Page 985 – RTO Insider

February 9, 2021

PG&E Files Wildfire Plan Under Intense Scrutiny

Pacific Gas and Electric submitted its latest wildfire prevention plan to the California Public Utilities Commission on Friday as it faces threats of more intensive oversight from the CPUC and a federal judge prior to this year’s fire season.

PG&E said the key to its $3 billion 2021 Wildfire Mitigation Plan is an improved computer system to predict risk more precisely.

“This new technology will allow us to more accurately prioritize our efforts within the highest fire-threat areas,” Debbie Powell, interim head of electric operations, said in a statement.

The updated risk modeling uses historical data on weather patterns, fire ignitions and outages, PG&E said in its plan. It also employs “fire-spread technology that shows the locations where specific infrastructure failures can lead to ignitions that have the highest consequences for our communities.”

That will allow the utility to focus its vegetation management and grid hardening efforts on the top 20% of high-risk circuit segments, the plan said.

The utility’s 2021 targets include installing 300 weather stations to complete its long-term goal of deploying a total of 1,300 weather stations, performing enhanced vegetation management on 1,800 miles of high-risk lines and hardening 180 miles of at-risk lines with covered conductor and stronger poles, among other measures.

Whether the utility’s plans will appease some of its staunchest critics remains in doubt.

‘Maybe Criminally Reckless’

Those critics include U.S. District Court Judge William Alsup, who oversees PG&E’s criminal probation related to the San Bruno gas pipeline explosion in 2010. In a hearing Wednesday, Alsup said he would likely impose new probation terms requiring PG&E to improve its vegetation management and public safety power shutoff (PSPS) practices.

Alsup said he believes the Zogg Fire, which killed four people in September, was likely started by a leaning pine tree that PG&E should have cut down. The line it hit remained energized during a PSPS event to prevent wildfires, even though PG&E had shut down other lines nearby, the judge said. (See PG&E Line Was Active when Zogg Fire Started.)

PG&E Wildfire Plan — Searchers indentified four sets of human remains in the Zogg Fire, including a mother and her young daughter. | *Shasta County Sheriff’s Office*

“I think it was reckless, maybe criminally reckless, for PG&E to have left that tree, that gray pine looming,” Alsup said. “It was leaning at a 60-degree angle over that line. Gray pines … have a shallow root system. That tree had also been burned earlier. That tree was a clear and present danger to the line, and whoever made the decision to leave that tree up should be looked at very carefully. And PG&E did leave it up.”

One new probation condition proposed by Alsup would require PG&E to consider whether lines had been cleared of dangerous trees when it decides which circuits to de-energize in PSPS events.

“Here is a fundamental problem I have with the way PG&E is doing this, the judge said. “When you decide on a PSPS and which lines to cut off, just hypothetically take two otherwise similar distribution lines. One is one that has been fully worked and is in full compliance with state law and [CPUC requirements]. The other is one that has not been worked at all. Your approach does not distinguish between those two.”

PG&E’s risk assessment and PSPS decisions consider weather patterns and historical wildfire data, the judge said. It stands to reason, however, that a line that has not been fully worked presents more of a danger than a line that has been cleared of problem trees, he said.

“The conditions that I’m requiring, or at least that I would propose to require, I believe would have saved those four people’s lives” in the Zogg Fire, Alsup said. Among the victims were a mother and her 8-year-old daughter who died fleeing the flames.

PG&E lawyer Kevin Orsini acknowledged the judge’s point but said the utility’s current approach “indirectly” factors tree trimming into its PSPS decisions. The utility wants the judge to soften his proposed conditions.

If “you take into account whether or not the line has been worked, that wouldn’t have had a different result with respect to the Zogg Fire,” Orsini said. About 1,000 trees in the area had been removed based on the recommendations of three foresters, but not the tree that may have started the fire, he said.

Alsup said he would entertain arguments to amend the probation conditions. The next hearing on the matter is scheduled for March. 9. But he ended Wednesday’s hearing by saying that since the San Bruno explosion, “PG&E has been a terror … to the people of the state of California.” With one more year left to oversee PG&E’s criminal probation, Alsup said he intends do all he can to change the utility’s safety culture.

“In this last season, I want you to do this right,” Alsup told Orsini.

CPUC to Weigh in

The California Department of Forestry and Fire Protection (Cal Fire) has yet to determine the cause of the Zogg Fire. Last year Cal Fire investigators seized PG&E equipment and a section of a gray pine in its investigation.

PG&E has told the U.S. Securities and Exchange Commission it expects to pay victims at least $275 million in damages for the fire, which destroyed more than 200 structures and burned over 56,000 acres.

Shasta and Tehama counties, where the Zogg Fire occurred, have sued PG&E in state court, and the Shasta County District Attorney’s office is investigating whether criminal charges are warranted.

If PG&E is found to have caused the fire, it would be the fourth year in a row that the utility’s equipment started a catastrophic blaze. The company was blamed for the wine country fires of 2017, the Camp Fire of 2018 — the deadliest in state history — and the Kincade Fire in 2019. The fires killed at least 111 people, destroyed 22,627 homes and other structures and burned approximately 500,000 acres.

In addition to Alsup, the CPUC has been trying to get PG&E to end its streak of death and destruction.

In November, CPUC President Marybel Batjer told PG&E that it could face a stricter regimen of oversight and enforcement because of concerns about its line maintenance. (See PG&E Faces ‘Enhanced Oversight’ by CPUC.)

“My concerns arose from what appears to be a pattern of vegetation and asset management deficiencies that implicate PG&E’s ability to provide safe, reliable service to customers,” Batjer wrote to the then acting CEO Bill Smith, citing Alsup’s findings.

A bill signed by Gov. Gavin Newsom in July requires PG&E to submit to greater scrutiny by the CPUC and potential state control for repeated and uncorrected safety problems. Under the terms of the law, the CPUC can appoint a third-party monitor, followed by a receiver, and eventually rescind PG&E’s license to operate as the monopoly utility for most of Northern and Central California.

The CPUC has three months to approve PG&E’s wildfire mitigation plan, which is set to take effect in June, shortly before the state’s summer-and-fall fire season typically starts.

February 9, 2021

FERC Rejects GridLiance Local Tx Planning Proposal

FERC last week rejected GridLiance High Plains’ proposal to conduct local transmission planning for nonpublic SPP utilities outside of the company’s service territory (ER20-3025).

The commission found in its Feb. 2 order that GridLiance’s proposal to perform the service for “transmission-dependent nonpublic utilities (TDNPUs)” would contradict its rules on local transmission planning, “which obligate the transmission provider to plan for the needs of transmission customers in its individual retail distribution service territory or footprint.”

GridLiance’s proposal would have allowed a transmission customer to conduct its own competing local transmission planning, FERC said, contrary to Order 890’s transmission-planning obligations. The commission disagreed with the company’s contention that its proposal would not give TDNPUs more rights to plan and develop local transmission facilities than they already have.

FERC said that while Order 890 requires that transmission customers “be allowed timely and meaningful input and participation into local transmission planning, it did not provide that transmission customers could establish their own transmission-planning processes and did not require that transmission customers be allowed to plan on a coequal basis with transmission providers.”

The commission said GridLiance’s proposal could not constitute a “local transmission-planning process” as defined by Order 1000 because the company would be performing planning outside of its own retail distribution service territory or footprint. Local transmission facilities resulting from the proposal would not meet the order’s definition of a “local transmission facility” because the facility would be located outside of GridLiance’s service territory or footprint.

FERC also found SPP’s tariff “does not contemplate third parties conducting competing local transmission-planning processes for customers within another transmission provider’s service territory or footprint,” noting the RTO does not have processes “designed to resolve different outcomes arising from the competing processes.”

“Without a clear system in place to resolve different outcomes arising from competing local transmission-planning processes, GridLiance’s proposal could increase conflicts and litigation … in SPP,” the commission said.

GridLiance, which collaborates with municipal utilities, joint action agencies and electric cooperatives to address transmission needs, disagreed.

“We are obviously disappointed,” GridLiance High Plains President Brett Hooton said in an email to RTO Insider.

He pointed to Commissioner Allison Clements’ concurrence with the order, saying, “Inadequate transmission planning is at the root of many of the problems leading to less reliable service for TDNPUs. As Commissioner Clements noted, reform is needed for more effective local transmission planning, including ‘mechanisms to address barriers to participation’ in local transmission-planning processes.”

In her concurring statement, Clements noted the grid has undergone “significant transformation” since Order 890 was issued almost 15 years ago.

“Consideration of reform to local planning processes is appropriate as part of broader transmission planning reform, to ensure that TDNPUs are given fair and adequate service,” she wrote, “and more broadly to ensure that all transmission system plans — local, regional and interregional — succeed in identifying cost-effective solutions to established system needs and thereby ensure that any new infrastructure is money well spent by customers.”

Clements said mechanisms similar to GridLiance’s proposal “may be appropriately considered as part of a broader discussion on transmission planning reform.”

“We perform transmission planning for our utility partners and believe our local planning process expansion would benefit other TDNPUs,” Hooton said. “While FERC didn’t accept our proposed solution in this case, we will continue our efforts to address inequities in transmission service to, as described by Commissioner Clements, ‘ensure TDNPUs are given fair and adequate service.’”

FERC offered a potential alternative, saying TDNPUs could always contract with GridLiance and other entities to study their local transmission needs and potential projects to address those needs, using that information to “inform their participation in the existing local and regional transmission planning processes.”

GridLiance said it had already executed planning agreements with three TDNPUs: Kansas Power Pool, Oklahoma Municipal Power Authority and Tri-County Electric Cooperative. It said that while it currently can conduct transmission planning outside of its local planning process, there is not a clear process for including identified transmission projects in the SPP process.

Western Farmers Electric Cooperative and Xcel Energy Services, on behalf of Southwestern Public Service Co., protested in the docket, arguing the proposal lacked sufficient detail regarding coordination with the incumbent transmission owner’s local planning process; that it would result in duplicative planning efforts; and that it did not explain how inconsistent planning results would be resolved.

February 9, 2021

NERC: Need to Prepare for Battery Growth

NERC on Monday called for the creation of a task force to ensure grid planners are prepared for the coming surge in battery storage, which is expected to double to 4 GW by 2023.

The ERO said the task force should be formed by the Reliability and Security Technical Committee (RSTC) and should study “the forward-looking implications” of battery energy storage systems (BESS) and their impact on bulk power system reliability and resilience.

The directive comes in a new report, “Impacts of Electrochemical Utility-Scale Battery Energy Storage Systems on the Bulk Power System.”

NERC Battery Storage — U.S. operating utility-scale battery storage by state | *NERC*

“As we continue to assess the implications created by the integration of cutting-edge technologies to the electrical grid and the increasing amount of projected battery storage in the future, industry and regulators must pay more attention to bulk power system-connected battery energy storage systems,” said Thomas Coleman, NERC’s chief technical adviser of engineering and standards.

The report, which focused on standalone BESS and hybrid resources — BESS connected with solar or wind — also recommended that:

system planners prepare for an increase in the “critical mass” of battery storage and ensure that it provides the essential reliability services to maintain BPS reliability, security and resilience. Planners must understand the impact of battery size, location and operating characteristics on maintaining reliability, NERC said, as well as batteries’ value as a complement to variable wind and solar resources.
planners conduct studies to determine the dynamic stability impacts of interconnecting battery storage and its ability to provide capacity to meet long-term and contingency reserve margin requirements.
entities reporting on batteries use consistent metrics and improve both their data and their reporting methods. “As energy storage systems become more prolific, accurate and timely data will be essential for both system planners and operators. The Institute of Electrical and Electronics Engineers (IEEE) should update the IEEE Standards to reflect any implications of battery storage systems,” it said. “The GADS Working Group should ensure that battery storage is accurately reflected in their data capturing protocols.”

U.S. BPS-connected battery energy storage power capacity (July 2020) | NERC

It concluded that existing reliability standards “adequately reflect battery storage as a generator, ensuring that the NERC TPL and MOD standards are applicable to the current number of BESS on the BPS.” But it called for a “gap analysis” to identify changes that will be needed in the future from both the growth of BESS and its additional functions.

Uses

Operating reserves and ancillary services (frequency regulation and voltage support) represent the lion’s share of BPS-connected storage capacity, with smaller amounts used for energy arbitrage, peaking capacity, black start and deferrals of transmission and distribution upgrades.

NERC recently conducted a joint study with WECC that highlighted the ability of BESS to provide fast frequency response (FFR) to avoid using under-frequency load shedding (UFLS) in response to generation losses. The study found that strategically located BESS provide effective FFR to avert UFLS.

“The team found that by altering the size of the BESS at different locations, it was able to inject power to arrest the frequency nadir,” NERC said. “While the location of this injection generally did not matter in relationship to interconnection-wide grid support, certain local stability problems may be exacerbated or resolved solved by using this BESS capability.”

Growth

The U.S. and Canada currently have 37.5 GW of storage capacity, 90% of it pumped hydro. Of the remaining capacity, more than half is lithium-ion batteries, which have matured because of their use in electric vehicles. “There are many electricity storage technologies at or near commercial viability with many more at various stages of development,” NERC noted.

The U.S. Department of Energy projects that 35% of the nation’s energy will come from wind (404 GW) and 27% from solar PV (632 GW) by 2050. BloombergNEF projects worldwide energy storage installations (including EVs but excluding pumped hydropower) will grow from 9 GW in 2018 to 1,200 GW of lithium-ion batteries by 2050. The U.S. is adding storage faster than any other country.

The largest battery in the U.S. is expected online later this year: Florida Power and Light’s 409-MW/900-MWh Manatee Energy Storage Center, which will pair storage with solar. Last April, Southern California Edison inked the nation’s largest-ever purchase of battery storage: 770 MW/3,080 MWh.

The top four states with facilities operating or under construction are California, Illinois, West Virginia and Texas, representing more than half of the total installed battery storage in the U.S.

Hybrids

According to the Energy Information Administration, the number of hybrid renewable-BESS rose from 19 in 2016 to 53 in 2019 and will double by 2023.

EIA says nine states comprise 90% of the operating hybrid capacity in the U.S., with Texas holding 46% of the total. “Although nearly 25% of the total United States battery capacity is installed as part of a hybrid system, only 1% of total wind capacity and 2% of total solar capacity is part of a hybrid system,” NERC said.

An ERO working group is currently drafting guidance on the application of the bulk electric system definition to BESS and hybrid resources and how owners of such facilities will have to register them.

February 9, 2021

SolarWinds Recovery May Require Extreme Actions

Large-scale replacement of computer systems “may be the only option” for some users of SolarWinds, FERC’s Joseph McClelland told NARUC attendees.

Large-scale replacement of computer systems “may be the only option” for some users of the compromised SolarWinds Orion network management software to ensure there are “no footholds left for an adversary to drill into the network,” according to Joseph McClelland, director of FERC’s Office of Energy Infrastructure Security.

“I’d say that absolutely is a possibility. We really don’t know the full extent,” McClelland said in a panel at the National Association of Regulatory Utility Commissioners’ Winter Policy Summit last week. “The number is growing, [and] we really don’t know how many other systems our adversary was able to burrow into.”

Orion’s Massive Reach Aided Hack

About 18,000 public- and private-sector organizations are confirmed to have been impacted by the SolarWinds compromise, according to a joint statement issued last month by the FBI, the National Security Agency, the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) and the Office of the Director of National Security (ODNI). The Department of Energy and FERC were among the entities affected. (See FERC Pushes Cybersecurity Incentives.)

However, as McClelland implied, those numbers may not reflect the full extent of exposure. While the breach was first reported by U.S. cybersecurity firm FireEye in December 2020, the attackers — “likely Russian in origin,” according to the agencies’ statement — are known to have inserted a backdoor into updates for the Orion platform published as early as March 2020, if not before. As a result the hackers had an open window into victims’ information technology networks for nearly nine months before any effort was made to stop them.

Compounding the issue is the market dominance of Orion, which is used by “almost everyone” with a large corporate network and “has to know everything about the network to work,” according to McClelland. The insertion of the breach into official updates for the software allowed it to disseminate quickly among SolarWinds’ huge global customer network.

Finally, although SolarWinds has developed a patch for the software that removes the malicious code, the hackers’ long period of unobstructed access allowed them an intimate look at both the application itself and its update process. As a result, simply applying the patch is only the first step in safeguarding the system, and the extent of required actions may not be known for some time.

“It is likely that the adversary is in a strong position to identify any potential (and as yet unknown) vulnerabilities in the SolarWinds Orion code that are unrelated to the inserted malicious code and may therefore survive its removal,” CISA warned in its emergency directive on the breach.

Federal Breach Response Draws Praise

The extent of the breach highlights the importance of cooperation between private industry and government cybersecurity experts, McClelland said — echoing assessments from other observers since the discovery of the hack. (See Panel: Industry Dialogue Key to Cyber Resilience.)

In particular, he emphasized the quick response of CISA and other federal agencies in setting up its alert for the breach within four days of the FireEye report, noting that “DHS did outstanding work on this.” The alert allows the agency to provide detailed information on every aspect of the attack, including methods for detecting compromised code; newly discovered attack vectors, including Microsoft 365 and Azure applications; and possible mitigation measures, from software patches to complete rebuilds of affected networks.

McClelland also praised the quick work of the National Security Council in setting up a unified coordination group (UCG) by Dec. 15, two days after the breach was discovered. The UCG is composed of the FBI, CISA and ODNI with participation by the NSA, and is tasked with coordinating all relevant federal agencies to investigate and remediate the attack.

“If it’s something as big as SolarWinds, we’re all involved. We’re all meeting at least weekly, and we’re meeting at the highest levels to exchange classified information and to understand exactly where we are and how to better deploy it,” McClelland said.

This massive joint effort is aided by the supportive relationship between both management and ground-level staff at the various groups working to secure critical computer networks.

“I’ve known Bob for years; I consider him a friend and colleague,” McClelland said, referring to Robert Kolasky, assistant director at CISA’s National Risk Management Center, who also took part in the panel. “I can pick up the phone and call him any time; he calls me at any time; [and] our subject matter experts work together. … I’d say the same thing about the states too — [we have a] great relationship with the states, with [NARUC]. And I feel like I can pick up the phone at any time and call any of the members.”

February 9, 2021

Building Resilience: From Pilots to Policy

Although grid resilience has become an increasing concern for regulators, their efforts have been reactive, resulting in pilot projects but no consistent policies or metrics for measuring success, speakers told the National Association of Regulatory Utility Commissioners’ Winter Policy Summit on Thursday.

“We haven’t found any commission in the country that has a comprehensive framework and long-term plan for what resilience means and what [level of resilience] are we trying to get to,” said Ted Ko, vice president of policy and regulatory affairs for Stem, which operates what it says is the world’s largest energy storage network.

To address that, Ko co-authored a policy roadmap on resilience, with a focus on using solar-plus-storage technology for backup power following natural disasters and outages.

Ko was joined by Bill Chiu, managing director of grid modernization and resiliency at Southern California Edison (SCE) and Damir Novosel, president of Quanta Technology, who outlined an October 2020 report they co-authored with other members of the IEEE Power and Energy Society titled “Resilience Framework, Methods, and Metrics for the Electricity Sector.” The session was moderated by New Hampshire Public Utilities Commissioner Kate Bailey.

“We’re seeing more and more of these so-called traditionally low-frequency events becoming more frequent and in greater intensity, and some of it’s obviously driven by climate conditions,” Chiu said. “So, moving forward … the resilience definition should be able to deal with protection against any kind of events that would have a significant impact to the grid.”

The IEEE report says regulators should take an “all hazards” approach that considers threats from hurricanes, wildfires and other natural disasters; cyber and physical attacks; aging equipment; and human error. That, Chiu said, takes “advantage of the commonality of the recovery process — regardless of the type of event that we have. … Regardless of whether you’re talking about severe weather events or other types of system trauma, there is going to be these five stages we need to consider: prevention, protection, mitigation, response and recovery. The whole idea here is to actively collaborate with key stakeholders to continuously mature what I call the resilience muscle … so that we get better at each one of these phases.”

The IEEE report identifies varying definitions of resilience and its relationship with reliability, along with metrics for evaluating and benchmarking it.

“Measures that help to improve reliability also increase the resilience. But there are times when there will be some opposing tradeoffs,” Chiu said. For example, the practice of reclosing power lines after faults could harm resilience by allowing lines to ignite foreign debris during wildfire season.

Novosel talked about technologies and methods for improving resilience, including improved power system modeling; sensors; use of outage reporting smart meters and monitoring for geomagnetic induced current; and drones for situational awareness and assessing conditions. “Our smart meters have not been fully utilized in the industry yet,” he said.

Smart inverters for controlling distributed energy resources, combined with energy storage, energy efficiency and demand response can allow customers to island via microgrids during disturbances. “The more renewables and storage we have, the more expansive the microgrid can be,” Novosel said.

He also noted, “Some of the investments in distribution can help the transmission system and the other way around.”

The report also offers recommendations on how to use the metrics and includes case studies from, among others, SCE, Con Edison, San Diego Gas & Electric, Commonwealth Edison and Austin Energy. Transmission and distribution system hardening practices and wildfire risk mitigation are covered in a section on lessons learned from California.

Florida utilities responded to hurricanes in 2004 and 2006 by undergrounding some lines and hardening others by replacing wooden transmission and distribution poles with concrete and steel structures able to withstand 145-mph winds, investments that have greatly reduced outages. Novosel said Entergy is now considering how to replace a line near the Gulf of Mexico that was destroyed by high winds during Hurricane Laura last August.

“There’s a question now: Should we rebuild the line, or should we put in a microgrid? And how to find the balance to minimize the risk … at the same time moving toward decarbonization?”

“There will be the issue of the level of investments that would need to be made. Should it be reached in three years, in five years?” he continued. “That’s where … probabilistic planning comes in very handy because we still have uncertainties that we need to include in the process.”

Making Resilience a Market

The Stem report takes note of efforts by regulators in New Jersey, New York, Maryland, Connecticut, Massachusetts, and Rhode Island to determine the costs and benefits of solar-plus-storage microgrids and backup power. The studies were followed by investments in backup power pilots for critical facilities such as hospitals, water treatment facilities and public shelters.

While the pilots have effectively proven the value of such investments, Stem said, “comprehensive policy support is now needed to scale implementation. Even among states most at risk of outages, the current policy landscape is a piecemeal collection of pilot projects, small grant programs, and catastrophe response — not a systematic and proactive approach to ensuring widespread energy resilience for all.”

It cites the California Public Utilities Commission, which is providing incentives for commercial and residential customers adding clean backup power under its Self-Generation Incentive Program. (See California PUC Devoting $1.2B to Self-generation.)

The program hasn’t worked exactly as intended, however. In October, the CPUC reported that much of the $612 million intended to provide battery backup to homes in high fire-threat areas has been taken by customers who use electricity to pump well water instead of helping the low-income and medically vulnerable residents it was meant for. (See PSPS Relief Funds Not Spent as Intended, CPUC Says.)

The report calls for developing a framework that defines resilience components, classifies customers according to resilience needs and recommends policy and market mechanisms to address possible scenarios.

It says states should strive to gradually eliminate subsidies and develop market mechanisms that allow stakeholders to analyze the costs and benefits of potential resilience projects and invest in those that are most cost-effective. Ultimately, microgrids and other projects for resilience should be included in integrated resource plans and distributed resource planning, it says.

February 7, 2021

MISO Focusing on Forward Info for Long-lead Units

MISO said last week that it is seeking ways to help slow-starting units make more informed commitment decisions but won’t plunge into developing a financially binding forward market anytime soon.

Senior Market Engineer Chuck Hansen said the RTO is using the umbrella title “enhancements for long-lead units and self-commitments” instead of forward market mechanisms.

“There’s really no acronym for this,” he said. “We can think of this as understanding information ahead of the day-ahead market.”

The effort may include new price forecasts and allow longer run times.

MISO is exploring the market system and settlement impacts of allowing unit owners to increase their minimum run times from the current 24-hour limit, Hansen said.

MISO Long-lead Units — Carmel, Ind. control room | *MISO*

The grid operator is also investigating using a vendor to produce multiday price forecasts on future locational marginal prices.

“There’s no ISO that does this,” Hansen said. “The question is, if MISO works with vendors, could it produce a better price forecast than what vendors can do with publicly available information?”

He said this year MISO will issue requests for more information from vendors to see what would be involved in generating such a forecast.

The grid operator is also considering publishing the additional 12 hours of its commitment engine results as a heads-up for operators. The RTO currently publishes only the first 24 of the 36 hours of data computed by the commitment engine. The additional 12 hours would be considered strictly advisory in nature.

Hansen said MISO will devote time to improving its existing multiday operating margin forecast. The RTO late last year began publishing a first edition of its multiday operating margins, which predicts supply conditions six days in advance. The multiday forecast is intended for informational purposes only and is not a multiday financial market.

Hansen said MISO could incorporate seven days of renewable forecast information at the subregional level into the multiday forecast. In the future, it could break renewable predictions down to local resource zones or local balancing authorities, provided the forecasts don’t reveal market participants’ private information.

The multiday forecast could also include color-coded reliability targets, emergency resource availability and amounts of must-run committed capacity, Hansen said.

MISO is also considering putting more of the onus on its members and may require them to make a “reasonable effort” to give the grid operator more notice on offers, schedules and when units can return from derates or outages.

Hansen said none of the ideas are final, and MISO is doing more research to discern which ones are the most helpful and feasible. He said he would return to a future Market Subcommittee meeting to discuss the RTO’s inclination.

February 7, 2021March 9, 2025

RTOs Planning to Ride Energy Storage Wave

Faced with varying waves of energy storage resources (ESRs), grid operators are taking steps to accommodate the devices that are — for now — mostly sitting in their interconnection queues.

“We can debate the timing and the speed with what change will come, but one thing is for sure, change is coming,” Renuka Chatterjee, MISO’s executive director of system operations, said during the Energy Storage Association’s virtual Policy Forum last week.

Clockwise from top left: Jason Burwen, ESA; Sandip Sharma, ERCOT; Greg Cook, CAISO; Michael DeSocio, NYISO; Bruce Rew, SPP; and Renuka Chatterjee, MISO. | ESA

Chatterjee said MISO has 9 GW of energy storage, split between stand-alone resources and hybrids, in its queue. CAISO had more than 69 GW of ESR projects in its queue as of last July, topping all other RTOs and ISOs. PJM is second with more than 33 GW of capacity while ERCOT has more than 26 GW of storage resources that have requested at least a screening study. ISO-NE, NYISO and SPP have between 3 GW and 9 GW in their queues.

All of which belies a 2020 study by the Lawrence Berkeley National Laboratory and the Electric Power Research Institute that found RTOs and ISOs had, at the time, 69 GW of storage capacity sitting in their queues.

Nearly 500 MW of new ESR projects were installed during the third quarter of 2020 alone, according to a Wood Mackenzie report. With technology continually improving and prices dropping, the research firm expects 2021 to be another record-breaking year.

“Almost all of the RTOs are going through an energy portfolio change,” Chatterjee said. “If you look at MISO in particular, almost all of our members have some sort of low-carbon goals or commitments they want to achieve. We’re seeing an increasing change in renewables, particularly with wind and solar. … We’re creating options for energy storage to participate as well.”

MISO has already received FERC Greenlights MISO Storage-as-Tx Proposal.)

Sandip Sharma, ERCOT | ESA

ERCOT has chosen a different approach after finding itself missing the first waves. Sandip Sharma, the ISO’s director of forward market operations, said the Texas grid operator was stuck at around 80 MW of energy storage for several years before it started seeing interest from the “battery community” and fragmented stakeholder discussions.

The ISO formed a task force to figure out how best to integrate ESRs. In December, ERCOT’s Board of Directors approved the group’s recommendations, which included representing storage devices as a single resource in what is called a “single-model” approach. (See ERCOT Board of Directors Briefs: Dec. 8, 2020.)

“We’re trying to ensure battery operations can have access to the market, as well as maintain their state of charge more flexibly,” Sharma said. “For ESRs to maintain their state of charge, they have to continue to be able to update their energy offers, because the energy offers are constantly changing.”

The new protocol language allows ESRs to decide whether to supply energy at a certain price point or provide ancillary services, Sharma said.

‘The Future That is Coming’

With just one ESR in its 17-state footprint, SPP is playing catch-up as well. The RTO has almost 9 GW of ESRs in its interconnection queue, which is clogged with nearly 78 GW of wind and solar resources under some form of study.

Bruce Rew, SPP | ESA

“Our GI queue is backlogged. We’re working to clear that but once we do, we will see a lot of ESRs coming online,” said Bruce Rew, SPP’s senior vice president of operations.

The RTO has tasked an ESR steering committee to coordinate and oversee the various stakeholder groups working on 37 different storage-related initiatives spread over six issue buckets.

“The key thing is we’ve looked at the load-carrying capability of the [ESRs], how we can increase that into our market and use it effectively from a market operations standpoint,” Rew said.

“Getting it right is the key thing for SPP,” Rew said. “ESRs continue to add complexity to our market. Let’s get some experience using ESRs as transmission first, then as an energy resource. We certainly have a lot ahead of us.”

Manu Asthana, PJM | ESA

PJM CEO Manu Asthana said PJM is similarly focused on preparing for a future grid where “energy storage is a meaningful part.”

He said the RTO is working with its stakeholders to draft rules that create access to distributed generation, a result of FERC Order 2222, and reform its interconnection queue practices. Both initiatives will enable further integration of ESRs, Asthana said.

“We want durable decisions that are supported by a supermajority of our stakeholders. PJM is committed to creating a level playing field for all resources, including storage,” he said.

Greg Cook, CAISO | ESA

CAISO’s storage capacity was approaching 1 GW by the end of 2020, and it has projected 15 GW will eventually be necessary to help reach California’s goal of 100% carbon reduction by 2045. Greg Cook, the ISO’s executive director of market and infrastructure policy, said he expects 3.3 GW, primarily hybrids, to come online in the next couple of years.

“New storage is being added to existing solar sites,” he said.

The ISO is operating under a new resource adequacy provision, Cook said, “as ensuring ESRs are available to be discharged when needed to meet the needs of that next peak load in California can be a challenge.”

“We do plan to have a policy catch-up where we can make multiple uses of those [storage] markets and have triggers for when they’re allowed to be in the market,” he said. “Ultimately, that’s the more efficient way to go.”

NYISO’s Michael DeSocio, director of market design, said his grid operator has embarked on the next phase of accommodating storage — valuing the resources based on their accredited capacity — following FERC’s August acceptance of tariff revisions that subject ESRs to transmission charges. (See NYISO’s 2nd Storage Compliance Almost Hits Mark.)

“There is a huge transition happening,” DeSocio said. “We’re making sure we’re ready for the future that is coming.”

February 7, 2021

NY Builds OSW Ports in Brooklyn, Albany, Long Island

New York offshore wind developers have begun constructing the port facilities needed to build and operate their projects after the state completed the nation’s largest wind procurement last month.

With the state’s 2.5-GW award to Equinor in January, New York has contracted nearly half of the 9 GW targeted for construction by 2035. Equinor and its partner, BP, will develop an additional 1,260 MW for their Empire Wind project in the New York Bight in addition to 1,230 MW for Beacon Wind, to be situated 60 miles east of Montauk.

The contract commits Equinor to develop the Port of Albany for tower manufacturing, including using the nearby Port of Coeymans for turbine foundation manufacturing, and to transform the South Brooklyn Marine Terminal (SBMT) into an assembly and operations and maintenance hub. (See NY Awards 2.5-GW Offshore Deal to Equinor.)

Partners Ørsted and Eversource Energy are building an operations and maintenance base at Montauk Harbor for the 132-MW South Fork Wind project. The companies are also developing a similar O&M base at Port Jefferson for their 816-MW Sunrise Wind project, as well as a facility in nearby East Setauket to serve both projects. (See BOEM Sees Moderate Impacts from South Fork OSW Project.)

For the Port of Albany, the developer has contracted with Marmen, a Quebec-based onshore wind turbine manufacturer, and Welcon, a Denmark-based manufacturer of OSW towers.

“That’s the premise of the Port of Albany, to combine one large manufacturer from Europe and another one from Quebec, who’s done more onshore than offshore, with the port itself in developing the site and the fabrication for towers and transition bases,” Anders Hangeland, Equinor head of East Coast development, told RTO Insider. “That’s bringing the best of prior experience in North America with the offshore experience from Europe in those two suppliers.”

“The offshore wind projects will furthermore leverage almost $3 of private funding for every $1 of public funding for a combined $644 million investment in resilient port facilities in the Capital Region and Brooklyn,” NYSERDA CEO Doreen Harris said on Wednesday as she announced the release of the agency’s 2021 Strategic Outlook.

A Fluid Process

Ports like SBMT and Albany had long been on the state’s radar as potential ports, Michael Lee, president of environmental planning and engineering firm AKRF, told RTO Insider. Lee’s firm spearheaded a project to make Port Cortlandt an OSW hub to use some of the industrial waterfront property near the imminently closing Indian Point nuclear power plant.

New York OSW — Map of the South Brooklyn Marine Terminal being developed by Equinor | *NYSERDA*

“The procurement process had the ports independent of the wind bids, then New York officials merged them last summer and made ports part of the total wind energy bids,” Lee said. “In a COVID world, it was very tough, so those who had an existing relationship were able to pull it together.”

NYSERDA originally said it would provide $200 million in grants toward ports development but changed it to $100 million in grants and $100 million in loans, with the private sector to come up with $444 million.

“All of this stuff is building blocks,” Lee said. “Step one is a port, and … you need to build the towers; you need to build the foundations, and COVID really restricted a lot of the abilities to get people to decide to do things.”

Equinor has not yet selected a turbine supplier, for which the contract doesn’t specify a certain date, but it is a normal part of the development process and the company will make the decision “when it makes sense,” Hangeland said.

“Bringing offshore wind from Europe, where it’s already a well-developed industry, to the U.S., which is an undeveloped area for offshore wind, is a question of how much can you build and manufacture on the East Coast itself, and how much would you need to transport from Europe,” he said.

Do European OSW contracts include similar development clauses?

“Obviously, as you see an industry developing, all the important pieces that make that industry viable develop, so in the beginning you have a bigger need for establishing such incentives,” Hangeland said. “As Europe has become more mature on this, all the different pieces needed to establish an OSW farm are in place, so incentives, whether on local content or on price, have gradually gone down as the industry has matured.”

Location, Location

Lee was impressed that the South Brooklyn Marine Terminal building, a staging facility, is behind a bridge — the Verrazzano-Narrows.

“To date, you’ll see all of the facilities on the Northeast coast or even what they’ve done in Europe, they like to build these things beyond any bridges,” Lee said. “I’ve heard there are videos to show how they can put this stuff on vessels and get it out underneath a bridge.”

Hangeland, however, said the height of barged material had already been considered in the planning, logistics and due diligence.

“If you look at how New York is central to all these markets, the SBMT is important because these are very big pieces of equipment and you can’t transport this stuff hundreds of miles,” Lee said.

Interstate cooperation around New York hasn’t happened like it has in the Mid-Atlantic, where some of the states are coming together, so most of the discussions have been state-by-state, but it was hard to discuss anything last year when “New York was slammed,” he said.

The governors of Maryland, North Carolina and Virginia in October agreed to collaborate to promote their states as a hub for the OSW industry. (See Md., NC, Va. to Team up on Offshore Wind.)

Another positive for the Brooklyn facility is that it’s an open port, so “it can be used for multiple contractors. Towers can be used for multiple contractors. They’re all independent of a particular technology, so I think it’s pretty strategic,” Lee said.

February 7, 2021

ACORE: COVID, Impeachment Could Delay Infrastructure Bill

Congressional wrangling over the size and scope of the COVID-19 relief bill and the impeachment trial of former President Donald Trump could easily push an infrastructure financing bill into the second quarter, imperiling the legislative goals of clean energy industries, the American Council on Renewable Energy warned last week.

“There are only so many times when Congress is going to pass legislation measured in the trillions of dollars, or even hundreds of billions,” ACORE COO Bill Parsons said at the group’s quarterly industry update, which featured a panel discussion about what the Biden administration ought to do to promote renewable energy generation, the grid and electric vehicles.

ACORE Infrastructure Bill — Bill Parsons, ACORE | *ACORE*

“This is an administration that understands the pieces of the puzzle,” Parsons said, noting that the president has already announced a goal to decarbonize the nation’s power sector by 2035, increase offshore wind development and make massive investments in the nation’s transmission system.

Yet, the political distance between the administration’s goals and congressional approval is difficult to measure at this point, Parsons said.

He warned that the wrangling over the pandemic relief bill and Trump’s impeachment could “poison the well” and leave the administration with little “gas in the tank” when Congress takes up infrastructure spending, probably in the spring.

Although there does appear to be bipartisan support for clean energy tax incentives, he said the window for passage could be narrow, noting that both Sen. Raphael Warnock (D-Ga.) and Sen. Mark Kelly (D-Ariz.) face re-election next year. A loss by either could change the balance of power in the Senate, where Republicans and Democrats each have 50 seats.

“We have an almost once-in-a-generation opportunity to enact a stable, predictable, long-term clean energy tax platform this year. That is going to be a priority for us, on top of the infrastructure and transmission” issues, he said.

Despite the split Congress and the pandemic that caused the layoff of more than 400,000 clean energy workers, clean energy begins 2021 in better shape than predicted, BloombergNEF analyst Ethan Zindler said.

“The industry really demonstrated a high degree of resiliency last year. Given that the U.S. GDP contracted by about 3.5% in 2020, I think the performance of the industry is pretty remarkable,” he said, explaining that renewable developers spent about $50 billion on U.S. projects in 2020.

Ladeene Freimuth, president of the Freimuth Group and a senior adviser to the think tank Securing America’s Future Energy, said the nation’s energy situation is “urgent.”

“We are proposing a comprehensive approach that we are calling a ‘Minerals to Markets’ approach. We must act now if we are going to achieve both a clean energy future and a secure energy future and maintain our economic competitiveness,” she said.

China currently controls nearly 70% of global electric vehicle battery manufacturing capacity, including direct or indirect control of the world’s lithium supply as well as nickel, cobalt, graphite and other minerals that are critical to these supply chains, she said.

China is building or planning to build over 100 lithium-ion battery factories, she added. The United States, in contrast, has just nine planned battery factories.

“That is a huge discrepancy. We are dragging behind and we need to catch up from an economic and national security perspective,” she said.

Tom Starrs, vice president for government affairs at EDP Renewables, agreed that the industry is thriving but wondered whether renewable energy developers would embrace Biden’s emphasis on union labor and domestic manufacturing, calling it a “quid pro quo” policy by the administration.

“There is no question that Biden’s plan is very strongly in favor of additional clean energy investment across the board,” he added. “But there is going to be strong pressure on renewable energy in the broader clean energy sector to step up.”

As for boosting U.S. manufacturing of batteries, solar panels and electronic controls, Starrs said the challenge “is essentially overhauling the entire supply chain to bring manufacturing back to the U.S. the way it was 30 years ago.

“We have just lost the material supply chain associated with the raw materials that are needed for industrial manufacturing processes,” he said. “That’s going to take a much more fundamental and targeted effort.”

Johannes Urpelainen, director of the Johns Hopkins School of Advanced International Studies, said there is broad agreement by energy analysts in the United States and globally that the transition to renewable energy is inevitable.

“There is still a question of how fast it will go and exactly how we get there. I don’t think anybody is saying we will be burning coal 30 years from now. This is new.”

February 7, 2021

PJM to Kick off Capacity Market Workshops

PJM is hosting a set of workshops beginning this week aimed at discussing potential enhancements to its capacity market.

RTO officials announced the workshops at the end of January, saying they intend to share their thoughts on the current state of the capacity market while accepting stakeholder feedback to determine the best path forward to improve market design.

The workshops are not part of the formal PJM stakeholder process, the RTO said, but are meant to begin a discussion on whether members want to pursue any changes to the market.

The first workshop will take place Friday and is designed to frame the issue. PJM plans to discuss the historical elements of the market and provide its perspective on the scope of enhancements stakeholders should consider and the principles by which potential enhancements can be evaluated.

In the second workshop, scheduled for March 4, PJM will seek stakeholder feedback and discuss the appropriate framing of market enhancements. The RTO is particularly interested in feedback on three questions:

What problem are we trying to solve through this effort?
Do you agree with PJM that we should be attempting to advance this discussion at this time?
What are the principles that possible enhancement should be built upon?

The third workshop, set for March 12, will feature stakeholders discussing specific market design proposals for consideration.

At a final March 26 workshop, PJM will provide feedback on the discussions from the second and third workshops and an analysis on the next steps to take for any changes.

Stakeholders have been debating changes to the capacity market since 2019 when the Base Residual Auction was first delayed over FERC’s expansion of the minimum offer price rule (MOPR).

According to the Independent Market Monitor’s third-quarter State of the Market Report for PJM released in November, stakeholder fears of the impacts of the expanded MOPR have driven discussions about overhauling the capacity market without first seeing the true impact of the MOPR on the BRA. The report did acknowledge “clear issues” with the market’s design, including an “overstated” market seller offer cap, the shape of the demand curve and the application of penalties for nonperformance. (See PJM IMM Warns Against Another Capacity Market Overhaul.)

PJM Capacity Market — Auction schedule | *PJM*

The RTO reiterated the importance of continuing with its auction schedule approved by FERC in recent MOPR opinions. The long-delayed capacity auction for the 2022/2023 delivery year is set to start on May 19. (See FERC Partially Accepts PJM MOPR Offer Floor Filing.)

At least one key stakeholder applauded PJM’s decision to hold the workshops.

The American Clean Power Association (ACP) commended the RTO on the “important initiative” to examine long-term reforms to utilize the economic and environmental possibilities of renewable resources throughout the region.

“While the current capacity market construct and MOPR present challenges to renewable energy development and growth, these workshops will enable PJM and its stakeholders to examine options and facilitate making changes to allow states to meet their customer-inspired renewable energy goals,” said Amy Farrell, ACP’s senior vice president for government and public affairs. “The clean power industry looks forward to engaging with PJM and other stakeholders as this process moves forward and we collectively work to build a better, more efficient, more affordable and cleaner electric grid.”