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A Customer's Guide to Interconnection

With over 20.5 GW of non-utility-scale solar online in the U.S. at the end of 2017, distributed generation (DG) has proven itself to be a cost-effective and sustainable resource. Given this increased growth in distributed solar, however, the need for improved grid infrastructure has become even more important. For instance, as solar assets have come online in mature markets like California, we’ve seen concerns over the “duck curve” caused by an oversupply of power during the peak mid-day solar hours.

While innovations like clean-peak standards and storage are starting to alleviate this pressure, high levels of distributed solar deployment have also affected the ability for future projects to come online.

For a distributed project to receive incentives, it must be interconnected to the local grid, allowing the utility to monitor its production. As more distributed solar is connected to the grid, the infrastructure’s ability to accommodate new generators decreases. How does this look in different parts of the country, and what are the effects on a solar customer’s project?

What are the regional differences in interconnection?

Today, when any generator wants to interconnect, it requires an interconnection study, which includes multiple steps to understand the project’s impact on the grid and whether or not the existing infrastructure can withstand a new generator. Some regional transmission organizations who match supply and demand on the grid, like ISO New England in the Northeast and PJM in the Mid-Atlantic, use a queue for these requests, which can mean that if a project requires grid upgrades in order to interconnect, the generator must pay for these upgrades. Expensive upgrades can prevent a project from going forward, even if it was developed right after a neighboring solar project.

It’s important to understand that the grid wasn’t necessarily built with distributed generation in mind. Originally, the American grid infrastructure was built to accommodate large, utility-scale generators located separately from sources of consumer load. Think of the old-school coal and gas plants that have conventionally been the base of our electric supply. This has turned the current system of utility interconnection upgrades into the vestige of a system that catered to utility-scale generators. Today, instead of larger projects interconnecting infrequently, distributed generators are numerous and require bidirectional metering to send unused electrons back to the grid.

Some regional transmission organizations in more saturated markets, like California ISO (CAISO), have implemented a cluster system where neighboring projects are evaluated together and CAISO can offer cost-sharing solutions. Some parts of PJM are also starting to use this clustering method as well, and there is a growing discussion over how regional transmission organizations can invest in cheaper grid modernization upgrades that can help avoid the costlier upgrades that often fall on DG projects.

In the meantime, it’s up to solar customers to stay educated and work with an experienced solar partner who can work through the interconnection process and assess what types of upgrades a project can withstand. It’s important to remember that even if a project requires grid upgrades, your solar developer can work with you to figure out how to redesign the project so it still goes forward.

What do grid upgrades mean for a customer’s ability to go solar?

The solar industry has seen numerous projects fail because of the inability to interconnect in a timely, cost-effective manner. Utilities can only process a limited number of interconnection applications at a time, and often when new incentive programs open, the utilities can be overwhelmed by the number of new applications. Interconnection delays can affect customers in numerous forms, though knowledgeable customers can overcome many of these common hurdles.

In all markets, customers who move the quickest in committing to go solar will be in the best position to take advantage of the most lucrative incentives in their markets, despite the design of the incentive program. Customers in declining block incentive programs are likely to receive lower incentives if they experience interconnection delays, as most programs require an executed interconnection service agreement. Customers whose interconnection applications are incomplete or delayed will not be able to enter the program in a timely manner and will receive a lower incentive as the rates step down.

For example, in Illinois, the queue for interconnection into the lucrative community solar program is already crowded and will result in a lottery system if oversubscribed by 200 percent. Similarly, in the new Massachusetts SMART program, the first incentive block’s applications are sorted by executed interconnection service application date, benefiting the earliest movers significantly. Declining block programs aren’t the only incentives that are foregone thanks to delayed interconnection. In SREC markets, interconnection delays can result in foregone SREC revenue as the market changes and prices generally decrease over time.

As a solar customer, what can you do?

Overall, interconnection upgrade costs and timelines can affect the ability for a customer to go solar, but early adopters can often avoid major costs, especially in newer markets. Despite existing grid constraints in mature markets, it’s important to know that first-movers still have the edge both in monetizing incentives which are most lucrative early on and because interconnection will be less costly and time-consuming today than in a year or two, barring any large-scale grid overhaul.  Even if you just have an inkling that you might be interested in solar further down the road, it’s still a good idea to explore your options sooner rather than later because they are already extremely strong today.

For all customers, it’s important to keep in mind that the interconnection timeline is not necessarily within a solar developer’s control. It’s up to the utility to process the applications, and the results may not always be positive for the project. However, having an experienced solar developer on your side is imperative, as they will keep you up to speed on what interconnection backlogs may exist in your area and if you should be concerned. Just because a project encounters an interconnection constraint, doesn’t mean its future is doomed. Customers who know which questions to ask their developer and the status of interconnection in their region will find themselves in the best position to succeed.

By Sandhya Mahadevan

This is an excerpt from the April 2018 edition of The SOL SOURCE, a monthly electronic newsletter analyzing the latest trends in renewable energy based on our unique position in the solar industry. To receive future editions of the journal, please subscribe.

ABOUT SOL SYSTEMS

Sol Systems, a national solar finance and development firm, delivers sophisticated, customized services for institutional, corporate, and municipal customers. Sol is employee-owned, and has been profitable since inception in 2008. Sol is backed by Sempra Energy, a $25+ billion energy company.

Over the last eight years, Sol Systems has delivered 700MW of solar projects for Fortune 100 companies, municipalities, universities, churches, and small businesses. Sol now manages over $650 million in solar energy assets for utilities, banks, and Fortune 500 companies.

Inc. 5000 recognized Sol Systems in its annual list of the nation’s fastest-growing private companies for four consecutive years. For more information, please visit www.solsystems.com.

Photo Credit: U.S. Department of the Interior via Flickr

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