As Xcel pushes non-wire alternatives, solar+storage pilot sparks utility ownership debate
Everyone loves that Xcel Minnesota is considering DERs instead of traditional infrastructure, but not that the utility wants to own them itself
In a reversal of typical roles, Xcel Energy wants state regulators’ approval to move ahead quickly on a solar-plus-storage pilot while DER vendors and environmental stakeholders want to slow it down.
Recent filings from the investor-owned utility in its grid modernization proceeding urge regulators to approve special cost recovery from its rate base for building a distributed energy resource (DER) facility at a location in the city of Belle Plaine to defer a traditional substation upgrade.
“Traditional investment for that substation upgrade would have been $6 million and we are asking for recovery for the solar-plus-storage installation of $12.5 million,” Xcel Energy Regional VP Aakash Chandarana told Utility Dive. “But the long term benefits of learning from this pilot would outweigh the slightly higher cost.”
Xcel also wants the Minnesota Public Utilities Commission (MPUC) to approve $27 million for its Advanced Distribution Management System (ADMS), which would add new software and smart capabilities to its Minnesota distribution grid.
The primary benefit Xcel sees in the project “is the ability to defer distribution capital investments associated with overloads,” its filing states, but the utility also expects to learn how solar and battery storage “might allow us to avoid investments down the road and save money for our customers,” Chandarana added.
Filings from other stakeholders in the grid modernization docket applaud Xcel for considering DER investments as an alternative to traditional grid infrastructure, but also raise questions over the regulated utility's plan to own and operate the solar-plus-storage station itself, rather than allowing a third party to do so.
Belle Plaine – the proposal
The City of Belle Plaine’s existing substation will approach its capacity within five years and Xcel plans to up its transmission source from 69 kV to 115 kV.
The utility wants to add a 2 MW, 6 MWh battery and a 1 MW solar array to reduce the load on the feeder and transformer at the location by shifting the load curve so there is “a smaller overload for a shorter length of time,” according to an Xcel filing.
Xcel also wants “to explore the benefits and complexities of storage working in conjunction with a variable generation resource,” it adds.
“Batteries can serve many roles and the much talked about 'blue sky' for battery energy storage will only be realized when we know all its capabilities,” Chandarana said. “With Belle Plaine, we want to learn the roles it can play in our distribution system over the next 15 to 30 years.”
Besides the potential savings, Xcel wants to assess the battery system’s potential to offer:
- Volt/VAR control by optimizing feeder voltage and reactive power flow;
- Transmission and Distribution system loss impacts analysis;
- Regulation services to MISO and other grid operator’s markets;
- The ability to protect customer loads by mitigating short duration power quality events, such as voltage sags;
- Smoothing to variable DERs, specifically PV, to reduce voltage fluctuations, increase feeder DER hosting capacity, and minimize maintenance costs for voltage regulation equipment.
“Recent studies on energy storage have supported the importance of capturing more than one value stream for projects to be economically feasible,” the filing adds. “We intend to learn about complex interactions and limitations involved with stacking multiple battery systems.”
The proposed pilot would also offer “the learning that comes from a Minnesota-specific deployment,” the filing notes. “It is essential that we learn how best to integrate and leverage storage technologies before costs drop to the level where adoption becomes more widespread…[and] start now to build the in-house capabilities and knowledge necessary to effectively benefit from this technology.”
With DERs, Chandarana said, “the dialogue isn’t as black and white as it used to be when it was just about the least cost widget, but it is a dialogue our commission in Minnesota, which is fairly progressive, understands and sees benefit in.”
Stakeholders in regulatory docket — including the Energy Freedom Coalition of America (EFCA), a group led and co-founded by leading rooftop solar installer SolarCity — have few objections to the ADMS smart software undertaking, and appreciate Xcel's efforts in pursuing non-wire alternatives.
DER advocates say this kind of non-wire alternative (NWA) to traditional utility infrastructure investment, typified by the landmark Brooklyn Queen Demand Management Program, can lead to ratepayer savings and grid benefits. Spurred by New York’s Revising the Energy Vision regulatory and policy proceeding, Consolidated Edison used a $250 million investment in DERs to defer a $1.1 billion substation upgrade.
A recent grid modernization study from SolarCity argued on behalf of just this type of investment. DERs “can offer deferral and avoidance of planned grid investments…[and] if deployed effectively and placed on equal footing in the planning process with traditional grid investments, can ultimately lead to increased net benefits for ratepayers.”
“It absolutely is important that Xcel is looking at this idea because step one is not investing in traditional wires-based solutions and looking at alternatives like storage,” said SolarCity Policy and Energy Markets VP Becky Stanfield on behalf of proceeding intervenor EFCA.
Surprisingly, though, EFCA’s final proceeding filing recommended that the Commission reject Xcel’s project. The reason for this opposition captures the newest tension between utilities and DER providers in the state.
“Step two,” Stanfield said, “is can they get even more savings by opening the market to private parties to bid in to solve the problem even more cost-effectively?”
EFCA's issues with the project
Xcel is offered the option for the special cost recovery for DERs by legislatively-mandated grid modernization effort, but because that recovery has to go through a regulatory proceeding, it offers stakeholders insight and a voice in the utility's grid modernization planning.
All the stakeholders’ comments, including Xcel’s, recognized the core of the proceeding is modernizing Minnesota’s grid, EFCA noted in its filing.
Where stakeholders differ is who should own and operate the project. Xcel proposes to own the Belle Plaine project itself, arguing that it can learn more about how to deploy and manage DERs like solar and storage if it owns the project itself.
DER providers, led by EFCA, say an open bidding process that allows for third parties to compete for ownership and operation rights will deliver more benefits to the grid at a lower cost, and that allowing utility ownership for this project could set a dangerous precedent for projects to come.
“Innovation can be more rapid and diverse in a competitive market,” EFCA argued. “The proposed project—which includes utility ownership of each component—will likely be more cost-effective and beneficial if it leverages the competitive market.”
A competitive bidding process “could result in a broader set of options, including technologies and ownership models, beyond the limited scenarios Xcel considered,” it added.
The Hawaiian Electric Companies and PSEG Long Island are among utilities calling for private sector bids to best use DERs to defer traditional infrastructure investments, EFCA said. The California Public Utilities Commission launched a DER proceeding intended “to transform grid-edge values into utilities' sourcing policies.”
Unless Xcel modifies its proposal to include a detailed call for competitive bidding, the commission should deny it, ECFA argued.
If private sector vendors "cannot put forward cost-effective options, Xcel’s utility ownership model would be an acceptable approach. However, it should be the exception rather than the norm…[and] rather than approving Xcel’s project as-is, Xcel be required to bid out the grid services it requires in a competitive solicitation.”
Xcel’s proposal limits what can be learned, Stanfield said. “If there was a range of pilots and some were utility-owned and some were intended to be competitively bid, we would be having a very different discussion right now because the outcome of that range of pilots might show something really important about the benefits of competition.”
Better understanding solar plus storage is important but Xcel’s pilot could do more, according to a joint filing from Fresh Energy and Minnesota for Environmental Advocacy (MCEA).
Xcel should more completely determine the benefits and costs of the Belle Plaine project and develop a methodology for assessing the value of future DER deployments, it argues.
The utility should also include in its cost-benefit analysis targeted energy efficiency, demand response, other load control technologies, and end-use measures, the joint filing said. It should assess how such measures could further reduce peak demand at the Belle Plaine demonstration feeder and further defer infrastructure investments.
Finally, Xcel should deploy and assess the value of advanced smart inverters to accomplish its end goals.
Xcel's response to the third party option
“Bringing in third parties is part of a much bigger conversation about whether we are a regulated state or a market and deregulated state,” Xcel's Chandarana said.
He didn’t rule out third party participation but said it requires a conversation that will take time, as it has in California and New York.
EFCA, as the representative of DER providers, is pushing Minnesota “headlong onto a similar path,” Xcel’s filing argues. “We believe that grid modernization efforts in Minnesota should be done in a way consistent with the State’s regulatory paradigm and that the vertically integrated utility model is fully compatible with the modernization of the distribution system."
There is "insufficient experience" with third-party DER deployment models in Minnesota, the filing argues, saying that the company is "concerned that under the third-party provider model advocated by EFCA, a provider of grid services is not directly accountable to the Commission and the utility is reliant on the performance of the third-party provider to maintain reliability of the distribution grid.”
The Belle Plaine pilot would give Xcel the understanding of DERs it needs “to appropriately assess the provision of this service by third parties behind the meter, let alone in support of the distribution system.”
This utility ownership strategy is how Xcel became a national leader in wind-generated electricity, Chandarana said. About half its wind now is company-owned and about half comes from independent power producers through competitively bid projects.
“We learned about wind and how to integrate it into our grid before we brought in third parties,” he said. “When we then evaluated and negotiated third party bids, we were able to get good prices and projects for our customers.”
Unlike generation, the distribution system “is the direct connection between us and our customers,” Chandarana said. “Reliability and customer and worker safety depend on it.”
What EFCA thinks about utility ownership
To avoid “anti-competitive concerns,” EFCA argues in its filing, oversight is “critical" and “non-utility ownership should always be considered.”
The commission must ensure that “utilities do not use their monopoly power to manipulate or restrict competitive industries...[because] competition both puts downward pressure on costs, and creates more choices and opportunities for customers,” it argues.
Utilities are “notoriously slow” at innovation because they tend to not invest adequately in research and development, EFCA said in its filing. Leaving the advance of DERs to utilities would therefore “risk creating stranded assets and higher costs … [and] ultimately limit utilities’ options in the marketplace by allowing them to pick winners and losers.”
The common thread in the filings of EFCA, Fresh Energy, MCEA, and other stakeholders is that the commission does not have adequate information to approval Xcel’s request for cost recovery.
“We agree with the Department of Commerce, the Attorney General, and other parties who suggested it would be better to wait until rules are established,” Stanfield said. “That would most likely be in a rulemaking in the grid modernization docket. That is where standards and the need for competitive bidding should be established.”
“The commission will evaluate all the proposals and decide if there is sufficient record for the projects to be certified,” said MPUC Director of Policy Chris Villarreal.
Delay on the horizon?
Despite uncertainty on the need for competitive bidding, “no rulemaking is necessary and the commission should move forward on certification of our projects,” Chandarana said.
In the face of technological, market, and policy changes, the Xcel filing argues, “one option is to pause until all questions can be answered, plans finalized, and dockets concluded.”
Because this would also delay the non-controversial ADMS project, this risks “missed opportunities, delayed progress on grid modernization and other efforts, and creation of a static set of rules that are slow or fail to adapt to ongoing change,” the Xel filing argues.
The other option, Xcel adds, is to move forward with "the best available information” and “learn and adapt” with experience.
“Rulemakings in the state of Minnesota can take two to three years and certifying a project and allowing rate recovery has often been done without significant rulemakings,” Chandarana said.
A rulemaking may also fail to clarify cost recovery questions and other key questions. “If we move on this now,” Chandarana added, “we have the benefit of deploying technology at the speed of value and the speed of value means our customers get the benefit.”
“In the case of any proposed project, we may like it but there has to be reason in the record for it to be certified,” the MPUC’s Villarreal said. “In this case, the commission will have to decide whether there is enough information to warrant certification.”