By - Jim Vess

Minnesota is adopting a methodical approach to grid modernization

Energize Weekly, July 5, 2017

Minnesota—unhampered by the pressures facing some other states—is taking a step-by-step approach in planning and developing a smart grid, one that could be a template for others.

The biggest initiatives in grid modernization are in states like New York, where in the wake of Hurricane Sandy there were serious reliability issues, or California and Hawaii, which face the challenge of managing burgeoning renewable generation.

Minnesota has had neither reliability nor distributed renewable generation issues. What it has had is an ongoing planning process both at the Minnesota Public Utilities Commission (PUC) and through non-governmental stakeholder groups.

“We are taking on this issue of modernizing the grid stepwise and at an orderly pace, and looking at customer value,” said Mike Bull, policy director for the Center for Energy and Environment (CEE), a Minneapolis non-profit focusing on energy efficiency programs. “We don’t have a crisis and are not under pressure… We are taking our time to get it right.”

Bria Shea, director of regulatory strategy and analysis for Xcel Energy, the state’s biggest utility, agreed. “Hawaii and California have been forced onto their paths. In Minnesota, we have a long runway.”

Minnesota’s runway started in December 2014 when the e21 Initiative, a stakeholder collaboration created by CEE and the Great Plains Institute, issued a white paper calling for a grid modernization process for the state.

In May 2015, the state legislature passed a grid modernization statute that required utilities under multiyear rate plans (Xcel) to identify inadequacies in the transmission system and investments necessary to modernize it. The utility was to file a report every two years.

The Minnesota PUC set up a docket for the statute, and Xcel filed its first report in November 2015 proposing to add a $27 million investment for an “advanced distribution management system” (ADMS) software platform that would enable quicker responses in handling outages and peak demand.

The utility also proposed a $12.5 million storage+solar pilot project in place of upgrading a new substation.

The PUC approved the ADMS system, but rejected the solar+storage pilot. “It was an interesting project, but not absolutely necessary,” Xcel’s Shea said. It was also twice the price of a traditional substation upgrade. “At the end of the day, they wanted more information, more data than we gave them,” she said. The next biannual report is due this November.

In March 2016, the PUC staff, at the commission’s request, issued a white paper outlining key priorities in grid modernization. The report came out after a series of stakeholder meetings.

Those priorities were to:

  • Maintain and improve the grid’s safety, security, reliability, and resilience at fair and reasonable costs in accordance with Minnesota’s energy policies
  • Enable and empower customers and energy options
  • Move toward efficient, cost-effective, accessible platforms for new products, new services and new opportunities for distributed technologies
  • Optimize grid asset use and minimize costs
  • Open up comprehensive, coordinated, transparent, integrated distribution system planning

The PUC has opened two other dockets addressing elements of grid modernization: an alternative-rate design docket and a docket on how distribution system planning should be done.

“Our key concern is bringing transparency to distribution planning,” said Allen Gleckner, director of energy markets at Fresh Energy, a non-profit promoting clean energy options. “The need is coming from the technology side. We are seeing a lot more opportunities to innovate on the distribution system.”

Fresh Energy and the Interstate Renewable Electric Council have also proposed the PUC update the state’s interconnection standards, which were last revised in 2004. This would help add distributed renewable generation to the grid.

Under the rate docket, Xcel is preparing a proposal for a pilot using time-of-use rates (TOU), which vary depending upon the demand for electricity on the system, Shea said.

“We’ve been working with groups on new customer rates,” Shea said. “We are going to propose a pilot in our November filling.”

Implementing TOU rates requires so-called smart meters or advanced metering infrastructure (AMI), which can record customer use in real time. “We think we are moving in the direction of time-of-use rates, and there will need to be some infrastructure investments,” Gleckner said. “The two are tied together.”

Xcel has worked on its PUC proposal with an e21 stakeholder group, including the state Department of Commerce, the state attorney general, Citizens Utility Board of Minnesota, Fresh Energy, Great Plains Institute, CEE and the Minnesota Chamber of Commerce.

“An e21 principal to the extent possible, it is good to get stakeholder input into a docket before it is filed,” Bull said. “We do the early work to round off the edges, and identify the areas for significant agreement and significant disagreement.”

Bull said that part of the issue with the solar+storage pilot the PUC rejected may have been that there hadn’t been that early stakeholder input, but that in general, the practice works.

“We have a very collaborative process,” said Shea. “Having stakeholder work groups help get everybody on the same page… It is nice to be able to do it before we go to the commission.”

In December 2016, Xcel filed a required report with the PUC on how much distributed solar its system could accommodate by analyzing more than 1,000 feeders in Minnesota. In its report, Xcel said more work needs to be done to refine the model.

The Institute for Local Self-Reliance, a Minneapolis-based non-profit focused on community-based approaches to energy and environmental issues, calculated that the Xcel hosting analysis indicated that 1,851 megawatts of solar could be added to the utility’s system.

But the institute still found the report limited, and called upon Xcel and the PUC to “do more to flesh out the analysis.”

“We’d like to move toward the California approach of mapping distribution capacity,” said John Farrell, director of the institute’s Energy Democracy initiative.

The e21 Initiative also issued its second white paper in December covering topics including integrated systems planning, grid modernization and performance-based regulation.

In the grid modernization section, e21 attempted to lay out a planning process, fundamental technologies required (such as AMI, smart inverters, storage and distributed generation management systems) and operational goals (such as system transparency, dynamic voltage control and load management).

“We are now moving into projects and proposals that will take us out of the white paper phase and move us into action,” Bull said.

For its part, Xcel is laying “building blocks for the future,” Shea said. These blocks include refining the basic supervisory control and data acquisition system (SCADA) used by the utility, developing its database management system (DBMS).

Then there is the refining the hosting capacity figures and developing the TOU rate proposal.

“By that measured approach, we can keep pace with technology while preserving flexibility to adapt and meet customer needs,” Shea said. “It is a long-term effort … how long depends on technology, customers and the commission.”

The process could create an approach to planning, rate development and infrastructure development that could be a model. “We are still early,” said Gleckner. “We are ahead of the curve from a lot of people who are putting their heads in the sand saying the industry isn’t changing.

“These things take a while, they are complicated so we are early in planning and setting up processes that are durable to take advantage of technological advances and experiences from states further along the curve,” he said.

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