ORIGINAL REPORTING: Inside Minnesota's disputed community solar deal

Inside Minnesota's disputed community solar deal; Did Xcel Energy divide and conquer solar developers or did developers do it to themselves?

Herman K. Trabish, July 9, 2015 (Utility Dive)

Advocates for the community solar sector are breathing a sigh of relief over a decision from Minnesota’s regulators – but potentially market-disrupting questions remain.

The Minnesota Public Utilities Commission gave preliminary approval late last month to a settlement between Xcel Energy and a small and not necessarily representative group of solar developers. That deal aims to settle disputes about the size and placement of community solar arrays, limiting them to 5 MW of capacity immediately, and decreasing the cap to 1 MW of capacity in September of this year.

Solar advocates expect this settlement to kick-start development of community shared solar in the state with the nation’s biggest installed capacity potential. National attention has been focused on the settlement since leading sector analyst GTM Research called community solar the country’s “next largest solar growth market” and named Minnesota the “swing state” in it.

“The settlement works for us,” said SunShare CEO David Amster-Olzewski. “The utility could have gotten lower prices for customers by allowing 10 MW co-located solar farms. You get more economies of scale and that reduces prices for the end customer. But overall Minnesota will still have one of the largest community solar markets in the country.”

The partial settlement

The agreement approved by the commission for docket 13-867 is expected to break an impasse on project approvals at Xcel and help construction begin on at least a small portion of the over 1 GW of applications the utility reports in its queue.

The key aspects of the “partial settlement” are:

-Co-located projects with pending applications will be sized to not exceed 5 aggregated MW

-The previously-approved applicable retail rate (ARR) for community solar gardens remains unchanged

-Developers agree to take the distribution system “as is” except to accommodate interconnection upgrades

-Xcel Energy committed to more transparency and expediency in its interconnection processes

-Starting September 25, 2015, co-located projects may only be 1 MW

-The stakeholders will accept Commission guidance and oversight on program price, size, land use, etc.

Xcel Energy, through subsidiary Northern States Power, accepted these terms, as did developers MN Community Solar, Novel Energy Solutions, Renewable Energy Partners, SolarStone Partners, Sundial Solar, and TruNorth Solar.

Calculations passed on by the clean energy think tank Fresh Energy and by Amster-Olzewski, and based on data from Xcel and other sources, suggested the developers acceding to the settlement may represent as much as 17% of project applications. Those who did not sign on represent the bulk of the balance.

Despite the CEO's supportive comments, SunShare did not sign on to the settlement. Neither did the other members of the Solar Garden Community, the ad hoc alliance of community solar developers formed to push back against the agreement.

Those developers are BHE Renewables, the newly acquired development arm of Warren Buffett’s Berkshire Hathaway Energy, SoCore Energy, SunEdison, the biggest renewables developer in the world, and Sunrise Energy Ventures,which just partnered with U.S. leading residential solar developer SolarCity.

Other intervenors in the commission proceeding who declined to sign on to the settlement it produced were the Minnesota Department of Commerce(DOC), a ratepayer advocate, and renewables advocacy group Fresh Energy.

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How the settlement happened

Minnesota community solar has been in limbo most of this year because Xcel has not been processing applications. Its resistance to co-located projects of greater than 1 MW collided with developers’ insistence the state’s community solar act allowed much larger arrays.

Fresh Energy, the DOC, and others convened stakeholders to find a compromise. There was, and remains, an urgency to negotiations because projects need to be online in time to qualify for the 30% federal investment tax credit (ITC). It drops to 10% on January 1, 2017.

Though Xcel opened the application process with all developers on a level playing field, the effort to bring all of them into the settlement broke down, according to DOC Deputy Commissioner Bill Grant. Developers who already had larger projects in the queue thought they would be significantly disadvantaged by a cap lower than 10 MW while smaller developers who got applications in later were concerned the larger projects limited room for them in the queue.

But with all stakeholders concerned the distribution system might not be able to accommodate the volume Xcel reported, “some sorting out is going to happen based on that limit and their position in the queue will determine whether they live or die,” Grant told commissioners. “We don’t know how real the limits that would block smaller developers are.”

Large solar projects generally have economies of scale that benefit all utility customers equally, Xcel Energy VP Laura McCarten explained to Utility Dive. But, she said, “only a small subset of our customers” subscribe to community solar projects. And the cost to the utility of such arrays’ output is set by policy at a higher rate than other utility-scale projects, even if co-located projects achieve greater scale.

“A 10 MW cap would lead to rate increases for our customers of close to 3%," MCarten said. "With a 5 MW cap, the rate increase would be about 2%."

Minnesota’s legislators limited the size of community solar arrays because they were aware “large scale solar energy projects secured through a competitive sourcing process provide our customers with energy at about half the cost of solar gardens,” McCarten added. “It’s important to customers thatthe solar garden program be right sized, in line with legislative intent.”

“In the end, Xcel was able to pit developers with larger projects against those with smaller projects and bring this partial settlement to the commission,” said Fresh Energy Electricity Markets Director Holly Lahd.

The commission considers the settlement

Despite two days of hearings, the commissioners wondered aloud as to whether they were adequately informed on the question of whether to cap co-located projects at 5 MW or 10 MW. Chair Beverly Jones Heydinger called a 10 minute break before the vote “to confer with staff” on the adequacy of their information.

When they returned, Commissioner Nancy Lange reluctantly moved to accept the partial settlement and the 5 MW cap as a way to move community solar forward and because it would protect ratepayers.

Commissioner Dan Lipshultz agreed the settlement seemed in the public’s interest and would likely produce “a pretty healthy number of community solar gardens” but, he added, “we certainly will have the opportunity to revisit the cap.”

“I sense we will be back here with the co-location issues,” said Commissioner John Tuma in voting to accept the settlement. He complained that important information on rate and cap impacts came in too late for commissioners and staff to fully digest its implications. But, he said, “I am comfortable erring on the side of putting protections in the ratepayers’ interest.”

In agreeing to the deal, Chair Heydinger said she was not satisfied about foregoing the 10 MW cap. “I was looking for a permanent resolution instead of something that will come back to haunt us before the ink is dry,” she said. “I don’t think we are solving anything with this.”

The vote in favor of accepting the deal was unanimous. After the vote, commissioners added stipulations requiring compliance commitments from Xcel. Throughout the proceedings, Xcel pushed for less stringentinterconnection requirements but in the end accepted the streamlining stipulations.

“The Commission seemed to believe the program had gotten too big, too fast, and was potentially too expensive for Xcel's ratepayers so determined a course correction was needed,” observed former Xcel executive, PUC staffer, and assistant DOC commissioner Mike Bull who, because of his pivotal leadership role in Minnesota’s breakthrough e21 grid modernization roadmap, was “watching closely due to the importance of the docket.”

After two “grueling days” working through the issues, Bull said, the commissioners “didn’t seem to see a better path forward than the proposed partial settlement so adopted it knowing more work will be necessary.”

“No side got everything they wanted,” said Novel Energy Solutions CEO Cliff Kaehler. “You know it’s fair when both sides think it could have been better.” His coalition of developers believed it was better to reach a compromise with Xcel than to continue in limbo.

The commission’s decision both “brings the program closer to its original intent” and protects non-participating customers who “could face significant increases in their bills if the program was left unchecked,” according toNorthern States Power President Chris Clark.

As a result, he added, Minnesota’s community solar program will be “among the largest, most robust” in the country.

Doubt about the numbers

There is significant dispute about the amount of community solar on Xcel's quene and just how much it will cost.

Xcel confirmed the over 1 GW of project applications in its queue. "It is difficult to judge which are, or are not, placeholder applications that will never come to completion," a utility spokesperson said.

Xcel made data on its interconnection queue public at the beginning of June, explained Fresh Energy Sr. Policy Associate Allen Gleckner. When it did, Fresh Energy took a close look.

After subtracting out placeholder projects from opportunistic developers, the over 1 GW in applications turned into 420 MW of projects that “had paid all deposits and fees and gone through the first checks,” Gleckner explained.

“If you put the cap at 5 MW and none of the bigger projects resize down to 5 MW, the community solar pipeline would be about 53.5 MW. If they all resize, and there is a decent chance that could happen, that would be close to 238.5 MW.”

With a 10 MW cap, those numbers come out at 206.5 MW and 296.5 MW, based on calculations done by Lahd, who was a DOC economist before going to Fresh Energy.

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Independent engineering analysis found the distribution system is likely only able to accommodate around that higher number of additions without upgrades, Gleckner added. Some upgrades might be reasonable but a major infrastructure improvement would make a project uneconomic.

By shifting the cap down to 5 MW ”all we are doing is freeing up space for other developers that didn’t act as quickly,” Stoel Rives Attorney Andrew Moratzka told the commission in explaining why his clients, the Solar Garden Community, would not sign on to the agreement. “All you are doing is taking a place from one developer in the queue and giving it to another who didn’t get in the queue as early. The difference between the groups is who acted first.”

“No one is losing position,” Novel Energy's Kaehler said. “We have at least five projects that were more than 10 MW, but if our projects are economical at 10 MW, they are economical at 5 MW."

Some also question Xcel’s rate impact calculations. Under Minnesota’s value of solar tariff, which Xcel has declined to use, the rate impact of 400 MW of community solar would likely be less than 0.25%. The 2% figure cited by McCarten was based on a limited avoided cost calculation “which is a comparison of apples and oranges," SunShare's Amster-Olzewski said.

Amster-Olzewski was referencing another set of numbers run by Lahd, based on Xcel parameters. They suggest that 400 MW of community solar, which matches Xcel’s application pipeline but probably couldn’t be accommodated by the distribution system, would increase rates no more than 1.4%, even if an avoided cost methodology was applied.

“That is negligible in the scheme of things,” Amster-Olzewski said. “Xcel just raised their rates 5% because of cost overruns for other generation.”

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What’s coming

The commission will file its final judgment within 30 days. Stakeholders have 20 days to ask for reconsideration.

The Fresh Energy rate and cap impact calculations that Commissioner Tuma complained came too late to be assessed will be studied.

“The commission’s decision was based on trying to get a successful programwith a rate impact they could be comfortable with,” Gleckner said. “Unfortunately, the rate impact information wasn’t developed in time and much of the narrative about the rate impact was created by Xcel.”

“There will be less community solar as the result of the settlement but the biggest question is whether Xcel will resolve the backlog of applications,” Amster-Olzewski said. “Whatever we can do to move the program along and get projects built by the end of 2016 is a good thing.”

All the stakeholders know the ITC sunset is driving the timeline, Lahd said. If Xcel does not honor its commitment to streamline the interconnection process, the commission will come down on them.

“Xcel is a good company and it is trying to figure this out,” Amster-Olzewski said. “They really believe this will adversely affect ratepayers because they haven’t yet learned how to integrate solar. And it is true that having 1,000 MW of applications was a challenge for them."

"I am okay with the settlement because it makes an important partner happy," he said.

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