NEW ORLEANS — MISO CEO John Bear opened the Gulf Coast Power Association’s MISO South Regional Conference with a recap of the RTO’s strategic initiatives and the five “500-year” storms he said the region has experienced in less than four years.

“I’m not a statistician, but I think that means they’re not 500-year storms anymore. This polar vortex thing … is real, and it’s happening on a more frequent basis. I’ll leave for debate why it’s happening … but we don’t really care. All we know is that it is happening and we have to deal with it.”

Bear also responded to concerns he has heard from state regulators and others that MISO’s costs are rising.

He said the RTO’s administrative charge is still about 38 cents/MWh, “which is right with PJM, which is half [the rate] of the next RTO that’s even close to us because of our scale and our ability to manage costs.”

He acknowledged that MISO’s transmission costs have risen but said the $5.6 billion invested as a result of the RTO’s Transmission Expansion Plan will produce energy cost savings of at least a 3-to-1 ratio. “So, the energy costs are going down while the transmission costs are going up.”

He also said transmission growth is essential to MISO’s efforts to clear its interconnection queue. “If we don’t build more transmission, it’s not going to help. It’s still going to be slow and, I would argue, it’s going to be inefficient.”

North-South Transmission

Bear said any consideration of potential transmission projects to provide more transfer capacity between MISO South and North-Central should be part of a holistic, regionwide analysis.

He said MTEP 19 will consider two different generation portfolio mixes, referring to the accelerated fleet change future and the distributed and emerging technologies scenario. “They look very different than the [portfolio] that we have today. And so, understanding how the transmission system could be optimized to operate that portfolio is the key.

“I think we’ve got to study that,” he added. “If there’s not a benefit, and a pretty significant benefit … then we’re not going to construct the transmission portfolio.”

In MTEP 17, MISO conducted a “footprint diversity study” to identify transmission projects to increase connections between the regions. But the study found that none of the 35 projects considered passed the 1.25-to-1 benefit-cost criteria based on adjusted production cost benefits. (See “No Tx Coming for North-South Constraint,” MTEP 17 Proposal: 343 New Transmission Projects at $2.6B.)

Several speakers at the conference offered different perspectives on the North-South bottleneck.

“While it’s important to look at the overall MISO footprint and have solutions that work for the overall MISO footprint, the reality is … that we have an 85,000-MW system in North-Central [and] a 35,000-MW system in the South connected by a 3,000-MW shoestring,” said Jim Dauphinais, managing principal for Brubaker & Associates. “And so therefore, when we have these [emergencies], they tend to be North and Central events or South events because we very quickly hit the transmission limit.”

Paul Jett, vice president of corporate development for GridLiance, said another look is warranted. Regarding the MTEP futures assumptions, he asked: “Do we have the right criteria? Are we measuring the right things? … It seems like we need to take a look at that because I think we’re missing something in the cost-benefit [analysis].”

Marcus Hawkins, executive director of the Organization of MISO States, suggested the RTO should take a new look at the North-South transmission expansion incorporating the “500-year” storms that were not in the initial analysis.

Hawkins said one of his group’s two strategic priorities for the year is whether there is a business case for a holistic “top-down” look at transmission improvements.

“The states want to be involved in developing the assumptions that go into that business case evaluation of bigger picture transmission plans. So, our authority is to be heavily involved in that process: guide what assumptions are made, make sure the appropriate benefits are included in that sort of analysis and that [the] uncertainty of this changing resource mix is captured accurately, because the states have very different views of what the future might look like … and then, at the end of that process, [find] out if transmission is the right answer or not.”

OMS’ second priority is being ready to respond if FERC issues an order on distributed energy resource aggregation. The commission opened a docket on the issue (RM18-9, AD18-10) in February 2018, separating it from its rulemaking on energy storage. (See FERC Rules to Boost Storage Role in Markets.)

Hawkins said some states are re-evaluating their bans on aggregation of distributed energy resources “because their consumers want to be more actively involved in the MISO market — and they want it now.”

“And this millennial can relate to that,” he said, sparking laughter.

LMRs Under Attack?

MISO officials repeatedly returned to the RTO’s resource availability and need (RAN) initiative during the daylong conference, saying their planners can no longer worry about just meeting the peak load hour of the summer.

“We assumed, and it was correct at the time, that if we had enough generation to meet that one peak summer hour, we’d be fine the rest of the hours of the year,” said Richard Doying, MISO’s executive vice president for market strategy and development. “What we’re finding now is that’s simply not the case. We really have to think about the availability of resources on an hourly basis all year long.”

Indeed, Dauphinais noted that none of the three MISO South maximum generation events since 2017 occurred during the summer. They included one on April 4, 2017, “which is the least likely time of the year you’d expect to be having a problem with deliverability of power to meet load,” he said.

Another occurred on Sept. 15, 2018, a Saturday. “In my 35 years of experience in this industry throughout the country, I can’t remember ever having a capacity emergency declared on a Saturday,” Dauphinais said. “So, we’ve got something unusual going on here.”

Dauphinais attributed the problems to higher planned outages, the lack of quick-start (two hours or less) resources “and, possibly, the retirement of older natural gas steam units.”

Last week, FERC approved one of three sets of proposed rule changes MISO has filed as part of RAN Phase 1, a requirement that load-modifying resources commit to deploying based on the shortest notification time they “can consistently meet.” (See related story, MISO LMR Capacity Rules Get FERC Approval.)

“We call it the best capability requirement, where — like generators — we’re asking LMRs to offer to us whatever their best capability is rather than their minimum capability,” MISO Executive Director of Market Development Jeff Bladen explained.

Dauphinais said industrial customers are concerned that in RAN Phase 3, which may include consideration of a seasonal capacity accreditation, MISO seems “to be … picking on LMRs again.”

“All resources need to be considered. Not [just] LMRs. Long start-time, high minimum-output, high variable-cost generators are not very different than LMRs that have a long lead time,” he said.

“If there need to be changes to the market design and products addressing both reliability and efficiency, you better identify those first — before you start changing how much capacity you’re going to credit the load-modifying resource or any other type of resources,” Dauphinais continued.

“LMRs and other resources should not have their capacity accreditation degraded if they do not provide a new product that MISO needs. Instead … MISO should create a separate market for that product if it’s truly needed and have resources compete to provide that. And that includes demand response. … Demand response is not the cause of the problem here. It is one of the solutions.”

MISO Independent Market Monitor David Patton said most LMRs were unable to help during the April 2017 and January 2018 maximum generation events because their notification times were longer than two hours. He disagreed that new products are needed, calling instead for improving reserve demand curves to ensure effective shortage pricing.

“I haven’t seen any evidence we need any new products. … If you have good shortage pricing, the folks that can start in two hours get paid, and the folks that can’t don’t get paid,” he said. “With all due respect to the LMRs, that 12-hour LMR is almost worthless.”

On the other hand, Patton said, MISO could offer “very attractive prices” for industrial LMRs that can respond to emergencies.

He said many cogeneration units in MISO South “would really be good 30-minute reserve providers. And when we’re short of 30-minute reserves, they would get paid even when we’re not deploying them — which means they wouldn’t even have to cut their load, but they would get paid $500 to $1,000/MW depending on how it’s priced.”

Bladen said improving shortage pricing is one aspect of the RTO’s “all-of-the above solution set.”

“There’s no silver bullet answers. It’s not just addressing outage coordination,” he said. “It’s not just addressing the emergence of emergency LMRs as a major element of our operating fleet. It’s not just addressing scarcity pricing. But it’s really all of the above.”

Bladen challenged Dauphinais’ contention that there is no chance for LMRs to earn additional compensation under the rules approved last week.

“To the extent that there’s a view that there’s a premium product that’s being asked for, certainly nothing stops the LMR resource owners [from offering] to sell at a premium price,” Bladen said.

“We want to adapt our markets to reflect a changing set of requirements. The need for flexibility is different today and likely tomorrow than it was yesterday. And the reason we haven’t addressed it previously is because the need was emerging rather than upon us.”

‘Highest Use’ for Storage?

GridLiance’s Jett said his company thinks MISO’s proposals on storage as a transmission asset (SATA) are a good “first step,” but he wants to ensure cost allocation rules put transmission owners and non-TOs on an “equal platform.” (See MISO Opens Storage Proposals to All Tx Project Types.)

“I’ve been around MISO a long, long, long time and lived through every one of the cost allocation discussions, so I understand all the issues from both sides — three sides, four sides. It’s tough to figure that out,” Jett said.

CEO Bear said that while MISO’s transmission queue has been flooded with wind and solar projects, “one thing we haven’t seen in the queue is storage.”

In addition to participating in stakeholder discussions on SATA rules, MISO staff is working to determine the “best, highest use” for the technology, Bear said.

Batteries might be most valuable as quick-response resources that help MISO operators balance the system around its growing wind and solar generation, rather than “trying to store energy in them,” Bear said.

“MISO’s footprint is so big and so diverse, it actually is the ultimate storage device,” he said. “But as we move forward, that may change as the capabilities and the technologies of storage or batteries change.

“We’ve almost internally forced ourselves as a company to calling them batteries, as opposed to storage, just because we don’t want to presuppose what the best use of them might be.”

— Rich Heidorn Jr.