by Jeff St. John
December 05, 2019

Last year, we covered Xcel Energy’s work on a Minnesota regulatory mandate, called an integrated distribution plan, to incorporate solar PV, batteries and other distributed energy resources into its future grid investment plans. 

We also highlighted how Minnesota’s approach differs from states such as California, Hawaii, New York, Massachusetts and Nevada that are taking on similar challenges — largely because, unlike most of those states, Minnesota doesn’t have many DERs deployed yet. 

Early last month, Xcel submitted a set of plans to the Minnesota Public Utilities Commission that highlights its unique Midwestern imperatives. The filing includes its formal integrated distribution plan (IDP), a 10-year guide for merging customer-owned and -operated DERs into its distribution grid investments and operations. 

But the majority of the 300+ pages are focused on a grid modernization rate case, asking the PUC for permission to charge customers for hundreds of millions of dollars of investments in smart meters, communications networks, self-healing circuits, volt/VAR optimization and other technologies over the coming three to five years. 

This focus on grid investments makes sense for a utility that hasn’t yet deployed smart meters, advanced grid management software or other important tools for connecting, monitoring or managing DERs at scale. It also matches Minnesota’s relatively slower pace of DER adoption. 

Compared to other utilities in other states pushing for DER-grid integration, “we are not currently undergoing sizable additions of DER[s] on our system,” Xcel wrote. That means that, rather than playing catch-up to disruptions from DERs, as is happening in states like Hawaii and California, Xcel can "take a measured approach and pace to [the] IDP that allows the requirements to be implemented in a cost-effective, systematic manner.” 

That doesn’t mean that Xcel isn’t supporting DERs through traditional means, the filing notes. The utility has 824 megawatts of demand response under contract and expects to add 400 megawatts more by 2023, making up one of the largest portfolios within the footprint of Midwest grid operator MISO. What's more, its community solar gardens program has brought 585 megawatts of projects online and is expected to grow to 650 megawatts by year’s end. 

Other DERs are less prevalent but are showing some growth. Over the past year, distributed solar outside the community solar program doubled to roughly 86 megawatts, distributed wind quadrupled to 16 megawatts, and the number of distributed storage projects seeking interconnection jumped from six to 35. Xcel has several electric vehicle pilot projects underway, ranging from public transit fleets to home EV services. 

Foundational grid investments 

What Xcel doesn’t have right now are the smart meters, grid sensors, communications networks and back-office software and systems to enable the kind of DER-grid integration envisioned in the IDP. These are the technologies at the heart of its Advanced Grid Intelligence and Security (AGIS) initiative, the multi-year, multi-hundred-million-dollar investment plan that Xcel is asking the PUC to approve along with its IDP filing. 

Xcel broke out spending projections across different technology categories for three-year, five-year and 10-year periods, in keeping with the multiple timeframes of its rate case, its AGIS initiative and its IDP. Most of it — about $275 million through 2023 and another $205 million through 2029 — will be spent on advanced metering infrastructure and field area networks to replace Xcel’s current system for its 1.5 million customers. 

Xcel has only installed about 17,500 smart meters so far, part of a time-of-use pricing pilot in the Minneapolis-St. Paul area. But by 2024, it plans to have them deployed for all its customers, providing “granular energy usage data” to support efficiency programs and offerings, rate plans and options, and other services. 

Today’s smart meters, unlike California’s last-decade models, also come with enough bandwidth and processing power to serve as nodes for communicating with in-home devices, smartphones, Wi-Fi routers and other parts of the digital home ecosystem. 

Other parts of Xcel’s AGIS plan are more grid-facing. Over the next 10 years, it plans to spend about $67 million on fault location, isolation and service restoration deployments to improve grid reliability during storms, plus about $35 million on an integrated volt/VAR optimization system to save energy by lowering grid voltages without threatening power quality. 

As for the control systems to coordinate these new technologies, Xcel is nearing completion of a multi-year advanced distribution management system (ADMS) upgrade that is expected to go live in early 2020. The ADMS “will provide the visibility and control necessary for enhanced planning and significant DER integration,” by serving as a single frame of reference for a multitude of distribution grid operations, down to the smart meters at the edges of the grid.

A tool for DER integration

Compared to its big-ticket grid deployments, software upgrades are relatively low in cost — Xcel expects to spend about $18 million on its ADMS implementation over the next five years.

It’s also planning to spend $9.3 million next year for advanced planning tool (APT) software to assist in the complex task of integrating DERs into its long-range grid plans.

Utilities have been struggling to adopt new approaches to distribution system planning that can accurately measure the future impact of DERs, largely because until recent years there wasn’t a market for such tools. We’ve covered some of the companies working in this relatively rarefied field of utility planning software, such as Willdan Group’s Integral AnalyticsSmarter Grid SolutionsOpus One Solutions and Spirae, to name a few. 

Xcel’s filing didn’t name the vendor for the APT it’s planning to buy, but it did provide a detailed description of the set of needs it’s seeking to solve by buying it. The growth of solar PV, plug-in EVs, behind-the-meter batteries and other DERs has made “granular load forecasting a much more complex and important undertaking than it was only a few years ago,” the utility notes in the document.

Xcel’s current planning software, which soon will no longer be supported, can’t manage the hosting capacity analyses, DER and load forecasts, and other work the PUC has ordered Xcel to conduct as part of its IDP. The APT software, by contrast, will grant the utility's "system planners...enhanced capabilities to consider DER adoption scenarios and non-wires alternatives,” both of which are important parts of the DER-grid integration efforts underway in other states. 

Taking all factors into consideration, Xcel’s filing for Minnesota’s IDP doesn’t go nearly as far as similar efforts in California and New York, in terms of calling for radical transformations of how DERs are valued as part of the utility distribution grid. 

For example, Xcel’s plans for Minnesota don’t yet include using DERs as non-wires alternatives to grid investments. “We clarify that we do not have any specific non-traditional distribution projects in our 5-year budget,” Xcel states in the document, citing a lack of distribution projects that fit the bill for cost-effective DER deferral.

Wood Mackenzie Power & Renewables analyst Francesco Menonna said no other Minnesota utility has suggested a non-wires alternatives project in its IDP filings so far, either.  

Likewise, while California, New York, Hawaii and other states have pushed utilities to deliver more detailed hosting capacity analyses of their distribution circuits and forecast the adoption of DERs for their long-term grid edge impacts, Xcel’s filing states that much of this work is just beginning in Minnesota.

Xcel published its first hosting capacity maps last year and is under PUC order to make “enhanced load and DER forecasting capabilities” and “updating of actual feeder daytime minimum loads” a priority for this year.

Of course, even the most ambitious states haven’t seen anything like a smooth rollout of their plans to integrate DERs into utility investments, as we’ve observed in our ongoing coverage of California’s Distribution Resources Plan proceeding, New York’s Reforming the Energy Vision initiative or Hawaii’s Integrated Grid Planning effort.

As Xcel lays out in its filing, it’s hard for utilities and regulators to forecast the pace of widespread DER adoption when the tools and methods they’ve relied on for decades no longer apply.