By Rich Heidorn Jr.

ST. PAUL, Minn. — MISO officials last week outlined proposals to boost its capacity resources, winning some support for efforts to streamline the generator interconnection process and redraw its zonal boundaries to reflect constraints.

But its proposal to switch from annual to seasonal procurement ran into stiff opposition from the Independent Power Producer and Power Marketers sectors, and states balked at a proposal to replace the interconnection queue with the auctioning of generator sites.

Jeff Bladen, executive director of market design, presented the resource adequacy “straw proposals” — the result of stakeholder meetings that began in February — at a meeting of the Advisory Committee. (See MISO Stakeholders Call for Seasonal Resource Construct; Cool to Mandatory Capacity Market.)

“We don’t have consensus, which shouldn’t surprise everybody, but I think we’re getting very good input,” CEO John Bear said afterward.

Seasonal Procurement Idea Receives Push Back

Bladen said the proposal for seasonal procurement was driven by concerns over the year-round availability of resources such as demand response and generation imports. Bladen said seasonality was one of the top three concerns cited by stakeholders in discussions.

“It goes well beyond demand response. There’s lots of different resource types that have either limitations in terms of the times of year they can offer to commit to MISO or have limitations in terms of the economics of how often they want to be available. Examples might include … imports from other regions that might need to be committed to the other region in some parts of the year.”

Mitch Myhre of Alliant said he was “supportive of what MISO has proposed so far.”

Exelon’s Marka Shaw, of the Power Marketers sector, questioned the need for the change, saying there is a greater need for a long-term price signal to incent generator construction.

“You may have solved a problem with Canada and may have created a problem with PJM because the PJM market doesn’t have a seasonal construct,” she said.

Representing the Independent Power Producer sector, Dynegy’s Mark Volpe agreed, calling PJM MISO’s “most important seam.”

“They’ve got an annual construct there, and [seasonal procurement in MISO] would seem to be at odds with talk of trying to converge capacity products,” he said.

Bladen noted that MISO’s just-in-time capacity procurement is already different from PJM, in which resources commit three years in advance.

“It’s hard to see how that would preclude resources from making the same kinds of decisions in the future that they make today on whether to commit to PJM three years in advance or to think about committing to MISO,” he said. “The perspective we’ve taken so far is having a better price signal that reflects the real loss-of-load expectation in the seasons might actually draw resources to” MISO.

Representing the Public Consumer sector, Nancy Campbell of the Minnesota Department of Commerce backed MISO’s initiative. “We don’t think that the seams issue should [prevent] going forward with the seasonal resources. In fact maybe that’s something we should encourage PJM to do as well.”

NRG Energy’s Tia Elliott, of the IPP sector, questioned why MISO was citing the 2014 polar vortex as justification for the change after saying it was not sufficient for changing the day-ahead energy schedule. “I think that MISO might be talking out of both sides,” she said.

John Moore of the Sustainable FERC Project also supported the effort, saying winter wind should have a higher capacity factor than the year-round 14.7% it is currently assigned.

“In MISO, a 13 to 14% annual capacity factor for wind, and also a relatively low capacity factor for solar, just doesn’t make sense to us. Where wind does very well it’s higher than that. So we think that a seasonal construct would help address that and bring more value to the resources that are out there.”

Calpine’s Brett Kruse said that NYISO and ISO-NE incorporate seasonality in their capacity procurement, with “pros and cons.”

But he said it would do little to make MISO more attractive to generators. “If you honestly think this is going to help with price signals on the capacity side, I got $100 that I’ll bet you right now that it doesn’t do anything,” he said.

The discussion gave Market Monitor David Patton an opportunity to offer a plug for his recommendation that MISO adopt a sloped demand curve similar to that used by PJM and recently adopted by ISO-NE.

Referring to Kruse’s comment in an earlier discussion about the potential for some combustion turbine owners to move them from MISO, Patton said, “It sounds crazy, but it’s not.”

Patton said seasonality wouldn’t necessarily reduce overall capacity costs but could allow efficiencies for owners of some older generators who would like to reduce plant staffing during shoulder months. “Those are good cost savings because they don’t cost other generators money,” he said.

Bladen said the discussion will continue at Thursday’s meeting of the Supply Adequacy Working Group, where stakeholders will discuss how many seasons to consider.

“We haven’t gotten into the details of what the makeup would be: whether it’s a single auction; whether it’s multiple auctions that are prompt; whether it’s two seasons or more than two seasons. We’ve tried to stay a little bit above that at this point, with a recognition that we will need to tackle that,” he said.

State Officials Wary of New Zonal Boundaries

MISO’s proposal to establish local resource zones based on physical constraints also sparked some opposition, even after RTO officials promised any new zones would respect state boundaries.

Michigan Public Service Commissioner Sally Talberg, representing the Organization of MISO States, said OMS favors keeping the existing zones.

Several speakers, including Indiana Utility Regulatory Commissioner Angela Weber, said they feared basing zones on physical limitations would result in “volatility.”

Chris Plante of Wisconsin Public Service Corp. said the Transmission-Dependent Utilities sector does not have “perfect alignment” in their position on the issue. But he said the sector did agree there is a problem in using “snapshot” power flow analyses to determine zones, because new generation, retirements, new transmission and loop flows can impact the results.

“Our concern is if you try to design those zonal boundaries based on those constraints every year, you’re going to have stakeholders coming to you and saying we need to redraw the boundary because something has changed,” he said. “We see already with the [capacity import and export limits and loss-of-load expectations]. They vary from year to year — sometimes dramatically.”

Dynegy’s Volpe said, however, that much of that volatility is due to recent improvements in LOLE analysis, including the lowering of the threshold from 230 kV to 100 kV. “We haven’t had stability in the ground rules around the LOLE study,” he said.

Patton said while the uncertainty caused by continually changing zonal boundaries can be “damaging,” price changes that signal shifts in the supply-demand balance are valuable.

“Defining interfaces that create potential deliverability problems [that] may bind or may not bind … has a huge benefit over a structure like in New York where you’re continually fighting about … whether you’re going to define a new zone.” Failing to define zones consistent with physical transmission limits can result in not purchasing enough capacity on the right side of the constraint, he said. “So you’re exposing yourself to resource adequacy or transmission security problems that would potentially have been easy to avoid if you just quantify how much capacity you have to have on this side of the constraint versus that side of the constraint.”

Patton said creating additional zones to reflect state boundaries is not a problem. “You can’t have too many zones. If you define zones you don’t need, they just don’t bind and the prices equilibrate. The idea that Amite South and WOTAB are not separately recognized as places where we need generation seems really hard to justify.”

Stakeholders Agree on Need to Reduce Interconnection ‘Churn;’ States Oppose Auction of Generator Sites

MISO’s call for reforms to the generator interconnection process drew wide support, but its proposal to replace the interconnection queues with the auctioning of pre-qualified generation sites drew opposition from Indiana’s Weber, who said auctioning might undermine state jurisdiction.

Dehn Stevens of MidAmerican Energy said the Transmission Owners support measures to reduce “churn.”

“There’s nothing more frustrating than to have something like three of every four projects we look at as owners … never actually get built,” he said. “It’s a very inefficient use of our internal resources.”

“If you’re providing cost certainty to a generator that’s interconnecting, but the costs differ [because of other generators dropping out of the queue], you can be basically moving costs onto the transmission owner or its … customers.”

Beth Soholt of Wind on the Wires said she was concerned that MISO proposals to increase the cash at risk for those in the generation interconnection queue could be a barrier to entry.

“In each queue reform process, we have put different mechanisms in place for the different milestones. So we’ve gone from really a portfolio option, or a smorgasbord of options, for interconnection customers on readiness — site control and the whole raft of things they can do to prove readiness to move through the queue — we’ve really gone to [requiring] a large pile of cash at risk.”

Soholt added that wind developers are willing to put more cash at risk if it leads to more certainty about costs of transmission upgrades they would be required to pay. “But that certainty has been elusive through several rounds of queue reform,” she said.

Next Steps

MISO and stakeholders will refine the seasonal and locational proposals in joint meetings of the SAWG and the Loss of Load Expectation Working Group through December with hopes to make changes effective for delivery year 2017/18.

The interconnection changes will be discussed by the Interconnection Process Task Force with a projected implementation in August 2016.

MidAmerican Energy’s Stevens said MISO’s timeline is “very aggressive” for such large changes.

“I would question the supposition that the sky is going to fall in two or three years with the reserve margins. I think we saw in this last update [to the MISO-OMS survey] that the shortfall moved out a year or two. Sure seems like you might see that again in a year that the shortfall is moved out,” he said. “You are going to be better served getting it right and having fewer than 150 people fighting you at FERC.”