By Robert Mullin

VANCOUVER, Canada — The three RTOs vying to organize Western electricity markets on Thursday faced off before an audience of utility regulators in what one state commissioner billed a “beauty pageant.”

“Thank you for competing,” Montana Public Service Commission Vice Chairman Travis Kavulla jokingly told representatives of CAISO, SPP and PJM. Kavulla is co-chair of the Committee on Regional Electric Power Cooperation, which hosted the panel at its spring meeting in the Coast Coal Harbour Hotel.

The regulators were there to examine the possible benefits and drawbacks of the competing grid operators’ efforts to sign up utilities in a region that has been historically resistant to organized markets. (See CAISO Bid for Western RTO to Face Competition in 2018.) They, and other industry watchers, also learned what region PJM is focusing on in developing its Western market partnership with Peak Reliability.

Here’s some of what they heard.

Looking West

Little Rock, Ark.-based SPP has been running its Integrated Marketplace since 2014, after previously operating a balancing system like CAISO’s Western Energy Imbalance Market (EIM). The RTO last year entered membership negotiations with Mountain West Transmission Group, a partnership of seven transmission-owning entities within the Rocky Mountain region of the Western Interconnection. The effort hit a significant roadblock late Friday when Xcel Energy announced it was pulling out of the group and the negotiations with SPP because of the “limited benefits” for its customers in integrating into the RTO. (See Xcel Pulls out of Mountain West, Endangering SPP Integration.)

“There are benefits from operating together” in an RTO, SPP Chief Operating Officer Carl Monroe told Western commissioners. “A natural inclination we would have is to look west.”

“We’ve got another unique situation in that we’re the only one connected to ERCOT,” he said.

Monroe touted the fact that SPP’s Board of Directors cannot express a decision without the consent of the RTO’s Members Committee, which provides each market participant a vote over market initiatives presented to the RTO board.

He also pointed out that SPP has functioned as a reliability coordinator (RC) for 20 years.

“And how that interfaces with the market … that was one of the key issues we dealt with in the market,” Monroe said. “These are hybrid markets. … They have to be designed to protect reliability itself.

“Our job one is to keep the lights on — reliability,” he added. “Even the economics don’t make sense if you’re not reliable.”

SPP’s market has been efficient for its members, he said.

“The capital costs of putting the market in — we recovered those within six months,” Monroe said, adding that the SPP footprint today carries 5 GW less generation than it would “if we weren’t running the market.”

He also pointed to SPP’s expertise in integrating large volumes of renewables.

“Of course we’re in a wind-rich area. We just set a record when 63% of the load was served by wind,” he said. “That could not have been done unless on a regional basis.”

“We actually do interregional coordination,” Monroe continued. “This is one of the things we’ll need to do within the West itself, is making sure we coordinate all the activities, whether it’s transmission planning, transmission operations, reliability coordination, market activity. All those things will have to be coordinated with the other parties that border whatever footprint we finally get around to.

“Part of the strategy going forward is being open to those parties who want us to do these services for them,” Monroe said.

Listening to the West

“As you all know, many states in the West are aggressively pursuing more renewables,” CAISO CEO Steve Berberich said.

With a fleet heavy in renewables, ramping and overgeneration become “a focal point” for the ISO, he said.

“Security-constrained economic dispatch — in other words, an optimized market — is the best way to run the grid as efficiently as possible, and the sharing of resources is the best way to solve our critical need collectively to support the variability of renewables and the induced ramps,” Berberich said. “Further, the zero-marginal-cost power is better shared at a lower cost for all of our customers. We share this view with our [SPP] friends from Little Rock. You’ll also hear that from our friends from PJM in Philadelphia.”

Berberich trumpeted the EIM’s $250 million in member net benefits since it was launched in 2014. CAISO last year proposed to expand the EIM to include day-ahead transactions without transitioning the market into a full RTO. The ISO has also announced it will withdraw from Peak Reliability as an RC and provide reliability services to other balancing authority areas in the West.

He acknowledged that the EIM’s implementation of a day-ahead market will require the ISO to resolve approaches to resource adequacy and transmission compensation.

“Those are solvable, and we’ll continue to give deference to state control over resource mix and capacity margins. We also expect the EIM Governing Body to morph into a broader governing body with at least some joint decisional authority with the current [CAISO] board of directors,” he said.

CAISO expects to offer the combined EIM and day-ahead market at a cost significantly below the ISO’s current grid management charge, Berberich said. It also intends to offer the same reliability services as Peak at a “significantly reduced” cost.

“When you cut through it all, the fundamental markets are all the same. … What is different in our market, however, is the sophistication of our optimization and how it supports renewables, steep ramps and distributed generation aggregations,” Berberich said.

He said the ISO doesn’t foresee the need for any new transmission to “support the transformation into a regional market.”

On the issue of governance of an expanded ISO, Berberich told the commissioners that the “main pathway” is to change the existing governance model through legislation at the state level in California.

“The alternate pathway is to continue to evolve our governance according to the Energy Imbalance Market’s governing model, and with a day-ahead market, that will necessarily involve decisions on transmission compensation and some form of resource adequacy, both potentially having input from the [EIM] Body of State Regulators,” he said.

“Some of the ISO brethren say the Peak/PJM market offering is a market by the West, for the West, which misses what has already occurred in the Energy Imbalance Market. Participants are certainly not guests of the ISO, rather, they help form the market,” Berberich said.

The ISO’s job is to “listen to whatever the West wants and do our best to provide the value inherent in our interconnected systems.”

“When do we need to move to this new market? Soon, we think. We believe it will provide the most efficient way to streamline new transmission planning and upgrades, reduce the need for more capacity and reduce the need to curtail valuable clean resources. It provides the greatest value with the geographical and resource diversity that the West is blessed to have.”

For the West, by the West

“We believe there’s a very real opportunity for the utilities in the West to pursue the potential for the creation of a separate market,” said Stu Bresler, PJM senior vice president of markets and operations.

Bresler was speaking on behalf of the joint proposal between Peak Reliability and PJM Connext (a PJM subsidiary) to develop new wholesale market structures for the West. Like the CAISO EIM day-ahead expansion, it would fall short of creating a full RTO in the near term, while creating a foundation for one in the future.

Kavulla asked: “What area are you focusing on? Is it an area with lots of trees and hydro, or lots of sun?”

“We’re focusing primarily in the Southwest,” Bresler replied.

“The value proposition — and Steve has already said it before I had a chance to get up here — is a market for the West and by the West,” Bresler said. “What we are really leveraging here is the combined knowledge of our expertise of both of our organizations.

“PJM has proven its ability to promptly deliver on its commitments,” he said, citing PJM’s pledge to complete a business plan with Peak by March 30. (See Peak/PJM Enter Western Market Commitment Phase.)

“We have also been sharing the full plan with a set of key entities in the Western Interconnection that could potentially form the basis for a separate market out here in the West, should they decide to pursue that,” he said.

Striking a similar note to SPP’s Malone, Bresler said that wholesale electricity markets exist for the sole purpose of reinforcing grid reliability.

“That’s why we develop them; that’s why we operate them.”

Bresler said markets are intended “to ensure that physical asset owners have the financial incentive to act in a manner as to reinforce grid reliability.” Key to that is ensuring that market prices reflect actual operating conditions, and that “those prices are transparent to market participants in real time.”

“And that transparency and that reflection of actual operating conditions is what builds the confidence of the physical asset owners that the dispatch instructions delivered by the system operator are in their financial best interests. That financial best interest is a powerful motivator that supports reliable grid operations,” he said.

“We believe that the bulk of trading activity actually occurs in the bilateral markets,” Bresler said. “That is really an appropriate way for things to occur because it is what allows market participants to best manage and therefore minimize their risk.”

Bresler said the Peak/PJM business plan — which has not been made fully available to the public — shows that “with a large amount of participation in a market in the West, the production cost savings become very substantial.”

Lauding Peak’s RC capabilities, Bresler said that much of the hard work of starting up a regional market is already complete based on Peak’s West-wide model and the processes and mechanisms in place to support reliability.

“Really, the smaller part is layering [the market] on top of those reliable grid operations,” he said.

PJM’s “Day 1” market offering would consist of a day-ahead and real-time market.

“Some options that could be included as well, should participants want it, we could operate ancillary services. We could also add [financial transmission rights], but that’s not a requirement for Day 1,” Bresler said.

Based on feedback from potential participants, Bresler said Day 1 won’t include a resource adequacy construct or capacity market; consolidation of transmission tariffs; provision of transmission service; and regional or sub-regional transmission planning.

On one key issue, Bresler sought to score points from commissioners overseeing utilities already participating in the Western EIM.

“I don’t think of the establishment of the market as being exclusive of participation in the EIM,” he said.

Bresler noted that Peak and PJM had envisioned getting a “critical mass” of commitments from market participants by May or June, but they have extended that timeline to determine a “go or no go” decision on the market by the fall.

Kavulla asked Bresler when Peak/PJM anticipated releasing its full business plan for public review.

“We don’t really have any plan to do that. If members do decide to take the next step, we would take the decision with the members to do that,” Bresler said.

Bresler wrapped up his moment in the spotlight by echoing Berberich’s conclusion: “If utilities in the West want a full market … there’s not a better time to do it than now.”