, blog post, we will discuss how to resolve disputes that may arise in the interconnection process. Stay tuned.
Sky Stanfield, Erica McConnell, and Joseph Petta are attorneys with Shute, Mihaly and Weinberger LLP, attorneys for the Interstate Renewable Energy Council.