When most power sector insiders consider U.S. grid modernization initiatives, their thoughts naturally float to the coasts. Initiatives to optimize the grid and reform distribution system operations have captured the industry's imagination in places like California and New York.
But a new regulatory report released recently shows there's action on grid modernization in the middle of the country as well — this time, in Minnesota.
The report is a summary of a series of multi-stakeholder workshops that were part of a regulatory proceeding on grid modernization. It engaged Minnesota’s utilities, regulators, renewables providers, technology vendors, and environmental and consumer advocates.
The “Minnesota Public Utility Commission Staff Report on Grid Modernization” lays out the points of agreement and contention between the Minnesota groups and may point the way toward a twenty-first century grid for other states with vertically-integrated utilities.
“The report is what we heard about the current capabilities of Minnesota’s distribution system, the future capabilities of a modernized grid, and the kinds of technology and policy choices that regulators, utilities, third party providers, and customers will have to make to build it,” Commissioner Nancy Lange, who is leading the Minnesota Public Utilities Commission (PUC) grid modernization docket, told Utility Dive.
In a vertically-integrated state, where utilities own the generation, transmission and distribution assets, creating opportunity on the grid for that range of stakeholders is a special challenge, added Beth Soholt, co-chair of the e21 Initiative and director at advocacy group Wind on the Wires.
With the exception of Minnesota, other states that have taken on ratemaking and distribution system reforms have all been deregulated, with utilities divested from generation assets.
“Utilities need new rate designs and/or incentives that make them agnostic to who provides the service,” Soholt said. “The big question is how fast that can happen because there is a long chain of policy and proceedings, as the report lays out, that have to be worked through.”
Grid modernization priorities
The report, authored by staff the PUC and released last month, outlines five key priorities for grid modernization in the state:
- Maintain and improve the grid’s safety, security, reliability, and resilience at fair and reasonable costs and 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.
Because of the many complicated issues that need to be resolved, the three-phase framework set up in the report will help set priorities. The first of the three phases is the adoption of definitions and principles.
The second phase is the considering and prioritizing of the many potential issues. They include integrated distribution planning, interconnection standards, rate design, and dealing with new technologies like smart inverters and new market potentials like third party aggregation of distributed energy resources (DERs).
The third phase is developing a long term vision of a modern grid and includes new utility business and regulatory paradigms and advanced rate concepts.
Some participants weren’t certain the PUC staff got the phases exactly right.
“There are things in the long term category that might come up in the near term," Erica McConnell, special counsel at the Interstate Renewable Energy Council, told Utility Dive.
Conceptualizing a new utility business model is in the third phase, but “the fundamental incentives utilities have in the current business model make it hard to accomplish some of the action items,” she said.
The principles include encouraging customer choice and encouraging the integration of DERs, she added. “If utilities’ incentives are to build things to recover costs and get a guaranteed profit on, it is not likely they will be eager to go for the proposed goals.”
One second-phase issue and third-phase question has already become a conflict in a current commission proceeding, she noted.
As Utility Dive reported last month, conflict emerged between Xcel Energy and DER providers when the utility asked regulators to approve a solar and energy storage pilot project at its Belle Plaine substation. The Energy Freedom Coalition of America (EFCA), an advocacy group representing leading rooftop solar installer SolarCity and other DER companies, argued the utility was not allowing adequate access to third party vendors.
Xcel declined interview requests on this piece, but in March a regional vice president told Utility Dive the pilot project would allow the utility how to learn how to better operate distributed resources on the system, critical for any future involvement of third party DERs.
“The role of third parties is closely related to the utility business model," IREC's McConnell said. "There will be tension when the goal is to encourage competitive markets because the utilities' incentives don't align with that. The commission doesn't have to develop a blanket policy right away but they will have to at least face it in a piecemeal fashion.”
Everybody says it’s time for new rate designs
In building a 21st century energy system that is cleaner and allows for a larger array of distributed resources, addressing Minnesota's antiquated rate structure will be critical, the report and stakeholders agree.
“The plain vanilla rate design is not going to serve us well into the future," Lange said.
Minnesota customers “pay the same price for energy no matter what time of the day they use it or how much they use,” said Holly Lahd, electricity markets director at Fresh Energy, a clean energy policy group and intervenor in the grid modernization proceeding.
“We have the technology to engage customers on their side of the meter, but we need the rates to enable it," she said.
The Staff report elaborates on Lahd's point: “Because customers pay the same rate regardless of the underlying price of producing the electricity, they have no financial incentive to shift their consumption from more- to less-expensive periods."
“In order to send customers more accurate price signals — and ultimately reduce system costs — many utilities have moved to time-varying pricing," the report notes.
The are many different types of time-varying pricing include time-of-use (TOU) rates, critical peak pricing, peak time rebates and real time pricing, the PUC staff notes in the report. All aim to reduce peak demand on the system, make it more efficient, and open opportunity for innovation from efficiency, storage and demand response providers.
A full range of environmental and new technology advocates in the proceeding endorsed time-varying rates, staff reports.
Xcel Energy, an investor-owned utility in the state, also "seemed amenable to the concept," the report ntoes, "positing the policy objective of sending ‘more accurate price signals to incent efficient customer behaviors and align rates with cost drivers on the system.’”
Though Xcel declined to be interviewed, at least one electric cooperative is on board with the concept of time varying pricing. Doug Larson, regulatory services vice president at the Dakota Electric Association, agreed with the PUC staff's point.
“There are better ways of pricing electricity than what we have right now,” he said. “But new rate design will be a very heavy lift.”
The rural electric cooperative has had “extremely low participation” in its TOU offering, Larson said. “Even though we promote TOU rates, people are not familiar with them and they are reluctant to participate.”
Dakota Electric customers have, however, allowed it to reduce its summer peak load 25% through load management rates. They give customers a price reduction for turning limited control of specific end uses over to the utility during peak demand periods, Larson said.
“We need both TOU rates and load management methods,” he said.
An investigation of five proposed alternative rate designs, including TOU and CPP, is part of Xcel Energy’s current rate case and “it is likely that much of the discussion will be relevant to other utilities and customer classes,” staff added in the report.
Lange agreed, saying that technologies that give customers and utilities more information about energy usage should new rate design opportunities. But, she said, those must be tempered by rate structures that are “just and reasonable and non-discriminatory and accomplish the public interest."
Do interconnection standards need fixing?
There is less agreement about Minnesota’s 110 page interconnection standard. It was formulated between 2002 and 2004 and has not been significantly updated since. Its limitations were revealed in the controversy that emerged in 2015 between Xcel Energy and community solar developers over how much solar could come onto the grid at any one site, according to Lahd.
“The community solar experience was the first stress test of the interconnection standards and it showed we need to reform them,” she said.
Fresh Energy, the Interstate Renewable Energy Council (IREC), and The Alliance for Solar Choice (TASC) were among the stakeholders who argued for a new proceeding on interconnection, regulatory staff reports.
IREC proposed a review of best practices. TASC wanted a streamlined interconnection process, more access to basic grid data, and more developer involvement, staff added. “Without this collaboration, TASC argued, the utility may prefer an overly conservative, and ultimately more costly, remediation.”
Minnesota Power, another IOU in the state, pushed back, arguing that safe interconnection is not a matter of "plug and play" and requires analysis to avoid unintended consequences for customers, according to the staff report.
Dakota Electric, for its part, has found the current interconnection standards "work very well and have been very useful," Larson told Utility Dive.
Before 2004, “each utility had its own process and developers with qualifying facilities [under PURPA] were frustrated because the rules of the road were not consistent," he said. "The current higher level of consistency helps the marketplace.”
Refinements, he acknowledged, could be made. “We can do some immediate things with a limited scope. Other changes should wait until ongoing work by the Institute of Electrical and Electronics Engineers is complete.”
The regulatory staff report proposes consideration of new rules for smart inverters and new national codes and standards for distributed generation. Echoing Larson, it warns that a full reconsideration would require an extensive proceeding.
“We heard the interconnection standards need updating and the commission is well aware of it," Lange said. “We see work on the interconnection standards running in a separate and parallel track.”
Interconnection standards "rise to the top of the many issues the report shows need attention,” Lange added. “But the fact that we will have a docket on interconnection standards doesn’t mean we can’t do this grid modernization process. We need to deal with them both.”
Next up: Distribution system planning
Conflicts often emerge in the interconnection process when the penetration of DERs rises, IREC's McConnell said.
“Utilities get applications, they process them, but they are not planning proactively," she said.
Similarly, the need for innovative rate designs and effective price signals becomes more pressing when DER penetrations rise and utilities have not adequately planned to manage them, McConnell said. “The Minnesota Staff report calls for that kind of planning.”
At the most recent grid modernization stakeholder meeting, Lange recommended that the next step in the grid modernization proceeding should be “a deeper dive into integrated distribution system planning," such as the California IOUs are doing today.
Minnesota has "a robust integrated resource planning framework and a robust transmission planning framework," Lange said. “This next phase will be building a framework to conduct integrated distribution system planning.”
The elements of that framework will include an assessment of distribution system capabilities, where to locate DERs, what costs and benefits they offer, and future growth scenarios, Lange believes.
The utilities in the stakeholder group were particularly helpful in laying the groundwork for the distribution system planning process she would like to see, the commissioner said said.
“We have minimal visibility into our distribution system,” she explained. “It was very important to have the utilities describe in detail the variety of their systems, the kinds of investments they are planning, the kinds of planning tools they use, and the kinds of planning tools they need.”
Grid modernization in a vertically-integrated state
Among the many questions to which the staff report does not offer answers is the role of third party aggregators, Wind on the Wires' Soholt pointed out. That highlights the difficulties of distribution system planning with vertically integrated utilities.
As DER penetrations climb, pushing electricity sales down, and private sector vendors pursue more customer information, utilities are likely to consider partnerships with the third party providers for DER deployment and aggregation, she said. The question will be whether that is the path to least-cost DERs and a least-cost future distribution system.
Given the major investments needed transition Minnesota's grid and generation fleet, cost effectiveness will become increasingly important, Soholt said.
“The report lays out an action plan for utilities but if they do those things, will they be making the most cost-effective investments?” she asked. “If they spend a little more or a little differently, could they stretch the dollars that have to be spent anyway or get some new capability from the grid?”
It may be complicated to get the answers to those questions from vertically integrated utilities unused to disclosure of proprietary information, Soholt believes. Xcel’s reluctance to work with vendors on the Belle Plaine project demonstrated that.
“Xcel wants to offer what customers want, but they want to make the offerings through the utility instead of letting providers come into its service territory and take its customers,” she said.
Other states are considering distribution system operators and opening up to competition, she added. “The Minnesota utilities are struggling with how to get there.”
Dakota Electric's Larson acknowledged that point.
“The proposed change in the utility business model is a long term vision,” he said. “We will have to figure out how that long term vision can integrate with our cooperative business model.”
Being a vertically-integrated, fully-regulated state may, however, give Minnesota regulators a head start on developing distribution system planning, Lange said.
“In integrated resource planning, we get a comprehensive look at all the resources on the table,” she said. “The information is not as granular as it would be in integrated distribution system planning but it gives the commission insight into how distributed resources come into play.”
Minnesota’s work could lead the way on distribution system planning in vertically integrated states, Lange said.
“We will find out if we can make that work here," she said. "Maybe the best answer is stay tuned.”