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November 20, 2024

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ISO/RTO Execs Talk Reliability and Resource Mix at House Hearing

Senior executives from all seven ISO/RTOs on Thursday discussed how the changing resource mix is impacting reliability during a hearing of the House Energy and Commerce Subcommittee on Energy, Climate and Grid Security.

“The nation is facing an electric reliability crisis and the nation’s grid operators are not equipped to address that alone,” subcommittee Chair Jeff Duncan (R-S.C.) said. “Federal tax subsidies and state policies designed to prop up renewables and EPA regulations targeting coal and natural gas power plants continue to lead to premature retirement of the nation’s most dependable generation sources. As a direct result, grid operators have issued unprecedented warnings and pleas to conserve energy and prepare for blackouts.”

Democrats also seek to maintain reliability and keep electricity affordable, said subcommittee Ranking Member Diane DeGette (D-Colo.). Reliability will only become more important as climate change leads to more extreme weather, she said.

“As the impact of the climate crisis grows, reliability may literally be the difference between life and death,” DeGette said. “Losing power during extreme heat or extreme cold events is life-threatening. And so, we must ensure that we have the assets and infrastructure to ensure reliability even as the climate changes.”

Need for Planning

A common theme across most of the ISO/RTO testimony was that while the transition toward more renewables and generally a cleaner grid presents new reliability challenges, they can be overcome with enough planning.

“This is a monumental task, and it requires four critical pillars to provide a robust foundation for the transition,” said ISO-NE CEO Gordon van Welie. “New England will need to add significant amounts of clean energy, ensure we have sufficient flexible resources to balance the renewable energy, ensure that we have sufficient backup energy for those periods when renewables cannot perform and … further build out the region’s transmission infrastructure.”

New England was not alone in that perspective, with MISO Senior Vice President Todd Ramey testifying that the grid operator has seen no-carbon resources like wind go from 0% of its generation in 2005 to 25% today. He said the trend has been accelerating lately and MISO expects 85% of its generation will be from wind, solar or battery storage by 2040.

“The growth in weather-dependent resources has occurred in parallel with the retirement of significant amounts of dispatchable generators, primarily coal, gas and nuclear resources,” Ramey said. “These investment and retirement decisions in combination with the different operating characteristics of the new resources versus the retiring resources [have] reduced the reserve margins in the MISO footprint to the minimum required levels.”

Other markets are looking to the future and worry they might get down to the bare minimum levels of resource adequacy.

ISO-NE appears to have sufficient RA through this decade, van Welie said, with a look ahead to 2027 showing the system could handle projected demand thanks in part to growth in solar power, which helps even in the winter. The situation becomes more precarious in 2032, but van Welie said that could be handled with proactive planning.

PJM sees the same issues with growing renewables and retiring traditional power plants. Conventional plants not only contribute to resource adequacy, but also provide other grid services, said RTO Senior Vice President Stu Bresler.

“Policies and consumer choices are shifting the grid away from dispatchable emitting generation resources toward resources with little to no carbon emissions, much of which is intermittent generation like wind and solar,” Bresler said. “As generation resources retire, competitive markets have in the past and will continue to work to incentivize replacement generation.”

The market helped replace tens of thousands of megawatts of retiring coal plants with natural gas-fired units in recent decades and Bresler said that experience could be repeated with the shift to renewables; for now, the RTO has a healthy reserve margin of about 20%. That could be complicated by rising demand growth from data centers and longer-term issues such as electrification, coupled with a rapid retirement of additional dispatchable power plants due to federal and state policies.

Renewables are coming online, but at a slower pace than retirements, and they often lack the kind of critical services traditional power plants produce, Bresler said.

Ramey said MISO has about 50 GW of resources with approved interconnection requests that are, on average, running about two years behind schedule.

Developers of those projects have told MISO that many have run into supply chain issues and delays in the permitting process, he added.

‘Greater Coordination’

While most grid operators pointed to the reliability challenges around the timing of the changing resource mix, Neil Millar, CAISO vice president of transmission planning and infrastructure development, noted one of the issues those clean energy policies are seeking to address.

“Our reliability challenges have been primarily impacted by the wider range of extreme weather events that are largely attributable to climate change,” Millar said.

The rest of the Western Interconnection has been dealing with that same issue, but CAISO and other balancing authorities in the region have been able to support each other and make it through challenging conditions with relatively minor disruptions to service.

“Beyond greater coordination in resource commitment and dispatch to support transmission operations, significant opportunities also exist to coordinate resource adequacy programs, resource planning decisions and deployment of transmission infrastructure across the western region,” Millar said. “Working collaboratively with our partners in the West will allow us to unlock these opportunities for the benefit of customers.”

The grid’s transition has also left it more dependent than ever on the natural gas system. Rep. Frank Pallone (D-N.J.), ranking member of the full committee, asked whether the executives testifying supported the idea of a mandatory reliability regime for natural gas.

“I think it’s imperative that we have better oversight of the reliability of the gas system,” van Welie said. “Because I think we should stop thinking about these systems as independent of each other. They’re totally interdependent, and what impacts the one system will impact the other. So, I sort of find it ironic that we’ve got all of this oversight of the electric system as a result of the 2003 blackout, but the biggest single source of energy to the electric system doesn’t have comparable oversight.”

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House E&C Members Grill HECO CEO About Maui Fires

Members of the House Energy and Commerce Committee’s Oversight and Investigations Subcommittee spent nearly two hours Thursday grilling Hawaiian Electric Co. (HECO) CEO Shelee Kimura on her company’s response to last month’s deadly wildfires on the island of Maui but had to accept deferred answers to many of their questions.

Hawaiian Electric CEO Shelee Kimura | U.S. House of Representatives

Kimura was joined for the hearing by Hawaii State Energy Office Chief Energy Officer Mark Glick and Hawaii Public Utilities Commission Chair Leodoloff Asuncion Jr. However, much of the focus of the hearing was on Kimura and her company, which has been accused of contributing to the fires — if not starting them outright — by neglecting required maintenance and by failing to power down its power lines and other electric equipment despite warnings of fire risk from the National Weather Service.

The Maui fires began Aug. 8 and have burned more than 3,000 acres on the island, including the historic town of Lahaina. According to Maui County’s latest update last week, the Lahaina fire was 100% contained, the Kula fire was 96% contained and the Olinda fire was 90% contained. Last month, estimates of the death toll stood at 113, but that number has been revised down to 97.

HECO and parent company Hawaiian Electric Industries are facing several lawsuits over their alleged role in the fires. Plaintiffs include the company’s shareholders, Maui County and residents of the island; several of the suits are seeking class-action status. (See Hawaiian Electric Faces Multiple Lawsuits over Wildfires.)

Questions About Handling of Risk

Throughout Thursday’s hearing, committee members pressed Kimura to explain HECO’s actions on the day the fires began and how the utility responded to the disaster, but the CEO repeatedly claimed not to recall specifics of the day’s events. Asked by subcommittee Chair Morgan Griffith (R-Va.) about HECO’s awareness of high winds Aug. 8, Kimura said the utility was aware of forecasts predicting 35-45 mph winds but could not recall when or if HECO learned the wind was gusting up to 80 mph. She promised to provide the information to the committee later.

Rep. Morgan Griffith (R-Va.) | U.S. House of Representatives

Griffith compared the weather situation to officials in his home state preparing for snowstorms, noting that “even before the first flake drops, if they see significant weather, they shut the school systems down.” He reminded attendees that a downed power line was known to have ignited a fire near Lahaina the morning of Aug. 8 — although, as Kimura pointed out, this fire was marked extinguished by firefighters and the main Lahaina fire started hours later — and asked Kimura about HECO’s readiness.

“Already, because of the invasive plants, because of the wooden poles, because the lines weren’t insulated, [the area] was at risk,” he said. “These are all risks that were known — what was the decision-making process not to de-energize or turn the power off on these lines during that critical period?”

Kimura attempted to begin her answer with a reference to HECO’s creation of its wildfire mitigation plan in 2019. Griffith cut her off, saying that while he appreciated the “history” he was “trying to figure out what happened that day back in August.” However, the chair relented when Kimura explained that the decisions about whether to de-energize “were made years before as part of … our protocols,” when HECO concluded that a public safety power shutoff (PSPS) program such as those in California would not work in Hawaii’s “very unique” conditions and implemented “other protocols.”

Griffith asked if the utility would be reconsidering those protocols and possibly creating a PSPS program in light of the fire. Kimura conceded that HECO was “absolutely reexamining our protocols” but reiterated that the cause of the afternoon fire in Lahaina still has not been determined. She also reminded Griffith that the lines in the area were not energized when the afternoon fire started; however, when he asked how long the lines remained a danger to the public after shutoff, she again could not provide the answer, promising to supply it to him later.

Wildfire Protocols Questioned

Asked by ranking member Kathy Castor (D-Fla.) for more detail on HECO’s wildfire protocols, Kimura said they included disabling the setting that would automatically reclose a circuit in the event of a fault, so lines would not re-energize. Castor asked how quickly the utility implemented this protocol after becoming aware of the wildfire risk; Kimura said she could not recall specifically but believed it happened the morning of Aug. 8.

Kimura also could not recall when she first learned the line in the Lahaina area was down. Asuncion told Castor he was informed of fallen lines “basically on the afternoon of the 8th.”

Energy and Commerce Committee Ranking Member Frank Pallone (D-N.J.) asked Kimura about HECO’s participation in Maui County’s investigation into the fires. Noting that “it’s still important for the fire investigators to determine the role of these power lines,” he asked if the utility planned to cooperate with investigators. Kimura said HECO was “fully cooperating,” as well as running its own investigation.

Pallone followed up on her response, asking if HECO would commit to make the results of its investigation public. Kimura said only that the investigation would “take many months to get done” and that she was “sure that there will be more to talk about once we know the results.”

“Is there any reason why you wouldn’t make it public? You seem to be hesitating a little bit,” Pallone said.

“I think it’s just too early to speculate on what that is going to look like in the future,” Kimura replied. “We’re very focused on finding out what happened there, [and] to make sure that it never happens again.”

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ERCOT Technical Advisory Committee Briefs: Sept. 26, 2023

ERCOT stakeholders on Tuesday approved a protocol change to the minimum state of charge (SOC) for energy storage resources participating in two of the grid operator’s ancillary services.

Staff are proposing to change the minimum SOC requirements for ERCOT contingency reserve service and nonspinning reserve service to slope from the full hourly amount of MW down to zero at the end of the hour. ERCOT says this will resolve the nodal protocol revision request’s “stranded energy” issue during scarcity conditions, which caused the Board of Directors to remand it back to the Technical Advisory Committee.

The directors sent NPRR1186 back to the committee during its August meeting, asking staff and members to address stranded energy associated with the proposed minimum SOC requirements for ECRS and non-spin during scarcity situations. The measure is seen as a stopgap until real-time co-optimization is added to the market in several years. (See “NPRR1186 Remanded to TAC,” ERCOT Board of Directors Briefs: Aug. 30-31, 2023.)

Dan Woodfin, ERCOT | ERCOT

“I think it solves the problem we were asked to solve,” Dan Woodfin, ERCOT’s vice president of system operations, told TAC on Tuesday.

However, Woodfin said ERCOT is concerned that a battery participating in nonspin may by completely discharged for future hours and not be able to charge as needed. He said staff will recommend to the board that more NPRRs be drafted to add compliance and financial penalties related to failures to provide ECRS or nonspin under a mechanism that applies to other resources.

“We’ve got to make sure that we’re enforcing the right level of compliance around that,” he said. “Potentially, we would disqualify resources for repeated failure to perform or if they don’t perform when they’re deployed during a grid emergency or other event. We’ll put a little more structure around it before then.”

Woodfin said the change to failure-to-provide would only add “additional consideration that are the unique technical characteristics of batteries.” He promised fleshed-out NPRRs for the board’s December meeting.

Public Utility Commissioner Jimmy Glotfelty called into the meeting to gently dispute Woodfin’s contentions. He said ERCOT staff are “barking up the wrong tree,” and he encouraged them to think differently about the issue.

“You want to control when you want to control them … which is you want [batteries] to look like a coal plant,” Glotfelty said. “If you’re doing these penalties associated with this, why do you even need to know the state of charge? You’re putting bootstraps and suspenders on something that is not necessary, because the penalty structure within ERCOT will be enough for the market to solve this problem.”

Woodfin responded that ERCOT doesn’t want to “just assess whether someone has the capability of providing the service when we actually need it.”

“We’re spending a whole lot of time and effort on an interim measure that should be resolved with [real-time co-optimization],” Glotfelty said. “You’re not going to get any more reliability about the fact that whether you know a state of charge or not, and it’s discriminatory. So y’all can go about your process, but as it comes down to me at the commission, that’s where I stand.”

Baker Botts attorney Juliana Sersen, representing storage developer Eolian, reiterated her client’s stance opposing NPRR1186 in its current form. Eolian has been joined by other storage developers in pushing back against the measure.

“Even if the battery does not fail to provide or if the battery’s [qualified scheduling entity] moves its ancillary service resource responsibility to another resource, we continue to believe that such compliance metrics are unnecessary and discriminatory,” she said.

TAC endorsed the NPRR in a 29-1 vote. Competitive retailer AP Gas & Electric was the lone member to vote against the motion.

IBR Change Set Aside

The committee agreed with ERCOT staff to table a nodal operating guide revision request after Woodfin said the version approved by a TAC subcommittee does not resolve the reliability risk as originally intended.

“We feel that additional data would be helpful to further consideration by TAC and the board,” he said. “We want NOGRR245 to include requirements that improve the reliability of the system, maintain the current reliability … but do so in a way that’s technically feasible and that we’re not asking folks to do things that they just technically cannot do.”

Staff said they intend to issue requests for proposals to inverter-based resources (IBRs) and the original equipment manufacturers to provide comments for TAC’s Oct. 24 meeting.

The NOGRR would replace the current voltage ride-through requirements for intermittent renewable resources (IRRs) with IBRs’ ride-through requirement. The change would be consistent with or beyond requirements identified in the new Institute of Electrical and Electronics Engineers (IEEE) standard for IBRs’ interconnection and interoperability.

Eric Goff, holding NextEra Energy Resources’ proxy for much of the discussion, urged TAC to consider changing the compliance date for new resources to earlier than 2024 while providing some exceptions based on details to be determined. He also called for tightening up the technical feasibility sections.

“We’re happy to work on additional changes,” he said.

“I always believe we come up with a better product when we work together,” ERCOT’s Stephen Solis said.

LP&L’s Final Transition Delayed

Oncor’s Debbie McKeever, chair of the Retail Market Subcommittee, told TAC the final 30% of Lubbock Power & Light’s load, about 201 MW, is on track for a mid-December transfer into ERCOT.

The transfer hinges on FERC’s approval of a settlement agreement between LP&L and Xcel Energy subsidiary Southwest Public Service Co. (SPS), which has long held a contract to serve the city’s load.

Last month, an administrative law judge certified an uncontested settlement offer between LP&L, Xcel, Golden Spread Electric Cooperative and several New Mexico cooperatives. LP&L and SPS agreed to pay the cooperatives $6.38 million, while the Lubbock utility will pay SPS either $77.5 million in a lump sum or six annual installments of $14.95 million for early termination of a partial requirements agreement (ER23-1144).

The commission is expected to rule on the settlement by early December.

LP&L moved 70% of its load out of SPP in 2021, six years after it announced its intentions to join ERCOT’s competitive market. Texas regulators approved the transition in 2018. (See Six Years in the Making: LP&L Migrates Load to ERCOT.)

RTC+B Group Gets Leadership

The TAC’s unanimously approved combination ballot resulted in the approval of leadership for the Real-time Co-optimization + Battery Task Force. ERCOT’s Matt Mereness will chair the group, and CPS Energy’s David Kee will be vice chair.

The ballot also included tabling a planning guide revision request (PGRR105) that would add DC tie resources to the list of resources required to meet the minimum deliverability condition and the 2023 major transmission element list.

It also included one NPRR and a system change request (SCR) that, if approved by the board, would:

    • NPRR1184: clarify ERCOT’s management of the interest it receives and is owed to counterparties for posted cash collateral and require staff to credit counterparty collateral accounts for interest every month. The NPRR also requires ERCOT to report the interest calculation.
    • SCR824: increase the attachment file size and quantities allowed within the resource integration and ongoing operations system.
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Annual OMS DER Survey Records 1-GW Rise in MISO Residential Capacity

The Organization of MISO States’ sixth annual survey on amounts of distributed energy resources in MISO tracked a nearly 1-GW rise in residential DERs year over year.

This year’s utility survey recorded almost 12.5 GW of DER capacity operating in MISO, up from 11.5 GW in 2022. OMS found that residential customers’ additions are responsible for all gains in DER capacity, up from 1.8 GW in 2022 to now more than 2.9 GW. For the first time, solar overtook demand response as the most plentiful DER class in the footprint, at 5.5 GW to 5.1 GW, respectively.

OMS also found that virtually all DER increases this year occurred in Minnesota, Wisconsin and the Dakota’s Zone 1 and Michigan’s Zone 7. Those zones together contain most of MISO’s DER amounts, at a combined 6 GW. Zone 1 alone holds almost 3.4 GW.

Five years ago, the OMS DER survey identified just 2.6 GW of DERs operating in the footprint.

MISO 2023 DER totals by local resource zone | OMS

During a Sept. 25 webinar to discuss survey results, OMS Executive Director Marcus Hawkins said a “steady trend of DER growth continues in MISO.” He said the surge in unregistered, residential DERs might be introducing load forecasting complications for MISO because it doesn’t have visibility into residential DER contributions. Hawkins also said the survey results could be undercounting the actual amount of demand response resources.

According to OMS, utility respondents to the survey agreed DERs soon will begin shaping load forecasting in MISO.

MISO over the summer tended to over-forecast load on its hottest days. Independent Market Monitor David Patton has said MISO’s forecast model overestimated load between 2-8 GW on the hottest days in July and August and might not account for voluntary load reductions and behind-the-meter solar. (See MISO: Could Have Employed Wait-and-see Approach for August Emergency.)

OMS said utilities this year expressed a willingness to work with DER aggregators and mentioned the need to build distributed energy management systems in the future, though they said it’s still an open question as to who will pay for those communication systems.

Some respondents also told OMS they’re waiting on MISO’s participation model for DER aggregation to be active before they move ahead on more comprehensive DER planning.

MISO has asked FERC to allow it until 2030 to comply with the commission’s directive to open its wholesale markets to DER aggregators under Order 2222. (See MISO Defends 2030 Completion for DER Market Participation.)

The RTO has said it needs time first to finish its ongoing market platform replacement and then require additional years to introduce a multi-configuration resource participation model before it can tackle offers from DER aggregations. MISO will lean on its electric storage participation plan for DER aggregations, limiting them to a single pricing node. The aggregations must self-commit in the RTO’s markets based on their own forecasts.

OMS has said MISO’s Order 2222 compliance plan is too drawn out and should include DER aggregations into its markets sooner.

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NJ Extends Third Solicitation OSW Deadline for ‘Contingent’ Projects

In a sign of the complexity arising from offshore wind developers chasing solicitations in different Northeastern states, New Jersey on Wednesday agreed to extend the deadline — if necessary — by which developers with solicitations pending in other states can drop out of New Jersey’s third solicitation.

The New Jersey Board of Public Utilities, in a 4-0 vote, authorized staff to extend the deadline for the third time by which so-called “contingent projects” — that have submitted projects in New York or Rhode Island — should be taken out of the running for approval in New Jersey. In that situation, approval in another state likely would mean developers would not want, or have the resources or corporate capacity, to pursue a project in New Jersey.

The New Jersey solicitation, which opened March 8, closed Aug. 4 with four submissions. The solicitation guidance document initially required contingent projects to notify the agency by July 31 if they planned to drop out. The agency extended that deadline in June to Sept. 11, and staff extended it again by 30 days to Oct. 11, as allowed under the guidelines.

The state wants as many developers as possible in contention for solicitation approval to ensure a competitive selection, and so doesn’t want to exclude any developers prematurely or unnecessarily. (See NJ’s 3rd OSW Solicitation Attracts 4 Bidders.)

But even the Oct. 11 deadline “could be insufficient to fully consider contingent projects,” because of the evolving competitive environment, Jim Ferris, deputy director for the BPU’s division of clean energy, told the board.

Key among the uncertainties is the shifting timeline under which New York’s Energy Research and Development Authority (NYSERDA) will announce the winners of its third solicitation. The solicitation closed for submissions Jan. 26, with six developers submitting 100 proposals. But NYSERDA in July said developers could revise their bids, with downward price adjustments only, before Aug. 24, and that the winning bids would be announced sometime in the fourth quarter of this year.

Among the developers in contention in New York are two that have said they also submitted bids in New Jersey: Community Offshore Wind, a joint venture between RWE and National Grid Ventures; and Leading Light Wind, a partnership between Invenergy and energyRE. Also bidding in New York is Danish developer Ørsted, which has two approved projects in New Jersey — Ocean Wind 1 and 2 — but has not said whether it bid in the state’s third solicitation. (See NYSERDA: 3rd OSW Solicitation Breaks Record.)

Ferris said giving its staff the authority to “adjust the contingent project notification date as necessary” would enable the agency to “evaluate all third solicitation project options as fully as possible.”

$200 Million Payment Escrow

New Jersey is seeking to build 11 GW of offshore wind by 2040, and the third solicitation could approve projects totaling 1.2 GW to 4 GW, and perhaps more. The BPU approved projects totaling 3,758 MW in the first two solicitations, in 2019 and 2021.

Yet developers have found the environment for offshore projects increasingly tough, as logistics and materials costs have risen, prompting some to try to renegotiate contracts with states and push for additional public support. In New Jersey, Gov. Phil Murphy (D) on July 6 signed a bill that allowed Ørsted to access federal tax credits that previously had been designated to help state ratepayers pay for OSW projects. Ørsted, while lobbying legislators to award the credits, said Ocean Wind 1 faced rising materials, equipment and transportation costs because of unanticipated events, including the COVID-19 pandemic and the Russo-Ukrainian War.

The BPU board on Wednesday, with a 4-0 vote, approved the creation of an escrow account to enable Ørsted to fulfill a second part of the agreement: a payment of $200 million by the developer for New Jersey to use to support offshore wind projects.

“By the terms of the legislation, the escrow funds are used to support additional investments in qualified wind energy facilities,” Michael Beck, general counsel for the BPU, told the board. “That term is defined in the legislation including offshore wind component manufacturing facilities.”

Grid Scale Solar Delay

In an unrelated matter, the board also approved, by 4-0, an eight-week delay in the second solicitation of bids under the Competitive Solar Incentive program. The second solicitation will open Nov. 27 instead of Oct. 1 as planned.

The program awards incentives for grid-scale projects — those greater than 5 MW — by setting incentive levels through a competitive solicitation rather than a BPU directive as in the first part of the program, the Administratively Determined Incentive program.

The BPU opened the CSI program on Oct. 1, 2022, hoping it would help the state reach its goal of 12.2 GW of solar energy by 2030 and 17.2 GW by 2035. Figures released by the board Wednesday show the state on Aug. 31 had 4.56 GW of installed capacity, with another 736,028 kW in the pipeline.

But the agency closed the first solicitation on July 12 without approving any of the bids.  (See NJ Rejects Solar Bids as Too Expensive.)

Agency officials at the time said all the “responsive” bids exceeded the confidential price caps developed by the BPU, which the agency attributed to rising costs and economic and regulatory uncertainty nationwide. While the board initially pledged to hold a new solicitation as soon as possible, the agency wants to make sure it is ready before launching the next one, BPU staffer Diane Watson told the board.

“Staff recognizes that the board needs adequate time to consider the lessons of a prior solicitation and integrate any necessary changes,” Watson said, adding that “by doing so, the board demonstrates a level of responsiveness that serves stakeholders and ratepayers alike.”

As in the first solicitation, the second solicitation will aim to award projects totaling up to 300 MW, she said.

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Michigan Senate Passes First Renewable Bill; Talks on Package Continue

LANSING, Mich. — The first bill in a package of climate legislation won Michigan Senate approval this week, while the chair of the Senate Energy and Environment Committee said talks are continuing on the other proposals.

As several hundred supporters of renewable energy production rallied at the Capitol, the Senate voted 23-14 to approve SB 277, with three Republicans joining the Democratic majority. The bill would codify current policy and allow farms enrolled in the state’s farmland preservation system to lease out land for solar energy projects. It’s unclear when the state House will begin work on the measure.

While the legislation does not have the same impact as some others in the package — such as SB 271, which calls for the state to have 100% renewable energy production by 2035 — it has symbolic value as the first measure to pass one chamber. Another bill in the package would end coal-fired electric generation in the state by 2030. (See Michigan Dems Seek to End Coal-fired Plants by 2030.)

Most Republicans voted against the bill, arguing it could reduce the amount of land used for food production in the state. The argument was similar to that used by local governments that have opposed solar and wind projects. (See Wind, Solar Opponents Defeat Four Proposals In Rural Michigan County.)

One Republican, Sen. Dan Lauwers, abstained because several solar companies are interested in leasing part of his family’s farm.

Agriculture competes with tourism as the state’s largest industry following manufacturing. The state is one of the nation’s largest producers of such crops as tart cherries, pears and blueberries.

Sen. Kristen McDonald Rivet (D) insisted the bill was pro-farm and pro-environment and that it respected property rights.

Sen. Sean McCann (D) told the rallying activists that discussions are ongoing on possible compromises to move the entire package forward. One change being considered to win support is extending the 100% clean energy goal five years to 2040.

He said he did not have a timeframe for when bills might move but said it was unlikely the Energy and Environment Committee chairs would act this week.

Environmental activists have warned there are limits to compromises they would accept on the bills.

Opponents of the package argue the proposals could expose state residents to less reliable forms of energy and higher utility costs. And with the ongoing UAW strike against the Big Three automakers, opponents also are warning that pushing EVs could cause widespread manufacturing job loss in the state.

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First Wash. Ferry Being Converted to Electric-diesel Hybrid

The first overhaul of a Washington diesel ferry into an electric-fuel hybrid has begun, with the converted boat expected to be operating by September 2024.

That would be the first of eight electric or hybrid vessels to be adopted by the Washington State Ferries system over the next several years.

Overall, the ferry system — the largest in the nation — has 21 vessels handling 10 routes in Puget Sound. The system has been hit recently with a rash of mechanical problems due to the ages of the boats. The fleet handled 17.3 million people and 8.6 million vehicles in 2022.

Washington State Department of Transportation (WSDOT) officials briefed Gov. Jay Inslee on the conversion plans Wednesday.

“This is the start of a long revolution in the maritime industry. … Like every revolution, we don’t expect everything to be smooth,” Inslee said.

Washington is converting its ferry fleet to cut back on carbon emissions and diesel fuel costs. “We should be tired of being shackled to paying these outrageous prices for diesel,” Inslee said.

The first ferry to be converted, the MV Wenatchee, will have two of its four diesel engines removed and a bank of batteries installed. On its future trips, the Wenatchee will be in fuel mode to leave and enter a dock, while using battery power for the bulk of its route between Seattle and Bainbridge Island, a suburb on the opposite side of Puget Sound.

Vigor will begin work on the $150 million conversion at its Harbor Island shipyard in Seattle. The company has been contracted to convert two more ferries into hybrids after finishing work on the Wenatchee.

The state has begun training crews to operate and maintain hybrid ferries, said Amy Scarton, deputy secretary of WSDOT. The state also needs to install electric charging equipment at its docks.

The state expects to seek bids in spring 2024 to build five new electric ferries, said Matt Von Ruden, WSDOT’s system electrification program manager.

Meanwhile, the Kitsap Transit Authority told Inslee it is looking to develop an electric passenger-only hydrofoil ferry linking Seattle with Kitsap County. The county is on the west side of Puget Sound and includes Bainbridge Island and Bremerton on the Kitsap Peninsula, which hosts a major U.S. Navy base. The Kitsap authority is seeking $4 million for the electric hydrofoil ferry’s design and $18 million for its construction.

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ISO-NE Details Proposed Order 2023 Compliance

WESTBOROUGH, Mass. — ISO-NE outlined its proposed compliance with FERC Order 2023 at Wednesday’s meeting of the NEPOOL Transmission Committee, detailing plans to revamp its interconnection processes.

The RTO said it plans to adopt most of the order’s requirements but will request independent entity variations related to its operating assumptions for storage resources and the cluster study timeframe, proposing a cluster study length of 270 days, compared to the order’s 150 days.

Al McBride, director of transmission services and resource qualification at ISO-NE, said this timeline would be “consistent with established timeline for System Impact Studies in New England.”

McBride added that uncertainty around how many projects will request interconnection in any given cluster, coupled with the lack of standardization for generation equipment, makes it difficult to guarantee a 150-day cluster study timeline. Also, ISO-NE proposed to establish a uniform $250,000-cluster study deposit, consistent with Large Generator Interconnection Procedures requirements.

ISO-NE’s proposed Order 2023 compliance would require interconnection requests to be submitted during a specified period lasting 45 days, which would be followed by a 60-day engagement window featuring a single cluster study scoping meeting. The RTO then would undergo the 270-day cluster study process, which would be followed by a potential cluster restudy period lasting 150 days.

Adding up all the steps, the process would take 525 days — or just under a year and a half — if all steps proceeded in immediate succession.

Some stakeholders have expressed concern about extending the cluster study length from 150 to 270 days. Alex Lawton of Advanced Energy United (AEU) told RTO Insider in a statement that the AEU is reviewing the compliance proposals but that it “encourages ISO to adhere to Order 2023’s 150-day cluster study duration, propose a study duration shorter than 270 days, and work with stakeholders to effect changes that are necessary for the ISO to confidently conduct cluster studies in a timely manner that is aligned with Order 2023.”

Lawton said ISO-NE should require transmission owners to attend the study scoping meeting in the engagement window, which is not mandated by Order 2023. He added that AEU hopes to see more information on cluster subgrouping, the effect of cascading restudies on subsequent clusters, study assumptions for storage and the ways ISO-NE will consider grid-enhancing technologies.

ISO-NE said the presentations were intended to initiate conversations with stakeholders and welcomed feedback on the proposals.

The RTO said it is preparing an alternative proposal for storage operating assumptions that will “no longer study storage resources charging at peak-load conditions” and will “avoid incorporating additional control technologies.” The RTO plans to provide more detail on the treatment of storage resources at the October Transmission Committee meeting.

Capacity Interconnection

ISO-NE also presented to the TC on changes to its capacity interconnection processes, which will be separated from the Forward Capacity Auction process in response to Order 2023.

In the current process, capacity interconnection is connected to the Forward Capacity Market (FCM) and requires new resources to participate in FCM qualification and obtain a capacity supply obligation (CSO).

Alex Rost of ISO-NE said the current process will not be compatible with the requirements of Order 2023. To comply with the order, the RTO will “move all steps of the capacity interconnection process into the overall interconnection process.”

Rost added that ISO-NE will evaluate capacity network resource interconnection service (CNRIS) requests within each cluster.

“Achieving a CSO in the Forward Capacity Market would no longer be a milestone to achieving CNRIS,” Rost said. “CNRIS would be achieved by completing the interconnection process and entering commercial operation.”

Transition Process

Jody Truswell of ISO-NE presented on the RTO’s proposed transition process, which would begin soon after the compliance filing, and “be the most impactful for active projects in the ISO interconnection queue,” Truswell said.

“Interconnection customers will need to make decisions shortly after the ISO files its compliance package regarding how they plan to proceed,” Truswell said.

Assuming no extensions to the compliance deadline, interconnection requests would need to be “deemed valid” by Jan. 4 to be included in the transition process. If projects missed this deadline, they would need to wait until the first cluster entry window opened, which ISO-NE projected to be in mid-2025. ISO-NE is proposing an effective date of March 1, 2024, to initiate the transition study process.

Truswell also proposed that two ongoing cluster efforts — the Third Maine Regional Integration Study and the Cape Cod Cluster System Impact Study — proceed as planned.

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Emilie Nelson Named NYISO COO, Replacing Rick Gonzales

NYISO on Wednesday announced that EVP Emilie Nelson was named COO, replacing Rick Gonzales, who is retiring at the end of the year.

CEO Rich Dewey told stakeholders at an ISO Management Committee meeting that he recommended Nelson to the Board of Directors, which approved the promotion. Nelson will now be responsible for overseeing both the operations and the market mitigation and analysis (MMA) teams.

“I feel that this really positions us well for the future and is a good leadership expansion for Emilie and sets up both our organization and teams for the challenges of the future,” Dewey said during the meeting.

Nelson joined the ISO in 2004 and has been in the industry for almost 25 years. She previously worked for Mirant New York as a power plant performance engineer. During her tenure at NYISO she has held various roles of increasing responsibility on the market monitoring, energy market design and operations teams.

Nelson holds a bachelor’s degree in mechanical engineering from Tufts University, an MBA from Pace University and is a graduate of Harvard Business School’s Advanced Management Program.

NYISO Board Chair Dan Hill said in a statement that “Emilie has built a strong record of performance-driven results in a number of senior management roles throughout her career at the NYISO.”

Gonzales also congratulated Nelson during the meeting, saying she “will bring some great change to the organization by bridging [the operations and MMA] parts together.”

Gonzales, who has been with NYISO since its inception and previously worked for the New York Power Pool, is scheduled to retire on Dec. 31, 2023.

Draft Budget

NYISO presented the MC its draft budget for next year, saying it will total $194.8 million and that $8 million remaining from this year’s budget will be used to make early repayments on outstanding debt.

The 2024 draft budget is roughly $5 million higher than this year’s budget, with much of the growth attributable to proposed increases in consulting fees and staff salaries, which NYISO says are necessary to accomplish next year’s project portfolio. The ISO will also hire for 19 new positions in both the system and resource planning and operations teams next year.

NYISO’s draft budget for 2024 compared to 2023 | NYISO

NYISO already faced stakeholder scrutiny after presenting its final project budget recommendations of $41.62 million for next year, with many balking at the proposed labor cost increases. (See NYISO Proposes $41.62M Project Budget for 2024.)

Stakeholders can discuss the draft budget again in early October before the board reviews it on Oct. 16. The ISO anticipates bringing the final draft to the MC for a vote on Oct. 25.

Seasonal Demand Curves

The MC also approved NYISO’s proposed revisions related to implementing winter and summer demand curves into the next demand curve reset for the 2025/26 capability year.

The ISO’s proposed changes will be part of the next four-year DCR, which regularly updates the parameters for New York’s capacity market, and seek to better reflect seasonal reliability risks and the value that certain resources provide during the competing seasons.

The revisions were previously approved by the Business Issues Committee and will now go before the board for final approval. (See “Seasonal Demand Curves,” NYISO Business Issues Committee Briefs: Sept. 14, 2023.)

August Market Performance

Gonzales delivered the August market performance report during the MC meeting, saying, “we had pretty mild temperatures that were cooler than average and a little less wet than July.”

He noted that August’s year-to-date energy prices are down 56% compared to last year, decreasing from $93.42/MWh in 2022 to $40.13/MWh this year. August’s gas prices were also down 85% compared with last year, and prices at the Transco Z6 NY pipeline touched a low of $1.18/MMBtu.

As in a monthly operations assessment delivered to an earlier Operating Committee meeting, Gonzales highlighted how an unexpected four-day heatwave in early September saw some of the highest demand during the summer and that the ISO will investigate the hot weather phenomenon. (See “August Operations Report,” NYISO Operating Committee Briefs: Sept. 15, 2023.)

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PJM Board Releases Outline of Capacity Market Changes

The PJM Board of Managers has released an outline of several changes to the RTO’s capacity market to be included in a FERC filing slated to be made next month.

In a Wednesday letter, the board stated it built the filing’s structure off the annual capacity market design PJM formed during the critical issue fast path (CIFP) process. The filing would retain the core design of the Reliability Pricing Model (RPM) but rework the capacity performance (CP) construct, how resource adequacy risk is modeled and resource accreditation. The filing is expected to include parallel changes to the risk modeling and accreditation for fixed resource requirement (FRR) entities with a four-year transition period. (See PJM Members Lobby Board Ahead of Expected CIFP Filing.)

The board directed PJM to submit the filing to FERC no later than Oct. 13, with the aim of having the changes effective for the 2025/26 Base Residual Auction (BRA). It notes that components could be grouped together or filed individually to “mitigate the risk of a single component of the filing causing the delay or rejection of the entire suite of enhancements.”

The filing completes the CIFP process the board opened in February but acknowledges stakeholders and PJM raised issues that remain unaddressed under the expected filing, such as a seasonal or more granular capacity market design and shortening the period between the auction and corresponding delivery year. The board’s letter states it expects to receive feedback on the filing and next steps during the next Liaison Committee meeting, scheduled for Oct. 2, and through discussions with the Organization of PJM States Inc. (OPSI). (See PJM Stakeholders Vote Against All CIFP Proposals.)

In reworking the CP design, the board stated that it sought to strike a balance between the risks generators see in taking on a capacity commitment and incentives for them to maintain the capability to perform during an emergency.

The filing would leave the penalty rate unchanged but would revise the annual stop-loss limit to be based on the BRA clearing price; currently, both are derived from the net cost of new entry (CONE). Proponents of basing penalties on the value of capacity argued that it would align the risks generators face with the revenues they earn as a market seller, while opponents argued it would reduce the incentive to perform. A proposal to base both values on the BRA clearing price was endorsed by the Members Committee in May but was not approved by the board. (See PJM Board Rejects Lowering Capacity Performance Penalties.)

The filing also directs PJM to revise its calculation of the market seller offer cap (MSOC) to allow generators to include more cost of risk in their offers even when their net avoidable cost rate (ACR) is zero or negative.

“The ability to express risk in offers is integral to ensuring the optimal set of resources are selected to provide capacity and on its own is not an exertion of market power when those quantified risks are rooted in rigorous, reasonable analysis, as is required by the current resource-specific process,” the board said.

The eligibility for receiving CP bonus payments — which are based on the amount of penalties collected and are distributed to generators that overperformed during an emergency — would be tightened under the board’s filing to go only to committed capacity resources, rather than all generators.

The board rejected proposals to excuse long-lead resources from CP penalties, which argued they are not capable of modifying their generators to be more flexible, saying the current rules incentivize them to be ready for emergencies.

“The board does not believe that self-scheduling of such resources in the anticipation of being required to operate presents a reliability concern for PJM, and to the extent a self-schedule request is actively denied by PJM, it represents a dispatch instruction by PJM and therefore an excusal,” the letter said.

The risk modeling changes would increase the amount of weather history data PJM uses to go back 30 years and using hourly granularity and modeling of correlated outages when evaluating resource adequacy. The board did not, however, adopt PJM’s proposal to zero out the capacity benefit of ties, arguing that doing so requires further consideration. It directed PJM to continue engaging in it with the aim of arriving at a new process of considering the value of imported power during emergencies. The new methodology should be targeted for implementation for the calculation of the 2025/26 installed reserve margin, the board said.

“While the board does not support the 0 MW proposal at this time, the board is concerned that the current process to produce CBOT may no longer produce accurate estimates, given the evolving view of resource adequacy risk and resource adequacy dispositions of neighboring regions,” the letter said.

The board also directs changes to modify the winter deliverability assumptions in resource adequacy risk modeling and accreditation for solar resources to consider system conditions and resource output beyond the hours now studied.

The filing adopts PJM’s CIFP proposal to shift to using a marginal effective load carrying capacity for all resource types, which the board said will improve alignment between market structures such as accreditation, compensation and incentives, with system risk.