MN Interconnection Ruling Contains Some Wins and a Major Threat
Editor’s note: This article was updated on August 8, 2022 to reflect emerging data on the impact of Xcel’s technical planning limit.
Interconnection has been making headlines more and more in recent months, as states around the country grapple with the reality that effective interconnection policies are essential to enabling rapid deployment of distributed energy resources (DERs), from community solar arrays to residential solar-plus-storage systems.
One of those states is Minnesota, where the local investor-owned utility Xcel Energy has been struggling with a significant backlog of interconnection requests for years. A new ruling by the Minnesota Public Utilities Commission (PUC) has important implications for interconnection, some good, some bad.
Some of the positive developments in the new ruling provide avenues to make the interconnection process more efficient, something that has been sorely needed. Another notable part of the decision creates a new mechanism for distributing the costs of grid upgrades needed to accommodate more DERs. These positive developments, advanced through the collaborative contributions of public interest groups like Interstate Renewable Energy Council (IREC) and Fresh Energy, reflect emerging best practices. Despite these wins, there was also one very damaging outcome of the ruling, an unsupported “technical planning limit,” that threatens the future growth of clean energy in the state.
In this article, we explore each of the key elements in this ruling, their implications for clean energy in Minnesota, and the lessons this ruling provides for other states.
Win #1: Easing the Interconnection Logjam
Given the long wait times facing Minnesota clean energy projects waiting to connect to the grid (a challenge facing projects in many other states), it has been clear that a more efficient process for reviewing interconnection applications is needed. An analysis by the Minnesota Solar Energy Industries Association last year estimated it would take 260 years to clear the backlog at Xcel Energy’s current pace of review!
Currently, Xcel reviews most interconnection requests one at a time, proceeding to review a subsequent project in the queue only after the project before it has a signed interconnection agreement (for projects 40kW and above, or smaller projects in capacity-constrained areas), as is typical in most states.
However, several leading states are beginning to explore more efficient approaches, including parallel studies and group studies. Parallel studies involve studying two or more projects at the same time, while group studies (sometimes called cluster studies) “involve grouping a series of DER projects together for a system impact study and later a facilities study.”((https://efiling.web.commerce.state.mn.us/edockets/searchDocuments.do?method=showPoup&documentId={4084E17F-0000-CD19-93F4-3731AC9F8288}&documentTitle=20223-184288-01)) The MN PUC’s decision addresses this in two parts: an interim plan focused on parallel studies, and a longer-term solution to develop a group study process.
Parallel Study Process Decision
Xcel already allows some parallel review of very small projects, but was unwilling to extend that process to projects requiring more in-depth study. As an interim step to help things move faster in the absence of a group study process, the Commission made two rulings.
First, it ruled that Xcel must extend the parallel review process to fast track projects where there are no known capacity constraints in the area, as well as in areas with known capacity constraints where the proposed project would not trigger the constraint.
For projects undergoing study, instead of finishing the entire study process and waiting for an interconnection agreement to be signed for one project before moving on to the next, the Commission ordered Xcel to move on to reviewing other projects once it begins the facilities study for the earlier-queued project. By this stage, Xcel should have determined what upgrades will be required for a project, if any, through the completed system impact study. This means it should be able to build a base case to begin studying the subsequent project in queue. The change will go into effect within 30 days of the Order.
Group Study Process Decision
While parallel studies are an improvement from sequential review, from IREC’s standpoint, group studies are the best near-term option available for more efficient approval of DER interconnection requests in light of the current queue situation in Minnesota.((IREC supports group studies when designed and implemented properly, but believes Commissions should ultimately move to a planning-based approach where upgrades are done on a proactive basis that anticipates and plans for the integration of future DERs, rather than reacting to them.))
Under the ruling, Xcel will begin piloting group studies while a working group is convened (within 120 days of the order) to define the details of how the group study process works. This is an exciting and positive development because there is now a pathway for developing a group study process in Minnesota.
The decision is not without flaws, however, because, no parameters or guidelines for the pilot process have been established, and the pilot can begin before the working group has convened to develop recommendations. This is problematic because participation in the pilot will be mandatory for projects that Xcel chooses (it applies to any area with three or more applications greater than 40 kW that cannot be reviewed in parallel) but the details of how the group study process will be implemented are unclear. This could result in serious disputes and consequences for affected projects because there are no boundaries or rules in place with respect to timelines, allocation of costs, or any other element of the pilot.
Because of this, the Commission should prioritize quickly moving to a more defined process, by ruling on the resulting working group proposal.
Win #2: Sharing the Costs of Grid Upgrades
A second very positive development from this ruling relates to how the costs of grid upgrades are distributed when upgrades are needed for more DERs to connect to the grid. This is a critical issue that is increasingly emerging across the nation as more states reach high levels of renewable deployment.
Historically, a “cost-causer pays” approach has been the norm—both in Minnesota and across the nation. Under this approach, when equipment upgrades are needed on the distribution grid to safely accommodate a new DER project that requests to interconnect, that project is responsible for paying the full cost of those upgrades. This approach is problematic for multiple reasons. At a system level, it significantly slows the process of implementing needed grid upgrades, because projects often can’t afford to absorb these costs and withdraw their interconnection request. This can happen repeatedly, leaving sections of the grid effectively closed to new DER development until a project arrives that can shoulder the costs. It also is unfair, because all projects that connect to that section of the grid after the upgrades are implemented benefit from the upgrades without sharing in the costs (at least until the next time a proposed project triggers the need for an upgrade).
Informed by our work in other states and the best practices that are emerging to address this issue, IREC introduced the idea of a cost sharing mechanism for small projects. From there, Fresh Energy led the work to develop the details of the proposal and do the math to make the case for its implementation.
Minnesota’s New Cost Sharing Approach
Under the new cost sharing method approved by the Commission, all interconnecting projects under 40kW will now pay a flat fee. That fee will contribute to a pool of funds that will be used to pay for the necessary grid upgrades for projects in that category.
Under this improved system, all DER developers will contribute equally instead of some unlucky projects bearing a disproportionate burden. This will prevent stoppages that otherwise result as developers grapple with unanticipated upgrade costs that may make their projects unviable. It also means that grid upgrades won’t be delayed until a project that can afford to pay for them moves forward.
Another win is that, as designed, this policy will not involve shifting the costs of grid upgrades to ratepayers. (This may be appropriate in some circumstances, but was not the best option here.) A proposal by Xcel had offered an alternative which would have distributed the costs across its customer base, and would have applied to a smaller subset of projects. To their credit, developers in Minnesota expressed their willingness to shoulder the costs of grid upgrades under the new system.
The amount of the fee that interconnecting projects pay will be revisited annually and adjusted based on the costs of upgrades in the prior year. The Commission opted to put a $15,000 cap on upgrade costs for any single project.((Note that this limit was chosen somewhat arbitrarily during the hearing; it is not yet clear what impacts it will have on the success of the program.)) This cap was not well justified in the record and will limit some of the benefits of a cost sharing approach. Specifically, often the most significant upgrades are those that cannot be borne by any individual small project. This $15,000 cap will prevent the application of the cost sharing approach to the more significant upgrades that most need cost sharing to proceed.
The Bad News: Significant and Poorly Justified Limits on DER Deployment
It was not all good news for distributed clean energy in this ruling, however.((One other element of the ruling, not detailed in this article, relates to an agreement that Xcel entered into with the Midcontinent Independent System Operator (MISO), one of the nation’s transmission grid operators. When a project seeking to interconnect on the distribution grid has the potential to impact the transmission system (operated by MISO in Minnesota and other midwest states), Xcel requires an “affected systems” study. Earlier this year, Xcel entered into an agreement related to these studies with MISO without commissioner or stakeholder input. Stakeholders raised concerns that this could be in violation of the state’s interconnection procedures. In this ruling, the Commission requested more comments on the issue. They will make a ruling a later date, while allowing the existing MISO ad hoc study process to go ahead.)) A potentially devastating element of the commission’s ruling is a decision to allow Xcel to implement a “technical planning limit” (TPL) that “caps the total capacity of a particular feeder or substation as a function of its respective equipment rating and DML [daytime minimum load].”
Xcel proposed a new methodology it plans to use internally to determine how much DER capacity can be installed in a given area of the grid. IREC calculates this change in policy will result in a 2-3 GW reduction of total available capacity!((This was corroborated in Xcel’s September 24, 2021 Office Hours where they referenced a 2.6 GW reduction.))
Xcel asserts that their new TPL policy would provide a buffer so that if load (i.e., customer electricity demand) dropped unexpectedly, thermal limits on feeders would not be reached. However, as IREC detailed in its public comments on the issue, the proposal is unreasonable for several reasons. First, Xcel failed to provide sufficient evidence to demonstrate that this change is really needed for safety and reliability. Second, it uses an overbroad approach that applies one metric to every feeder, instead of a more specific calculation that would be more representative of actual grid conditions. Finally, it assumes that a substantial amount of load would drop off suddenly on a feeder, despite no evidence that this is likely to occur or has occurred in the past. (For more information on the technical details of Xcel’s proposal, see PUC Staff Briefing Papers.)
The damage of this decision is further compounded by the fact that Xcel has taken the position in other dockets that it will not upgrade equipment on constrained circuits past a certain “conductor size” unless it is as a result of changing load. It will not engage in upgrades for new generation—even if the customer will pay for it. While the details of how this will work in practice remain to be seen, it could mean that beyond a certain amount of generation, no more can ever be interconnected without building entirely new feeders (something Xcel has also been reluctant to do).
Although it was made very clear at the Commission meeting, through direct responses to Commissioner questions, that Xcel had not provided sufficient support for this proposal, the Commission declined to reject the current proposal and require more evidence. Instead itallowed Xcel to proceed, with the requirement that it “raise specific issues with DML in its quarterly compliance filings.” This directive is unclear and does not require Xcel to meet a reasonable standard of proof that its policy is not unduly restrictive.
One small positive in this outcome is that the Commission did reject a related proposal by Xcel to reserve 25% of available capacity for DER systems smaller than 40 kW. This policy was not supported by evidence and would have preferenced homeowners over community solar projects, raising equity concerns.
Early TPL Results Already Show Decreasing Capacity for Renewables in Minnesota
As of August 1, 2022, Xcel is now utilizing this planning limit in its hosting capacity analyses (HCA), offering some early insights into the impacts of this decision. HCA is a grid transparency tool that allows developers and other stakeholders to see how much remaining capacity is available to accommodate new clean energy generation on different parts of the grid, among other things.
As a result of this and other changes, Minnesota feeders (sections of the grid) that show zero hosting capacity available have increased—from 65 out of 1,055 (6%) in Q2 of 2022 to 110 (10%) now. For a short period of time, this is a significant increase in sections of the grid that can no longer accept renewables, and it is important to understand that this is not a limitation based on the actual conditions on the grid, but rather Xcel policy. The TPL will likely undercut the state’s ability to meet its clean energy goals over time.
Two Steps Forward, One (Big) Step Back
Interconnection policies continue to be one of the most significant issues limiting the growth of clean energy across the U.S. and the issues faced in Minnesota are representative of challenges being confronted in other states. This ruling includes multiple improvements over the status quo that are meaningful and offer insights for other jurisdictions (group studies and cost sharing). At the same time, the technical planning limit (TPL) is a huge threat to Minnesota’s clean energy and climate goals.
The Commission’s approach of not requiring the regulated utility to provide an adequate level of support for a policy that could substantially limit the amount of DER deployed in the state undermines the Commission’s regulatory authority. It enables, and perhaps even encourages, utilities to use the interconnection process to circumvent other Commission policies they may not agree with. We hope the Commission will more thoroughly investigate the need for the planning limits and ensure that, if a need is shown, the policy is carefully tailored to address the need and not applied in an overly broad manner that unnecessarily hinders the ability of customers to install clean energy systems.
