By Erica McConnell and Laura Beaton
Imagine you’ve just moved to a new neighborhood and you’ve signed up for your new internet service. You’ve paid an initial fee to connect your home to the network, and all systems seem to be a go. As you eagerly await the installation so you can catch the long-awaited season 7 of the Game of Thrones and order some new home necessities online, you receive a notice from the provider that—surprise—your internet connection is going to overload the network in your neighborhood, which will slow down everyone else’s service.
You will pay for needed network upgrades, to the tune of thousands of dollars, or you can’t have internet at all. You alone must pay for the network upgrade, though everyone in the neighborhood will benefit from the faster internet, including anyone who moves to the neighborhood after you. As the unlucky one whose connection request caused the tipping point, you are on the hook for paying the cost of the upgrades—or no internet, no online shopping, and no Game of Thrones.
While this scenario sounds unimaginable—one that most consumers would not stand for—the reality of connecting distributed energy resources (DERs) to the grid, like rooftop solar or energy storage, is that such occurrences are not uncommon. As explained in our last Connecting to the Grid blog on cost certainty and predictability, the interconnection of DERs to the distribution grid is generally a “cost-causer pays” system. In other words, a resident, business, school, or hospital seeking to install solar has to pay for any distribution system upgrades that may be deemed necessary to accommodate the project, even when the upgrades will very likely support the interconnection of additional projects in the future. What’s more, those future projects won’t have to pay for those upgrades, but they will likely benefit from the investment in the grid infrastructure.
Economic cost allocation and fairness theories aside, this practice can kill perfectly viable and beneficial projects that haven’t budgeted for high upgrade costs, and it can also cause major delays in the process for all involved. If an applicant receives a bill for upgrades that she can’t afford, she may spend time trying to figure out a way around paying the costs, grinding the interconnection queue to a halt for that circuit until a solution is found or she drops out. And then the next applicant repeats the same process, until someone eventually can pay. Or, no one attempting to connect to the circuit may be able to afford the cost of upgrades, effectively closing the circuit.
While this story doesn’t play out for all DER projects, the need for system upgrades does arise, particularly when multiple distributed generation (DG) projects are connected to a single circuit, sometimes called stacked projects. At some point, the circuit will reach a threshold, or capacity, for DG connecting to the grid. Upgrades are needed to increase the capacity of the circuit or otherwise address voltage and other system impacts. As it stands in most states, whichever applicant is unlucky enough to be next in line when that point is reached pays for the upgrades, which range in cost and depend on the size and nature of the project, but can be in the thousands or tens of thousands of dollars for smaller systems, and up to $1 million or more for much larger projects.
Hawaii—the state with the highest rate of solar penetration in the United States, with one in nine households having a rooftop solar system—was the first state to experience the significant ripple effect of problems associated with closed circuits. Following a boom in solar growth, Hawaii’s utilities started declaring circuits “closed.” According to the utilities, there was simply too much distributed solar connecting to the grid and unless upgrades were made and paid for, no one else could install solar in the vicinity. But a single homeowner could not pay the cost of upgrading the whole neighborhood’s circuit.
With no new interconnections possible, the solar market in Hawaii contracted dramatically. Hawaii’s closed circuits resulted in public outcry and garnered significant attention, leading the state to implement significant interconnection and other solar policy reforms, including increasing the maximum capacity for solar PV on the initially closed utility circuits (which were increased from 120 percent to 250 percent of daytime minimum load). In addition, the expanded use of smart inverters and/or energy storage are being further explored as ways to mitigate adverse system impacts and increase the circuit hosting capacity.
While Hawaii remains the best known and most referenced example of this scenario, we are seeing the issue of closed circuits crop up elsewhere, including in states with substantially smaller solar markets as compared to Hawaii, like Maryland.
Aside from increasing the technical hosting capacity and pursuing other solutions to mitigate system impacts of increasing DG on a circuit, the issue of cost allocation remains problematic when the only option is a costly upgrade to the distribution grid. This issue has left stakeholders in states across the country wondering about other ways to study multiple projects on a circuit and perhaps share the burden more evenly among their fellow applicants.
States with higher penetrations of DG have begun piloting some possible solutions. For example, California has adopted distribution group-study processes to allow the utility to study multiple projects interconnecting to the grid at the same time. If the study shows that the interconnections as a group will trigger the need for an upgrade, the cost of that upgrade is allocated proportionally to all of the projects. Another process, quite similar to California’s, is the “cluster study” processes used for transmission-level interconnections, such as those undertaken by the California Independent System Operator (CAISO) and other ISOs.
However, group interconnection studies are not without challenges. The objective of fair cost allocation relies on every applicant in the group sticking through the whole process. So, for example, if one applicant in the group study drops out, studies may need to be repeated and costs reallocated among the remaining applicants—which could itself increase costs, add more time, and cause more headaches for utilities and applicants.
New York recently adopted a different approach to cost allocation, proposed by New York’s Interconnection Policy Working Group, that could avoid the problem of repeated restudies. For certain projects and in certain circumstances, once an upgrade is deemed necessary, the project triggering the upgrade pays for it and then applicants interconnecting to that circuit afterwards reimburse that initial project, up to a certain point. This approach has intrinsic appeal because it allows for cost sharing and avoids the problem of projects dropping out of a group study process midstream.
The approach is an interim solution, however; it is limited in scope and does not address allocation for all possible types of shared upgrades. It also remains to be seen how useful it is in practice and doesn’t get around the fact that the cost-causer may not have the upfront capital to pay for the upgrade (but may stay in the queue and cause backlogs). The Interconnection Policy Working Group continues to work on refinements and improvements to this new concept.
The cost-allocation methods discussed here are steps in the right direction. While individual customers may chafe at paying more to interconnect, the alternatives—not being able to interconnect at all because the circuit is closed, or being the one unlucky applicant who has to pay for all of the upgrade—are arguably worse outcomes, particularly for those who have already invested considerable time and resources to develop, permit, and finance a project. Innovative ways to share costs between and among projects offers a fairer approach, which can hopefully support a more streamlined and cost-effective process for consumers, utilities and developers.
However, cost allocation challenges are symptomatic of a larger issue at play on the distribution system. The process to review and interconnect DERs to the grid is still reactive, instead of proactive. Absent more comprehensive and transparent distribution grid planning and DER forecasting, costly queue backlogs and system upgrades will likely be a constant reality as penetrations of DERs on the grid continue to increase.
Hawaii’s utilities and regulatory stakeholders took a step in this direction with their proposed proactive approach, which would have utilities determining the need for and constructing necessary upgrades, as determined by past studies and other system analyses, and distributed generation forecasts. It still leaves open the core question of who pays for those upgrade costs at the outset, and how the costs are ultimately allocated among interconnection applicants, and potentially ratepayers.
Hawaii’s approach contributed to the very similar concept known as integrated distribution planning, which is under consideration in a number of states today and represents an innovative shift for the planning of the distribution grid and interconnections of DERs. In addition to cost allocation, integrated distribution planning puts issues of hosting capacity analysis and DER forecasting front and center. It brings us to the cutting edge of interconnection, and its intersection with distribution planning and broader grid modernization efforts.
Check out the next installment in the Connecting to the Grid series for a deeper dive on this transformative approach to grid planning—just when you thought the anticipation that comes with waiting for the next episode of the Game of Thrones couldn’t be matched.
Erica McConnell is special counsel and Laura Beaton is an associate attorney with Shute, Mihaly and Weinberger LLP, attorneys for the Interstate Renewable Energy Council.