by Jeff St. John
October 23, 2018

Over the past several years, a handful of states — California, New York, Hawaii, and most recently, Nevada — have taken on the challenge of integrating distributed energy resources (DERs) like rooftop solar, energy storage and plug-in electric vehicles into the way utilities plan for and operate their distribution grids. Now it’s Minnesota’s turn. 

On August 30, the Minnesota Public Utilities Commission approved its Integrated Distribution Planning Requirements for Xcel Energy (PDF), the state’s biggest utility. This IDP framework orders Xcel to start the work of building systems to value DERs’ contribution to the grid serving its 1.3 million customers. 

By Nov. 1, Xcel is required to file an IDP plan that includes a ton of data on its distribution grid and the DERs connected to it, as well as its best available forecasting for local load growth and DER proliferation over the next 10 years. It will also be asked to provide a five-year “action plan” for “distribution system developments and investments in grid modernization based on internal business plans,” one that includes DER forecasts, hosting capacity analyses, and a “non-wires alternatives analysis” that represents the state’s first foray into DERs to replace traditional grid investments.  

The PUC will have until June 2019 to accept or reject the plan, giving parties involved in the process some time to comment and suggest alternatives. Meanwhile, it has established separate dockets for the rest of the state’s rate-regulated utilities to come later. 

“We’re really pleased with the results overall,” said Allen Gleckner, director of energy markets for Fresh Energy, a nonprofit that’s closely involved in Minnesota energy policy. Fresh Energy has been involved in the IDP process since it was launched in 2016 as part of the PUC’s broader grid modernization initiative (PDF). He explains the concept behind it as, “If we’re going to be tackling the distribution grid and updating it to handle new grid edge technologies, then distribution planning should be our first big place to dig in." 

And as a first effort, “it’s actually really comprehensive,” he said. “Our biggest focus now is how [we can] take these requirements and translate them into plans and a stakeholder-regulatory process that drives meaningful outcomes.” 

Xcel’s IDP framework has borrowed quite a bit from the states that have gone before it, such as California’s Distribution Resources Plan proceeding and New York’s Reforming the Energy Vision initiative, he noted. 

At the same time, Minnesota’s IDP has its own state-specific foibles, as pointed out in a September blog post from Sara Baldwin, regulatory director for the Interstate Renewable Energy Council, another group closely involved in the policy’s development. IREC and Fresh Energy both asked the PUC to add more requirements and specifics to the draft IDP plan submitted by Xcel earlier this year. Some of these made it into the final PUC framework adopted in August — but others did not, as Baldwin pointed out. 

“It’s definitely important to keep in mind that this effort is relatively vanguard across the country,” Baldwin said in an interview last week. “We’re asking utilities to do a much more detailed analysis of their distribution system in the context of distributed energy resource growth, and how these planning components and forecasting components and analytics can start to sync up.” 

“It will take some time for utilities to start to get these tools developed,” she said. “The good news is, there are a growing number of providers out there that have tools to do this in a more streamlined way, so that they utility doesn’t have to reinvent the wheel.” 

Minnesota’s IDP framework: What’s in it and what’s missing, so far 

The Minnesota PUC defines the planning objectives of its IDP process as maintaining and enhancing grid safety, security, reliability and resiliency at fair and reasonable cost; ensuring optimized use of grid assets to minimize total system costs; enabling more customers to engage in energy services; and moving “toward the creation of efficient, cost-effective, accessible grid platforms for new products, new services, and opportunities for adoption of new distributed technologies.” 

Beneath this broad mandate, the IDP framework lays out a comprehensive set of requirements for Xcel, starting with a lot of new data it will need to provide about its distribution grid. The PUC is asking Xcel for 33 separate types of information, ranging from fundamental system data like loading and interconnection data across its substations and feeders, to financial details on its historical and planned spending and investments, as well as critical data about current DER deployment and penetration levels. 

Both IREC and Fresh Energy asked the PUC to add data categories to this list, and some of them were adopted in the IDR framework, Baldwin noted. For example, the PUC adopted IREC’s idea for Xcel to quantify not only utility investments in distribution system upgrades to allow DER interconnection, but also the share of costs borne by customers in that process. 

IREC’s suggestion to break down existing and queued DER interconnection figures by DER technology type, such as solar, energy storage, or a combination of the two, was also adopted. And the PUC adopted Fresh Energy’s proposals for Xcel to report on the number of EVs and public EV charging stations in its territory, as well as data on energy efficiency and demand response capacity across its system. 

But the groups didn’t see all of their data disclosure suggestions adopted by the PUC — at least, not for this iteration of the IDP, Baldwin noted. For example, the IDP requires Xcel to hold a “discussion of how DERs [are] considered in load forecasting and any expected changes in its load forecasting methodology,” but it doesn’t actually require Xcel to disclose the data coming out of its load and DER forecasting, she said. 

That’s a less transparent method than California utilities use in their similar Grid Needs Assessment reports, which list specific data on circuits, she noted. Minnesota’s IDP also doesn’t specifically require utilities to calibrate their forecast data against real-world data to improve their methods over time, as California’s assessment process does, she said. It’s not that the PUC is ignoring these ideas. Instead, “the data provision pieces that we’ve asked for, and the calibration of data, are things they’ll take up in the future.”  

IREC also had some objections to the structuring of the non-wires alternative analysis portion of the IDP, she noted. For example, while it successfully fought to have the cap on the size of distribution projects to be considered for deferral from $5 million to $2 million, it’s still concerned that this cap might well exclude less expensive projects that are nonetheless good candidates for DERs as an alternative. “We don’t know how many projects that excludes,” she said. “It’s an arbitrary threshold. There isn’t any data — or at least we haven’t seen any analysis —– to define how that threshold is set.” 

IREC also feels that the IDP’s relatively short description of what Xcel must include in its non-wires alternatives analysis is lacking in details and metrics that have proven useful in other states, she added. For example, the Minnesota PUC hasn’t ordered Xcel to create a working group of stakeholders to participate in the process, and it hasn’t set up a process by which its findings could be turned into DER procurements, as California has done, according to Baldwin. 

Minnesota’s IDP has also been hampered somewhat by the fact that a key set of data and capabilities it will need — the hosting capacity analysis that Xcel is conducting across its distribution grid — is being done under a legislatively mandated effort. This accident of state policy development has meant that Xcel’s hosting capacity analysis has been proceeding along a separate track from the broader grid modernization effort that has spawned the IDP, and “it’s been a challenge for the last year and a half to two years to make those two pieces synch up a little bit,” Baldwin said. 

Last year, Xcel published its first maps including color-coded hosting capacity across its circuits, from green for those with more than a megawatt of capacity, to red for those that can’t host more DERs without major upgrades. Because much of the IDP is predicated on the goal of improving this process of DER interconnection, the planning framework “was at least intending to start to bridge the gaps between those two efforts,” she said.  

But the PUC chose not to include proposals from IREC and Fresh Energy to bring the current HCA data into the planning discussion, whether in terms of informing its five-year distribution plan or its NWA analysis, choosing instead to keep them within the existing hosting capacity docket. That’s a concern, because “there are questions about whether the methodology they’re using can provide accurate and detailed enough information…not only to help streamline the interconnection process, but to serve a role in planning,” she said. “How that actually comes into play will be more clear as Xcel files its first plan, and in filings thereafter."