Contributed by C.J. Colavito, VP of Engineering, Standard Solar; GridTECH Connect Forum Advisory Board Member
How will the solar industry meet the expected surge in solar-driven by the Inflation Reduction Act (IRA)?
The new infusion of incentives will provide an enormous boost for the industry, but it will not remove barriers to deployment like long interconnection queues. To take full advantage of the IRA incentives, we must also deal with these barriers.
By 2030, the $370 billion allocated in the IRA for climate and energy measures is expected to increase solar deployment fivefold and spur 550 GW of new renewable energy projects — many of which will be solar installations.
These numbers are impressive, and the industry welcomed the boost and policy certainty provided by the IRA.
But the $370 billion by itself, while helpful, is not enough to achieve the projected figures for solar growth. Now that we have policy certainty, we must focus on removing some significant barriers that stand in the way of increased solar deployment.
Interconnection is one of the most tenacious of these barriers. Ironically, the IRA could even exacerbate this already significant challenge — unless we make a concerted effort now to fix the system.
SAVE THE DATE! The next edition of the GridTECH Connect Forum will be held in Newport, Rhode Island on Oct. 23-25. We’re bringing together developers, utilities, and regulators to take on the critical issue of DER interconnection in the Northeast. Save the date to be alerted as soon as registration is open. See you in Newport!
A foundation for interconnection reform
Fortunately, the technology we need to streamline interconnection is already available. What’s needed now is good policy at both the federal and state level to open up the current logjam. Interconnection policy should follow the principles of transparency, standardization, and automation.
Transparency in interconnection is key. Developers need detailed, real-time load data, hosting capacity maps, and queue information to determine whether to enter the interconnection process. Timelines, processes, and costs must also be transparent. And for projects at the distribution system level, technical requirements and fees for infrastructure upgrades must be clear and reasonable.
As much as possible, interconnection processes and fees should be standardized and automated. That should include predictable, reasonable, and firm timeframes, deadlines for interconnection studies, and rigorous enforcement.
A positive step that’s being taken at the federal level is the proposed rulemaking on interconnection from the Federal Energy Regulatory Commission (FERC), which focuses on speeding up interconnection. If implemented, the proposal will facilitate the deployment of utility-scale projects across the U.S.
However, much more action is still needed at the state level for projects interconnected to the distribution system. We have the opportunity to make real progress for large-scale distributed generation projects between 1 MW and 20 MWac. That will allow distributed energy resources (DERs) to play a significant role in managing the grid and supporting the distribution system’s reliability — benefitting solar companies, utilities, and customers alike.
First steps to reforming DER interconnection
How do we arrive at these mutually beneficial solutions? It will take the evolution of distribution utilities into distribution system operators (DSOs). But, in the near term, we can start with closer coordination between developers and utilities, using detailed feeder-level grid data and information about projects in interconnection queues. Developers need this transparency and insight, and utilities need tools and resources.
DER management systems (DERMS) provide a vital tool for utilities to support the grid with more DERs. With real-time controls between a solar system and the distribution grid, DERMS give utilities the ability to see the details of the system and control it. For their part, developers need certain limits and requirements to ensure that the utility control still allows the projects to deliver expected returns.
Within these kinds of bounds, DERMS provide significant benefits to all stakeholders. They allow a utility to use a solar PV system as needed to help balance the grid. And they allow more DERs to connect to the grid, which brings all ratepayers the benefits of increased local energy generation. For a developer, this added capacity can mean a project can be built that could not have built without the DERMS, or it can mean a larger project can be built.
As crucial as DERMS are, they are simply tools to facilitate DER integration. Close coordination between utilities and developers is still needed to help clear interconnection queues. Unfortunately, queues are often clogged with projects that are not viable. Because many incentive programs are tied to having interconnection approved, developers often submit numerous projects and hope that one or two make it through the process. This practice needs to change, and incentive programs should be adjusted to avoid this situation.
More feedback and transparency from utilities will also help prevent projects that aren’t viable from entering the queues. This must go beyond more detailed and ubiquitous hosting capacity maps to include more transparent queues. Without giving away proprietary information, utilities can let developers see the number of systems in the queue, their proposed AC capacities, and the substation transformer’s kVA rating.
More resources are needed for both utilities and developers to support interconnection studies and reviews, and utilities should invest in more employees to support the process. But backlogged interconnection queues put more strain on the already limited resources. Another option could be for utilities to allow applicants to directly contract with pre-approved consultants to conduct interconnection studies. Increased transparency will help developers clear the queues of projects that are not viable and avoid wasting valuable time and resources for both utilities and developers.
A vision for the future: Utilities as DSOs
The next step beyond increased coordination is the shift to DSOs. A DSO would operate and maintain each local distribution area like a regional transmission operator (RTO) but at the distribution system level.
Because utilities already perform many of the functions of a DSO, they are well-positioned to make this shift. The increased deployment of DERs will hasten the shift, and utilities will also be motivated by the resilience benefits of distributed solar plus storage. Developers will need to be paid for that resilience value, making projects more affordable and incentivizing them to build more.
Some utilities across the U.S. are already moving in the DSO direction and modeling good interconnection processes with detailed information and transparency. That demonstrates that it’s achievable. In some locations, utilities pay customers to cede control over their EV charging or air conditioning as a grid balancing tool in exchange for compensation. This à la carte method, which will expand to include EV infrastructure, distributed renewables, and perhaps other DERs, is likely to evolve into a more holistic, integrated system as utilities find they need more policies and programs for effective grid management.
Our task now is to replicate and expand on the models that are working. The U.S. Department of Energy’s Interconnection Innovation e-Xchange (i2X)initiative is convening diverse stakeholders to support these efforts and facilitate the exchange of knowledge. We must get the word out about effective models and ensure utilities and developers have the information and tools to streamline interconnection. This is necessary for both fulfilling the promise of the IRA and meeting our nation’s clean energy goals.
