Page 1007 – RTO Insider

December 11, 2020

WECC Says Extreme Events Require Forecast, RA Changes

Western balancing authorities should determine what caused the drastic errors in their load and generation forecasts during August’s massive heat wave and fix their forecasting process before next summer, WECC said this week.

That recommendation was just one of eight the regional entity offered the region’s BAs based on findings from its event analysis of the mid-August “heat storm” that gripped much of the West for nearly a week. The weather event prompted WECC Findings Show Complexity of Heat Wave Event.)

The heat wave was the topic of a technical session at a virtual version of WECC’s quarterly series of Board of Directors meetings. Tim Reynolds, WECC senior engineer, opened his presentation by saying there are two main reasons to perform an event analysis.

“One is you’re expected to, which is not the most ideal, because you’re doing the bare minimum checking the boxes, and you want to move on,” Reynolds said. “The second reason is more of learning mentality, and that’s definitely the approach the [WECC] team [took] for the analysis for the heat wave.”

WECC broke its heat wave event findings and recommendations into four categories: high load demand, use of transmission, inaccurate forecasting and resource adequacy.

Under the “high load demand” category, WECC determined that the Western Interconnection set a new peak record of 162,017 MW on Aug. 18, continuing a trend in which summer peak loads in the West have been increasing steadily over the past 10 years, creating increased competition for generating resources. Reynolds noted that some northern balancing authority areas that were previously winter peaking are becoming “dual peakers,” with both summer and winter peaks.

Reynolds said that 11 Western BAs were placed into an energy emergency alert (EEA) state during the event, with six elevated to the highest alert level — EEA 3 — but only CAISO was forced to shed load Aug. 14-15.

The event also indicated to WECC that reliability coordinators (RCs) and BAs may be applying NERC standards BAL-002-3 and BAL-002-WECC-2a inconsistently. The first standard ensures that a BA balances resources with demand and returns its area control error to defined values after a contingency event. The second specifies the quantity and types of contingency reserves required to operate in normal and abnormal conditions.

Reynolds said when an RC invokes an EEA, BAL-002-WECC-2a allows the affected BA to use multiple types of resources to meet its contingency reserve requirement but prohibits it from dropping below the required reserve to address a real-time emergency.

In response, WECC recommended that the regional entity work with industry experts to determine whether the standard should be changed to allow BAs to temporarily drop below the requirement. It also recommended further collaboration with experts to produce a document that provides more guidance to how BAs and RCs should respond to EEAs.

Unscheduled Flows, Unqualified Paths

Reynolds prefaced his description of WECC’s “use of transmission” findings by explaining how transmission flows in the West generally move in a circular fashion from north to south, with output from Northwest generation traveling on multiple transmission paths to serve loads in California and the Southwest.

Months before the heat wave, a windstorm damaged the Northwest AC Intertie (NWACI), a major line connecting the Bonneville Power Administration control area with California, reducing its rating by up to 1,250 MW. At the same time, a 750-MW derate on Path 3 limited transfers out of British Columbia. Transmission operators were able to increase the NWACI’s rating over Aug. 14-15, but derated it again after the system became unstable due to unscheduled flows.

Reynolds said the region’s existing procedure to mitigate unscheduled flows could not be applied to the NWACI because the line is not considered a “qualified path” under the Western Interconnection Unscheduled Flow Mitigation Plan (USFMP). As a result, the plan could not be invoked to coordinate phase shifters in the region because there were no unscheduled flows occurring on qualified paths at the time.

To avoid a similar outcome in the future, WECC recommended that RCs and BAs use phase shifters to help mitigate unscheduled flows beyond qualified paths. It also advised BAs to determine whether more transmission paths should be included in the USFMP.

WECC additionally recommended that RCs, BAs and transmission operators prepare for next summer by developing operating plans for a similar event. TOs should also work with their RCs to explore any phase angle concerns and establish “appropriate” system operating limits and interconnection reliability operating limits, WECC said.

Forecast Errors

A joint root-cause analysis of the blackouts by CAISO, the California Public Utilities Commission and the state’s Energy Commission found that under-scheduling by the state’s utilities contributed significantly to the ISO’s blackouts and subsequent EEAs. (See CAISO Says Constrained Tx Contributed to Blackouts.) WECC’s analysis has extended that finding to other areas of the West that declared alerts.

“What is interesting is when we asked the BAs that were in an EEA as to the cause of them being placed in it, some of the responses stated that their demand was higher than forecasted and it was difficult to find generation to purchase — so they had to go into an EEA,” Reynolds said. Other BAs told WECC that wind and solar production on Aug. 17-18 fell short of day-ahead forecasts, preventing them from meeting demand obligations.

“The BAs need to go back to this event, find the errors in their forecast leading up to it and make the changes needed to prepare for next summer,” Reynolds said.

“The longer out you can accurately forecast things, the more you can do ahead of time … like bringing back generation or transmission lines that were out for service,” he said.

Read, Understand, Follow

The California joint agency report and WECC have both pointed to outmoded resource adequacy planning as a central cause of the August energy emergencies. A key part of the problem, WECC found, is how current RA planning methods account for the contribution of the variable renewable resources that failed to perform as expected in intervals of peak demand during the heat wave.

That risk could be compounded as the West increasingly relies on renewable generation because of state clean energy mandates.

“From 2013 to 2019, we see overall about a 1% change in total net generation … which is not a significant change,” Reynolds noted, pointing to a bar graph in his presentation. “However, we do see an increased change in the use of solar and wind with a decrease in the baseload generation.”

“Resource adequacy usually forecasts a year out,” said Matt Elkins, WECC manager of performance analysis and resource adequacy. “We’re not really into forecasting day-ahead or anything like that, but you can see the same thing” with respect to the impact of variability on predictions.

Elkins said WECC found that current methods for planning RA are not reliable for extreme weather events. “We have to change the way we do things, and I think that’s what we’re getting at here.”

WECC’s recommendation? That industry participants “read, understand and follow” the recommendations to be included in WECC’s Western Assessment of Resource Adequacy, to be released later this month as a supplement NERC’s Long-Term Reliability Assessment for the entire North American grid.

Elkins provided board members a peek at those recommendations during their meeting Wednesday, which followed a technical session on the heat storm Tuesday. Included among the recommendations is a suggestion that the West adopt a dynamic reserve margin to better ensure reliability for all hours as more variable resources come into the system.

‘A Lot of Communication’

At the end of the Tuesday’s technical session, WECC Director Jim Avery asked how the heat wave analysis will be shared with state regulators.

“Will that be something the [Western Interconnection Regional Advisory Body] does? Is that something you’ll be reaching out to offer the regulators in the region? Because I know several regulators … raised concerns about what happened this summer, and if we’re part of the answer to explaining it, how are we getting the right information to them?” Avery asked.

“I think this is a very important message, and I think our plan will be to have targeted conversations with WIRAB and others to really inform them on what we’re seeing and what our plans are to mitigate some of these issues,” said Branden Sudduth, WECC vice president of reliability planning and performance analysis.

Avery noted also that the analysis covered the variability around renewable resources and weather, “but with extreme weather you get derates on baseload. How did that play out?”

“That’s an analysis we want to do,” Elkins replied.

Director Dan Arvizu asked about the biggest opportunities for improving forecasts. “Is it about the modeling? Is it about the computational capacity?” Arvizu asked.

“I’d be remiss if I didn’t mention from the team that it’s definitely been computational time,” Elkins said. “That’s one of the biggest problems with probabilistic studies to date is that the computing capability has not been there. We’re just now breaking into that.”

“And also, communication. … A lot of communication in the entire interconnection needs to be occurring,” he added.

December 11, 2020

Texas RE Says Goodbye to CEO, Chair

The Texas Reliability Entity on Wednesday bid farewell to CEO Lane Lanford, Chair Fred Day and Director Delores Etter during the regional entity’s annual meeting.

The virtual format frustrated incoming CEO Jim Albright, who lamented not being able to rub shoulders one last time with outgoing board members.

“This sucks,” Albright said. “The next time we meet together, you need to come to the meeting so we can have a proper sendoff.”

Albright and other board members took turns honoring the departing officials for their tenure with Texas RE in what Lanford said “looks suspiciously like a roast.”

“You created an environment for all of us to be successful,” Albright told Lanford, who served as the Texas Public Utility Commission’s executive director for 17 years after leaving the banking industry.

Lanford joined Texas RE in 2010, becoming CEO two years later, “fortunately for us,” Albright said, crediting him with growing the entity as a separate extension of ERCOT.

Day, who served two terms as chair during his 10 years on the board, reviewed Texas RE’s accomplishments during 2020. They included a third extension of its contract with NERC; a 10-year lease at a cheaper, less congested location in Austin; and the Nomination Committee filling two independent directors’ positions on the board and choosing Albright to replace Lanford. (See Texas RE Names Albright as New CEO.)

“Jim is well prepared for this. He’s been training for an opportunity like this,” Day said.

Day and Etter also credited Lanford with helping to improve the REs’ relationship with NERC.

“Our relationship at the NERC level is much better than it was 10 years ago, I can assure you,” Day said during the board’s meeting, which followed the annual meeting and Member Representatives Committee (MRC) session.

“We have a lot more say about what happens than we did 10 years ago. And it’s not that people didn’t listen 10 years ago. I just think we have more influence, if you will, on the final outcome of what is going to be done,” he said. “I think one of the main reasons for that is people like Lane Lanford and others who have worked with NERC … trying to convince them that the only way for [the ERO Enterprise] to really work the way it should work, and the way it needs to work, is to build some trust.”

Etter agreed. “I think Lane had a lot to do with kind of organizing the other heads of the [regional] entities and doing it in a very professional, respectful way,” she said. “I know when I was on the NERC board [2004-2005], there was not any people from the entities that sat at the head table, and one of things Lane did was change that.”

Albright, who joined Texas RE in 2013 and was previously the COO, said he was honored to be leading the organization. “[The staff] gets all the credit for us continuing to do what we do [and] the consistency we’ve had over the years,” Albright said.

“I think way back to January of this year; it seems like a long time ago. We were thinking we were going to execute the plan that was in place but in March; we were faced with something completely different,” Lanford said. “I’m sure a lot of things we’ve done this year will be carried forward in new workplan. There were a lot of positives that came out of this.”

Lanford pointed to the increase in workshop participation and the ability for staff to perform their work remotely, thanks to Texas RE’s home office setups.

“That’s paid off, because we haven’t missed a beat,” he said.

MRC Meeting

The MRC met briefly in the morning, reviewing staff’s quarterly reports and regulatory updates.

ERCOT’s Christine Hasha, who chairs the grid operator’s Critical Infrastructure Protection Working Group, reminded members that CIP-008-6 (Cyber Security-Incident Reporting and Response Planning) takes effect on Jan. 1.

Texas RE’s outreach effort has been 100% virtual since March, staff said. Still, webinars and workshops attracted more than 2,300 participants this year, almost double the number reached in each of the previous two years.

The RE has a net increase of 10 members entering 2021 for a total of 110. The generation segment increased by 12 members, to total 68, but cooperative membership dropped by two, to 11.

Oncor’s Eric Shaw told the MRC that he will chair the NERC Standards Review Forum’s reliability, security and compliance efforts in 2021, with ERCOT’s Matt Stout serving as vice chair.

Return of In-person Meetings

Albright said the Texas RE is hoping for a return to in-person meetings in April, saying its original planned January return is not realistic. There will be no on-site audits until people are comfortable with them, he added.

“Obviously, we’re concerned about everyone’s healthy and safety,” Albright said. “We don’t want to push things too quickly.”

Lanford said the RE’s new, more spacious offices will be near ERCOT’s. “We can’t create any kind of social distancing” in its current office, he said. Working from the office is voluntary and limited to 50% of the total staff.

Change to Annual Meeting?

The board approved Vice Chair Milton Lee as chair to replace Day and newcomer Suzanne Spaulding as vice chair. Spaulding is joining the board as an independent director for a three-year term beginning Jan. 1. (See “Committee Selects Ex-DHS, CIA Counsel as Director,” Texas Reliability Entity Briefs: Sept. 3, 2020.)

In one of his final actions, Day urged the board to consider changing its bylaws to move the annual meeting to February from December.

“We have so many other things we need to get done at the December meeting,” Day said. “It’s not quite as busy in February … and also it would be nice to have a recap of the full year rather than doing a report in December. Hopefully, that’s something that, Milton, you and others can make happen.”

Corporate Goals Added to Work Plan

In his report to the board, Albright said he was adding four corporate goals to the annual work plan priorities document: integrating “the realization of ERO transformation aspirations”; intentional engagement with stakeholders; enhancing the information technology and security program; and promoting diversity and inclusion.

Albright said he will report to the board quarterly on progress in meeting the goals. He told the board he would “let you know if there’s any issues going on where we might not be making key objectives for the year. If we’ve already hit it in the second quarter, we’re going to let you know that too,” he said.

Albright said engaging with stakeholders will be particularly important next year because of the continuation of remote or hybrid operations from the coronavirus pandemic.

Texas RE 2021 corporate goals and key objectives | *Texas RE*

“New entrants to our region, when we sign new people up, we’re going to get out there in front of them. We want to meet them. We don’t want the first time that they talk to us [to be] when we go out to audit them. We want it to be up front. We want to engage with them and let them know how we can help them.”

He also said he wants to “create a cybersecurity awareness outside of the compliance area.”

“We’re not talking about compliance; we’re just talking about best practices: spreading information with the industry participants. We’re looking to be able to leverage our relationship with the [Electricity Information Sharing and Analysis Center], and the best way we can do that is to make sure it’s outside of the compliance space.”

Distribution Provider Survey

Joseph Younger, director of enforcement, reliability standards and registration, briefed the board on the RE’s survey of its 37 distribution providers, the first such survey since 2015.

Younger said the survey was in keeping with the ERO’s risk-based approach by determining whether each of the distribution providers were properly registered.

“Can you be registered in a different way, either a distribution provider with just [underfrequency load shedding] or taken off the registry altogether?” Younger asked. He said the preliminary review indicates “a number of entities are likely to be deregistered or have their registration footprint reduced.”

“It will help us in the long run to really streamline all of the areas of our program because this is really the foundation for every engagement, every enforcement activity. All those touchpoints start here.”

Expanding Resource Adequacy Beyond Peak

Director of Reliability Services Mark Henry told the board the RE is “going to look very good” in this year’s NERC Long Term Reliability Assessment (LTRA) “compared with previous years.”

“We did very well this summer with what [resources] we had; how that will shape up in the future, I don’t know,” he said. “We want the LTRA to look at a lot more than peak adequacy. We also want to start thinking about different ways to measure that. … There’s a consideration of a market-based resource adequacy measure going on in our region. There’s also consideration of different approaches that are used in other parts of the world. So, you’re going to see a lot of discussion about that over the next year, I believe.”

December 11, 2020January 15, 2025

Southeast Utilities Announce Regional Energy Market

Eighteen Southeastern utilities and cooperatives, led by Duke Energy, Southern Co. and the Tennessee Valley Authority, announced Friday they will seek FERC approval to launch a 15-minute energy market next year.

The Southeast Energy Exchange Market (SEEM) will be “an overlay to the existing bilateral market to increase efficiency and opportunities for wholesale economic energy purchases and sales,” Duke Energy Carolinas and Duke Energy Progress said in an informational filing to the North Carolina Utilities Commission. The system will provide automated matching, reservation and tagging functions.

Map of proposed Southeast Energy Exchange Market | SEEM

“In the existing bilateral market, buyers and sellers have to find each other. The SEEM will increase efficiencies by using an electronic algorithm-based wholesale energy trading platform to match willing buyers and sellers in the Southeast region who are already able to transact under existing power sales agreements and authorizations.”

Duke said the market will be under the sole jurisdiction of FERC and that it will not replace or change existing federal balancing authority or transmission provider reliability requirements.

The agreement is not a pooling agreement or a wholesale power sales agreement, Duke said. It will use otherwise unused transmission capacity, and the transactions matched via SEEM will be consummated under existing bilateral agreements between the buyer and seller, Duke said.

The company’s filing included the SEEM “platform agreement” and other governing documents.

Listed as founding members of SEEM are: Associated Electric Cooperative, Dalton Utilities, Dominion Energy South Carolina, Duke Energy Carolinas, Duke Energy Progress, ElectriCities of North Carolina, Georgia System Operations Corporation, Georgia Transmission Corporation, LG&E and KU Energy, MEAG Power, NCEMC, Oglethorpe Power Corp., PowerSouth, Santee Cooper, Southern Co.’s Georgia Power and Mississippi Power, and TVA.

The companies said an independent third-party consultant estimated the market will provide members a total of $40 million to $50 million in annual savings in the near-term, potentially growing to $100 million to $150 million annually “as more solar and other variable energy resources are added.”

Not an RTO

The companies made it clear that SEEM is not a gateway to an RTO. “Importantly, SEEM members maintain local control of their generation and transmission assets, and participation is voluntary. Many of the member companies operate within state guidelines and directives, so having full control over their respective generation and transmission resources is an important governing requirement,” they said.

“We’re assessing the details released by the utilities today, but we’ve been suspect about this from the beginning,” Frank Rambo, the head of the Southern Environmental Law Center’s clean energy and air program, said Friday. “If your goals are truly to encourage renewables and lower costs, this is not what you propose and not where you stop. You would go much further in reforming the wholesale market.”

“While we are still digesting the filing, the Southeast Energy Exchange Market proposal would benefit from a number of improvements,” said Sean Gallagher, vice president of state affairs at the Solar Energy Industries Association. “The proposal is missing critical details about renewable energy integration as well as a mechanism to prevent price fixing. Both issues will ultimately impact ratepayers and are a hallmark of monopoly utility power. We support a competitive marketplace in the Southeast. Stakeholder input will be a critical part of this effort, and we look forward to engaging with regulators to help improve this proposal and create more opportunities for competition.”

When word of the prospective market broke in July following months of secret negotiations, Maggie Shober, director of power market analytics for the Southeast Alliance for Clean Energy, said it appeared to be an effort to avoid legislative action to create an RTO in the Carolinas. (See Southeast Utilities Talking Regional Market.)

North Carolina House Bill 958, introduced in April 2019, would authorize the North Carolina Utilities Commission to require the state’s investor-owned utilities to establish or join a regional transmission entity after determining such a move would be in the public interest. It was referred to the House Committee on Rules, Calendar and Operations of the House.

South Carolina lawmakers introduced legislation (S. 998 and H. 4940) in January 2020 that would establish an Electricity Market Reform Measures Study Committee to study the benefits of electricity market reforms and whether the legislature should adopt them. In February, H. 4940 crossed over to the Senate.

Shober said her organization is pleased with the utilities’ proposal for SEEM, calling it “a potential stepping stone toward letting clean energy resources compete with existing fossil generation on an even playing field.

“The governance and stakeholder structures matter,” she added. “The settlement method is unique and has not been tested under a similar setup anywhere in the country. I suspect that these will be some of the key discussion points as SEEM moves through the regulatory process.”

Administrator

The market will be run by a Southeast EEM Administrator and overseen by a four-member Operating Committee (two members representing investor-owned utilities and one each from cooperatives and governmental utilities) and a Membership Board.

Each member will get at least one vote on the Membership Board (the “Popular Vote”) plus a number of votes based on its share of the net energy for load (“Net Energy for Load Vote”).

One quarter of the market’s costs will be allocated on a per-member basis with the remainder allocated based on net load shares.

A spokesman for Associated Electric Cooperative said startup costs are expected to be less than $5 million with annual operating costs of $1 million to $3 million.

December 11, 2020

CAISO CEO Defends Blackouts Response

CAISO’s CEO and four other top officials discussed the ISO’s handling of California’s mid-August blackouts and actions to head off future shortages in a webinar Wednesday hosted by the Clean Coalition, a nonprofit that advocates for clean energy and grid modernization.

The webinar was intended partly as a response to a similar Clean Coalition event last month in which Loretta Lynch, former president of the California Public Utilities Commission, questioned CAISO’s actions in August and called on the state’s attorney general to investigate ISO market practices. (See Former CPUC President Calls for CAISO Probe.)

“I think it’s time for the California attorney general to investigate what happened at the ISO and, more than that, the ISO’s market practices that can’t keep the lights on,” Lynch said at the time.

CEO Elliot Mainzer, who assumed his role Sept. 30, denied any insinuation of a coverup Wednesday. He said the ISO’s top priorities include transparency, market integrity and resource adequacy.

CAISO Blackouts — Clockwise from top left: CAISO CEO Elliot Mainzer; COO Mark Rothleder; Vice President Neil Millar; Anna McKenna, interim head of market policy and performance; and Vice President Stacey Crowley discuss resource adequacy. | *Clean Coalition*

“This is clearly a pivotal moment for the state, and I think we all recognize that it’s essential that we develop a clear-eyed understanding of the root causes of the summer events,” Mainzer said. “This is exactly what we are working on at the moment.”

CAISO, the CPUC and the California Energy Commission (CEC) plan to release a final report by Dec. 31 on the root causes of the August blackouts and the planning, procurement and operational changes needed to prevent further outages, Mainzer said. The report will build on a preliminary analysis sent to Gov. Gavin Newsom in October. (See CAISO Says Constrained Tx Contributed to Blackouts.)

Among Lynch’s questions in November was why CAISO had allowed large exports during an extreme heat wave when it knew the system would be strained. She also questioned why some generators were not operating and asked whether convergence bidding, a financial hedge on supply and demand, played a role.

In additional written questions read to Mainzer on Wednesday, Lynch asked about the ISO’s views on transparency and why it had sought permission to withhold information from the CPUC in a recent proceeding to secure emergency capacity for next summer.

Mainzer insisted there had been no effort by CAISO staff to obfuscate. “From day one, personally I have been very pleased with my staff’s openness and their commitment to rigorously analyze and learn from the events of August,” he said.

A report by the ISO’s Department of Market Monitoring found no evidence of market manipulation or strategic outages, Mainzer noted. (See CAISO Wasn’t Gamed in Blackouts, Watchdog Finds.)

“That said, we need to stay ever vigilant on that front,” he said. “The integrity of our markets is of paramount importance to me.”

Responding to Lynch’s question about the CPUC proceeding, Mainzer said his understanding was the ISO had sought to avoid releasing reams of data to hasten the PUC’s emergency procurement process. But he said of Lynch’s query, “I’ll take that as a fair question. Certainly, my commitment to transparency shouldn’t expire in the first inning.”

‘Vulnerabilities’ for Several Years

COO Mark Rothleder, who is leading the root-cause analysis, reiterated that several major factors caused the Aug. 14-15 blackouts and energy emergencies over Labor Day weekend that nearly led to blackouts. The main causes included “climate change-induced extreme [heat] conditions … across the Western United States” that exceeded planning targets, and inadequate supply during the net peak — the early evening hours, when solar dropped offline but demand remained high.

The ISO is examining its market practices that may have contributed to the strained conditions including rules on exports and scheduling, he said.

Rothleder warned that “vulnerabilities and the need for additional capacity will exist for several years,” as aging gas plants and the state’s last working nuclear plant, Diablo Canyon, cease operations. Shortfalls next summer could range from 450 to 3,300 MW, he said.

Most of the new resources coming online by summer 2021 will be storage, and the ISO needs to ensure that operators maximize their ability to contribute during the hour or two after solar generation wanes.

CAISO is asking the CPUC to increase its planning reserve margin from 15% to 20% for peak and net peak times and to procure additional resources in anticipation of summer shortfalls, he said.

December 11, 2020

MISO Monitor Reviews Blustery Fall

Fall in the MISO footprint was a study in record wind production — in more ways than one.

The quarter was defined by unprecedented hurricane activity and peak wind generation. MISO set an all-time wind output record of nearly 19 GW on Nov. 15, when wind accounted for nearly a third of all generation.

MISO Independent Market Monitor David Patton said during the RTO’s Markets Committee meeting Tuesday that installed wind capacity and output expanded by 33% and 30%, respectively, compared to last fall. But he said the record production came with a price, as more than half of the quarter’s real-time congestion was related to wind generation.

“As our wind output grows, the transmission congestion it’s causing is significant,” Patton said.

MISO acknowledged that though wind is taking an increasing portion of the resource mix, it continues to be curtailed during high production.

Patton said “dramatic” changes in wind output occurred several times during the fall, making MISO’s forecasting vital. He said that on Oct. 18, wind generation fell from 15.5 GW to 1 GW during the day. On Oct. 16, it dropped nearly 6 GW right before the evening peak.

“If MISO doesn’t see this coming, it’s like losing six nuclear units at once,” he said.

Patton said average load was down about 7% compared to normal because of a combination of the COVID-19 pandemic and moderate fall temperatures. MISO estimated that the pandemic was tied to a 4% reduction in load this fall.

A blend of lower load, lower natural gas prices and high wind output contributed to a 14% decrease in energy prices from last fall, he said.

Pandemic-muted loads are also creeping back into the seasonal picture as infections soar and local officials again limit gatherings.

“We are moving back into COVID-19 load levels, where we are about 5% below load from a normal, non-COVID world,” MISO Director of Operations Planning J.T. Smith said.

Laura Pricing in Question

Pricing issues after Hurricane Laura made landfall in Louisiana on Aug. 27 continues to be a source of debate among staff, the Monitor and stakeholders.

Patton said the storm caused $90 million in congestion costs and “effectively created a dead zone in the Lake Charles area, destroying a significant amount of distribution system lines and transmission.” He said about $10 million of the congestion costs was from MISO pricing dead buses in the area at the $3,500/MWh value of lost load (VOLL).

He questioned the logic of pricing widespread, disconnected buses at VOLL. (See Laura Pricing Has MISO Stakeholders Scratching Heads.)

“It wasn’t an area where we were resource-inadequate. … In theory, this is not a situation that warrants VOLL pricing,” he said. “We lost a lot of key transmission lines into the area, and we lost a lot of generation.”

Patton said he is working with MISO to more appropriately price the area.

“I’m sure I’ll have more to report,” he told the Board of Directors.

MISO declared local conservative operations for a month after Laura’s landfall to support restoration efforts.

Patton said that by mid-September, three generating units in the area were again able to serve load, but total restoration was not complete until mid-October.

MISO encountered “modeling challenges” in the load pocket created by the storm, Patton said, noting the grid operator could not price conditions consistent with the aftermath until early September. During that time, prices during peak conditions only averaged about $20/MWh, even though industrial load was still going unserved, he said.

“For about a week after Hurricane Laura, the prices in the area should have been fairly high but they were inefficiently low,” Patton said. The RTO eventually established a reserve procurement constraint Sept. 8, but Patton said that by then, the tightest conditions had already passed.

MISO President Clair Moeller said it took about two to three days for the RTO’s operators to manually readjust reserve zones to get more accurate pricing following the storm. He said MISO’s pricing must be more automated and dynamic in the future.

December 11, 2020

NYISO Business Issues Committee Briefs: Dec. 9, 2020

NYISO’s Business Issues Committee voted Wednesday to recommend approval of Tariff revisions to streamline the ISO’s transmission planning and expand its scope to capture the grid’s ability to deliver energy from the future generation resource mix to the forecasted load.

The changes rename the Congestion Analysis and Resource Integration Study (CARIS) as the draft System & Resource Outlook and double the assessment periods to 20 years, consistent with the study period for proposed economic or public policy transmission projects. They also remove language requiring time-intensive staff work of little value, such as the evaluation of generic solutions to the same “top three” congested paths each cycle.

The new rules also will affect the ISO’s consideration of non-bulk power transmission facilities by incorporating transmission owners’ local transmission plans into the economic planning process.

“We wanted to make this clarification because we are planning on working with transmission owners a bit closer in our model development just to make sure that we’re capturing all the information necessary and have the coordination we find necessary to produce the best study possible,” Manager of Economic Planning Jason L. Frasier said. If the Management Committee and Board of Directors approve the Attachment Y Tariff revisions, the ISO will make a Section 205 filing with FERC in January.

Clarification: Landfill Gas Covered under Tailored Availability Metric

The BIC also voted to recommend MC approval of a clarification to apply the ISO’s new Tailored Availability Metric (TAM) rules to landfill gas resources, as well as wind and solar. (See “Tailored Availability Metric OK’d,” NYISO Management Committee Briefs: April 29, 2020.)

FERC accepted the TAM rules in September for intermittent resources for implementation with the day-ahead market run for May 1, 2021 (ER20-2337).

The clarification will replace the terms “wind and solar resources” with “intermittent power resources,” which includes landfill gas, in section 5.12.14.3 of the Market Administration and Control Area Services Tariff.

The TAM rules change how the ISO measures the amount of unforced capacity (UCAP) intermittent resources can sell — calculated as installed capacity less the resource’s derating factor. While thermal resources’ derating is based on forced outages, intermittent resources’ derating is based on their historic performance during certain peak load hours.

The BIC also approved modifications to the Control Center Requirements Manual to incorporate tariff modifications made in November related to utilization of meter services entities (MSEs) for demand-side resources. (See “Other Approvals” in NYISO OKs Changes on Hybrid, Fast Start Resources, TCCs.)

December 10, 2020

CPUC’s Randolph Named CARB Chair

California Gov. Gavin Newsom on Wednesday appointed Liane Randolph, a member of the state’s Public Utilities Commission, as the next chair of the California Air Resources Board.

CARB oversees vehicle emissions, among other roles, and has battled with the Trump administration in recent years. Its policies have influenced manufacturing in the automotive sector for decades and will continue to do so with the state’s adoption of electric vehicles. In September, the governor ordered that all new vehicles sold in the state must be emissions-free by 2035. (See Can California Meet Its EV Mandates?)

“Cleaner air is essential for California’s families, and Liane Randolph is the kind of bold, innovative leader that will lead in our fight against climate change with equity and all California’s communities at heart,” Newsom said in a statement.

Current CARB chair Mary Nichols is retiring at the end of this year and is being considered by President-elect Joe Biden as head of the U.S. Environmental Protection Agency, according to the Associated Press and other news outlets.

Randolph, 55, was named by former Gov. Jerry Brown to the CPUC in 2015 after years working in state government and in private practice as an attorney. She served as deputy secretary and general counsel at California’s massive Natural Resources Agency from 2011 to 2014 and as head of the state’s political watchdog, the Fair Political Practices Commission, during the tenure of Gov. Arnold Schwarzenegger, from 2003 to 2007.

In a statement released by the CPUC, Randolph said she was “beyond excited and honored to join the path-breaking team at CARB, which has been at the forefront of environmental progress for decades.”

During Randolph’s time at the CPUC, the commission has dealt with California’s mandate to switch to 100% clean-energy resources, the massive gas leak at the Aliso Canyon storage facility and the bankruptcy of Pacific Gas and Electric after it was blamed for catastrophic wildfires.

Randolph is a centrist on the CPUC, often reaching decisions that her colleagues support but may be more business-friendly than some would like. For instance, Randolph oversaw PG&E’s general rate case that awarded the utility a $1.3 billion rate increase over the next three years, much of it to harden the utility’s grid against wildfires. (See PG&E Gets $1.3B Rate Hike, Cancels Mass Blackouts.)

Commissioner Martha Guzman Aceves said she would vote for the decision to protect residents even though it would hit poorer households harder during the pandemic and economic downturn. Guzman Aceves also expressed doubt that PG&E would maintain and upgrade its long-neglected power lines.

Environmental justice groups had advocated for Guzman Aceves to be the next CARB chair, Politico reported.

Newsom named four other members to CARB: John Balmes, 70, professor of medicine and environmental health at the University of California, San Francisco, and at UC Berkeley; Belmont City Council member Davin Hurt, 45; Los Angeles attorney Gideon Kracov, 49; and Tania Pacheco-Werner, 36, assistant co-director of the Central Valley Health Policy Institute at California State University, Fresno.

Newsom will appoint Randolph’s successor on the five-member CPUC. All the appointments will require confirmation by the state Senate.

December 10, 2020

NYISO Monitor Highlights Out-of-market Dispatch

NYISO energy markets performed competitively in the third quarter of 2020, but the use of out-of-market actions to meet local and statewide reliability needs was a significant concern, the Market Monitoring Unit said Monday.

“One of the big themes in this quarter, partly because of relatively low load levels and low natural gas prices, was the frequent use of out-of-market [OOM] actions to maintain reliability and transmission security,” Pallas LeeVanSchaick of Potomac Economics said in presenting the Market Monitoring Unit’s State of the Market report for the third quarter to the Installed Capacity/Market Issues Working Group. “To the extent that you’re meeting reliability needs through out-of-market actions, you’re not providing efficient market signals for investment to meet those needs.”

For the second consecutive quarter, capacity costs constituted the majority of New York City’s all-in prices (62%), because of an increased locational minimum installed capacity requirement (LCR) and very low energy prices, he said. (See “Pandemic Reduced NYC Load by 11%,” NYISO Q2 Energy Prices, Load at 10-Year+ Lows.)

All-in prices ranged from $22/MWh in the North (Zone D) to $69/MWh in the city (Zone J). Prices were up in Zones A-F (1 to 11%) and in the city (21%), but down 18% in the Hudson Valley (Zone G) and 6% in Long Island (Zone K).

Average natural gas prices fell 15 to 24% from a year ago, resulting in the lowest quarterly average price for a third quarter since at least 2009.

Average load fell slightly, but peak load also rose slightly. The COVID-19 pandemic may have reduced average load by about 3% for the quarter, the MMU said. Load reductions were largest in the city (6%), while many other regions saw increased load for the quarter, such as 2% in Long Island.

Nonetheless, load levels were comparable to levels in the same period a year ago as warmer summer weather largely offset the effects of the pandemic, the MMU said.

OOM a High Priority

“In New York City we saw out-of-market commitments daily to maintain adequate reserves to satisfy N-1-1-0 criteria for some of the 138-kV load pockets as well as for the 345-kV system,” LeeVanSchaick said. “Again, that’s important because those are some of the same areas where reliability needs are being identified by [NYISO], as well as where you have byway deliverability bottlenecks that could make it harder for generation to interconnect in certain areas.”

NYISO has greatly reduced the use of OOM actions to manage congestion in upstate New York over the last two years by modeling most 115-kV transmission constraints in the day-ahead and real-time market models, he said.

In New York City, some local reliability needs are met by Consolidated Edison making manual commitments. In other cases there are constraints in NYISO software that cause a resource to be committed OOM but do not result in prices reflecting local grid needs. So, “it’s not that the NYISO doesn’t see the constraint; it’s that there is no local reserve requirement that sets a clearing price that can be paid to all resources for providing local reserves, so you have to commit something out of market,” LeeVanSchaick said.

Bid production cost guarantee (BPCG), or uplift, payments totaled $20.6 million, up 16%; 26% of BPCG payments were to New York City units, and 63% were to Long Island units, for local reliability needs, the MMU said.

The report lists modeling reserves dynamically and having local reserve requirements to reflect N-1-1-0 criteria as high-priority recommendations.

“Without meeting these requirements through the market, as opposed to out-of-market actions, it’s going to be really difficult to get people to invest in resources that have flexible characteristics and are located in the right areas where they’re needed most,” LeeVanSchaick said.

Mapping Congestion

Day-ahead congestion revenues totaled $84 million, down 34% from a year ago, primarily because of lower gas prices, the report said. Congestion fell by nearly 42% in New York City from the prior year.

But Long Island accounted for the largest share of congestion (33%) this quarter, up 69% in the day-ahead market ($11.4 million) and 11% in real-time ($2.2 million) from a year ago. Load increased on Long Island, with higher residential cooling needs from the pandemic and the hotter-than-normal summer weather.

“The system congestion map indicates that eastern Long Island has a lot of areas that don’t have natural gas service,” LeeVanSchaick said. “The generation in the eastern half of Long Island is in large part higher-cost than in other areas.”

Looking ahead is challenging, he said, because lower NOx limits will take out some generators in the Astoria and LaGuardia areas of Queens, which support areas to the east where there aren’t many generators. That will lead to some reliability needs starting in 2023 that could be met through some other generation or transmission. A similar situation in the Greenwood Heights area in Brooklyn will lead to reliability issues beginning in 2025, he said.

December 10, 2020

State Decarbonization not on Track, Study Says

States that have set goals to reduce greenhouse gas emissions have yet to implement sufficient policies to meet their pledges, the Environmental Defense Fund said in a study released Wednesday.

Twenty-five states and Puerto Rico, which have pledged to meet the U.S. commitment under the Paris Agreement on climate change, are on a trajectory to reduce emissions by about 18% below 2005 levels by 2025, well below the 26 to 28% reduction promised, EDF said.

EDF study — EDF’s study focused on 25 states and Puerto Rico, which have made commitments to reduce their carbon emissions in line with the Paris Agreement. | *EDF*

Based on emissions data from Rhodium Group, the study included Puerto Rico and 24 states that created the U.S. Climate Alliance after President Trump announced his intention to withdraw from the 2015 international agreement. It also included Louisiana, whose governor separately announced the state would meet the 2025 Paris target and eliminate net emissions by 2050.

EDF said the gaps are even larger when compared with the reductions the U.N. Intergovernmental Panel on Climate Change (IPCC) says are needed to avoid the worst consequences of climate change. The study said the states and Puerto Rico are on track to reduce emissions by only 11% from 2010 levels by 2030, rather than the 45% IPCC says is needed.

“While many states have taken important steps on climate, they are not moving fast enough to turn commitments into the policies that will lock in the needed reductions in pollution,” said Pam Kiely, EDF’s senior director for regulatory strategy. “Making a climate commitment is only the starting point — not the finish line. Even under a new president with a meaningful climate agenda, state policies are essential for securing significant and immediate reductions in climate-warming pollution. … It’s also time for states that haven’t made a climate commitment to join the effort.”

EDF’s study recommended the establishment of declining, enforceable limits on GHG emissions, citing the model of the Regional Greenhouse Gas Initiative. It also said a well designed carbon price “can enable much greater ambition by securing the most cost-effective reductions, jumpstarting innovation and accelerating early action.”

“Regardless of the specific suite of policies deployed, it is imperative that states focus on the targets they have set, acknowledge their current emissions gaps and take action to achieve quantifiable reductions in pollution needed to limit warming over the coming decades,” EDF said.

The study cited New Mexico Gov. Michelle Lujan Grisham (D) as setting a good example, saying she is “engaging in a robust data analysis, transparently laying out the emissions gap and setting a course to enact comprehensive emission-reduction policies to ensure the gap is closed.”

The study says that although the IPCC has also called for net-zero carbon dioxide emissions by 2050, the amount emitted before that year is also crucial. “Carbon dioxide can remain in the atmosphere for thousands of years, so emissions entering the atmosphere over the next few years will continue to warm the planet for many decades to come,” EDF said. “The earlier we reduce emissions, the better the chance we have at achieving temperature stability at desirable levels.”

December 10, 2020

NERC Standards Committee Briefs: Dec. 9, 2020

NERC’s Standards Committee voted Wednesday to reject the standard authorization request (SAR) for Project 2020-01, submitted by the System Planning Impacts of Distributed Energy Resources (SPIDER) Working Group last December to revise reliability standard MOD-032-1 (Data for power system modeling and analysis).

Wednesday’s meeting represented the second attempt to bring the SAR to the committee for approval, after it was removed from the agenda of last month’s meeting to give members more time to review comments received during the informal comment period that ended Apr. 24. (See “SAR Team Members Sail Through,” NERC Standards Committee Briefs: Nov. 19, 2020.) Following the vote, the SAR will be sent back to the SPIDER group with a written explanation for its rejection.

NERC Standards Committee — NERC’s office in D.C. | © *ERO Insider*

Marty Hostler, reliability compliance manager for the Northern California Power Agency, made the motion to reject. Hostler said he was seriously concerned about the SAR drafting team’s response to the informal comment period — or rather the lack thereof, as the team made no changes to the SAR between the end of the comment period and submitting it for approval. Along with Sean Bodkin of Dominion Energy, who seconded his motion, Hostler said that even though the team was not required to respond to the many negative comments received, it was unacceptable to ignore them.

Representatives from NERC pushed back on the motion unsuccessfully. Howard Gugel, NERC’s vice president of engineering and standards, suggested that industry participation in the comment period was low because the SAR had been endorsed by the Planning Committee, replaced earlier this year by the Reliability and Security Technical Committee (RSTC).

“I would not state that just reading the comments … necessarily indicates that industry is not in support of it,” Gugel said. “[My] opinion is that [because] the RSTC endorsed it, they felt that they didn’t need to comment on it.”

NERC’s Chris Larson, who served on the SAR drafting team, added that it did take note of the comments but saw no need to revise the SAR, as it expected to be given “appropriate flexibility” to address the concerns after being made the standard drafting team (SDT). This argument did not convince the committee, however. Hostler said there was no good reason for delay when the team knew action would be needed eventually, while Robert Blohm of Keen Resources said this logic created a mechanism by which “you could avoid rejecting any SAR.”

“You could say, ‘Well, yeah, there’s a lot of opposition, but trust us, we’ll take care of it … when we have to do the drafting,’” Blohm said. “[It] kind of lessens the impact of the whole SAR development process.”

Smoother Road for Project 2020-04

Hostler raised a similar objection to the SAR for Project 2020-04 (Modifications to CIP-012), asking that the drafting team be given more time to revise the document in reaction to concerns raised in its informal comment period, which ended in May. This time he failed to gain support, however, with Bodkin noting that industry comments in this case were not as negative or numerous as those received for the Project 2020-01 SAR. Bodkin’s motion to approve the SAR and appoint the SDT passed.

Bodkin also successfully moved to accept the recommendation of NERC’s Standards Efficiency Review project to review the ERO’s reliability standard template. The evaluation will be carried out by the Standards Committee Process Subcommittee (SCPS) — which Bodkin chairs — and is intended to “ensure the template facilitates a systematic approach to developing an effective and efficient results-based standard.” The SCPS will also review SDT training modules and reference manuals to remain consistent with changes to the template.

PMOS Charter Change Questioned

The committee agreed to revise the scope document for the Project Management and Oversight Subcommittee (PMOS), primarily intended to “allow for better alignment” with the committee’s charter.

Bodkin questioned Charles Yeung, executive director for interregional affairs at SPP and chair of the PMOS, about a note added to the new charter that meetings are open to any interested parties, “subject to any preregistration meeting requirements included in the meeting announcement.” He worried that this might discourage industry participation in NERC, though Yeung suggested that the benefits could outweigh this risk.

“[As] a chair in a meeting, if somebody didn’t preregister [and just walked in], wouldn’t you want to be able to turn them away?” Yeung asked.

“Nope. As the chair of the SCPS, if somebody comes in, if they’re an interested party in the subject matter and they want to participate, I would definitely invite them,” Bodkin replied. “[If], say, somebody just came in to heckle, I could eject them under the professional conduct policy that we have. But I would not want to prevent somebody who actually has a vested interest from coming in just because they didn’t register.”

Others pointed out that the Standards Committee charter itself contains identical language in its section on meetings. Gugel said this wording is not intended to discourage participation but to comply with security restrictions that hosting entities might have in place; for example, some companies require background checks for anyone entering their premises. The new charter, including the questioned language, was approved by the committee.