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November 20, 2024

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NERC Board Accepts State of Reliability Report

NERC’s Board of Trustees voted to accept the organization’s 2022 State of Reliability report on Thursday, clearing the way for its release later this month.

The ERO produces the report each year to provide an analysis of the overall health of the bulk electric system, identify performance trends and emerging reliability risks, and measure the success of mitigation activities. Unlike NERC’s seasonal and long-term reliability assessments, the State of Reliability report is formatted as a review of the bulk power system’s overall performance the prior year along with specific incidents that impacted reliability.

Jim Robb (NERC) Content.jpgJim Robb, NERC | NERC

In Thursday’s board meeting, NERC CEO Jim Robb said the growing threat from severe weather, coupled with the shift to renewable and low-carbon energy sources, made it more important than ever that “reliability has a seat at the table” during conversations about the future of the BPS. He added that the Summer Reliability Assessment, issued in May, has already “catalyzed a very productive conversation” with Energy Secretary Jennifer Granholm.

“The importance of these assessments is clearly growing, given both the changing climate conditions that the grid is having to operate under, and the transformation of the grid itself,” Robb said. “And I don’t think there’s any better proof of that than all the attention that our summer assessment … has gotten, both in terms of the popular press as well as the trade press.” (See West, Texas, Midwest at Risk of Summer Shortfalls, NERC Says.)

Thursday’s discussion did not include a look at the full report; that is scheduled to be released during a media event on July 20, a spokesperson for NERC told ERO Insider. However, NERC staff had provided a preview at the board’s May meeting with some of the report’s key findings, which John Moura, NERC’s director of reliability assessment and performance analysis, referenced in his presentation to the board.

John Moura (NERC) Content.jpgJohn Moura, NERC | NERC

“If there’s one question the State of Reliability really helps us answer, it’s ‘are we making a difference?’ … I think the answer is largely ‘yes, we are making a difference,’ and we do see incredible reliability improvements, specifically in how we keep the system stable,” Moura said. “On the other hand, when we look at our performance around resource adequacy and energy adequacy, we are seeing trends that really are leading to some concerns.”

One of the main challenges in 2021 was extreme weather, including the winter storms that knocked out power for thousands in Texas and the Midwest, Hurricane Ida’s impact on New Orleans and wildfires in the Western Interconnection. The winter storm in particular accounted for more than 23 GW of firm load shed, according to FERC and NERC’s joint report on the disaster, and was the sole reason for last year having the fewest hours without operator-initiated firm load shed since 2016. (See FERC, NERC Release Final Texas Storm Report.)

Trustee Roy Thilly said the report provided a strong reminder of the importance of planning for severe weather; he reminded listeners that “science tells us … we’re not dealing with a one-off situation.” Noting that “planning takes a long time to make changes,” he urged NERC to continue working to improve the grid’s preparation for the changing climate.

By contrast, Trustee Jim Piro suggested that while these issues must be recognized, the report also appears to tell an overall positive story. He said that although much work remains to build the grid of the future, NERC should be mindful of its successes so far so that it can properly build on them.

“There’s a lot of work that goes into making that happen, and sometimes we forget about how important that is and the work that’s been done. In fact, the system is pretty reliable, or very reliable, absent these severe events, and I think it’s important to note that for the industry,” Piro said.

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Entergy Proposes $1.2B in New Orleans Resilience Investments

Entergy’s New Orleans division unveiled a plan Tuesday aimed at hardening the bulk electric system in preparation for future storms in the city.

The proposal comes in light of the “increased frequency and severity” of extreme weather events that are causing “greater costs and disruptions” to electric customers on the Gulf Coast, the utility said.

In the proposal, submitted to the New Orleans City Council last week, Entergy (NYSE:ETR) identified nearly 900 projects across its distribution and transmission systems that would have a beneficial resilience effect. The planned upgrades would affect more than 33,000 structures and almost 650 line-miles and would cost almost $1.3 billion over the next 10 years.

Entergy’s filing repeatedly referenced the devastation wrought last year by Hurricane Ida, which struck the Gulf Coast in August and caused more than 1.2 million electricity customers across eight states to lose power, according to the Energy Information Administration. Nearly a million of those customers were in Louisiana, including a complete blackout of Greater New Orleans after a “catastrophic transmission failure” cut all eight transmission corridors into the city. (See Entergy Investigations Certain to Follow Hurricane Ida Restoration.)

Council Ordered Resilience Plan

Following the storm, the city council ordered Entergy to submit a “system resiliency and storm hardening plan” detailing how it would prevent future natural disasters from causing such severe impacts. The council’s resolution also referenced the high costs to Entergy’s ratepayers associated with repairing storm damage; this was a frequent cause of complaint among city officials in the weeks after Ida, who also asked why previous Entergy projects that were supposed to improve resilience seemed to have no effect in practice. (See New Orleans Seeks FERC Inquiry into Entergy Planning Practices.)

In its filing, Entergy avoided these adversarial characterizations, painting itself as a partner in suffering from recent storms’ destructive powers, and an ally to the city council in attempting to alleviate their impacts on the people of New Orleans.

“Over the last five years, major hurricanes have become more frequent and intense, and slower and wetter, further increasing the potential for devastation,” Entergy said. “Additionally, coastal erosion caused by severe storms, among other things, has increased the vulnerability of New Orleans by removing an important wetlands buffer. In short, the increasingly frequent threat of severe weather poses an existential threat to the region, including New Orleans.”

The grid hardening projects identified by Entergy include 184 “rebuild projects” in the distribution feeder category, which involve the “evaluation and potential rebuilding or replacement of every asset in the protection zone to bring such assets up to the company’s current design standards.” Another 674 rebuild candidates were found among distribution laterals, while the utility also noted 30 potential overhead line burial projects.

Among the distribution projects is a feeder rebuild in Algiers, involving the hardening of 324 structures along nearly four line-miles. Another is an overhead-to-underground project involving a third of a mile of line in the Treme/Lafitte area, affecting 611 customers.

Entergy also noted two transmission rebuild projects that would “have positive benefit to cost ratios and fall within the optimized budget.” These are the Front Street to Michoud 230-kV line, which would provide “an additional connection to the eastern interconnect … that allows for additional flexibility to operate during and after a major event.” The other project is the Gulf Outlet to Air Products 69-kV line, which would replace several structures along about a mile of transmission line.

Cost Recovery Rider Proposed

To pay for the proposed upgrades, Entergy proposed a cost recovery rider to “provide a stable, long-term recovery mechanism that could be used over the 10-year period of the projects.” The rider — dubbed the “Resiliency Rider” by Entergy — is patterned on the Purchased Power and Capacity Acquisition Cost Recovery Rider and the Securitized Storm Cost Recovery Rider, which Entergy used to recover its investment in the Union Power Block 1 and the Hurricane Isaac storm restoration, respectively.

Perhaps anticipating further complaints about passing along the costs of resilience investments to customers, the utility noted that credit ratings agencies downgraded Entergy New Orleans “several times” after Hurricane Ida, with further downgrades a possibility “if financial pressures are not mitigated and system resiliency is not enhanced.” Entergy argued that accomplishing the latter without alleviating the former may not be possible with the resources currently available.

“Credit ratings directly affect [Entergy’s] cost of capital investment and overall customer rates,” Entergy said. “Without timely and efficient cost recovery for the projects presented herein, [Entergy’s] financial health likely would be further compromised given the amount of the expenditures involved over an extended period.”

Entergy executives sought to position the proposal as a proactive measure to upgrade and modernize the grid ahead of future storms, while attempting to soften expectations by pointing out that “no amount of infrastructure investment can make an electric system completely resistant to the impacts of extreme weather conditions.” In a press release Deanna Rodriguez, CEO of Entergy New Orleans, said the utility expects to work with the city council to finalize the project list and its financial backing.

“While investments to harden the grid carry a significant cost, they result in substantial customer benefits in the long run,” Rodriguez said. “Robust investments in grid resiliency will reduce the duration of power outages following major storms and will also reduce future storm restoration costs. Our objective is two-fold: the hardening of the New Orleans grid and how quickly we get power back on for customers.”

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Markey, Others Grill ISO-NE over Markets, Transparency

A high-ranking ISO-NE official sat down with some of the RTO’s biggest critics last week, who pushed her on the RTO’s clean energy efforts, market rules and transparency.

Anne George, ISO-NE vice president for external affairs, defended the organization and answered questions lobbed at her by a group of stakeholders in the energy industry and from environmental groups at a roundtable put together by U.S. Sen. Ed Markey (D-Mass.), who himself has offered frequent critiques of the grid operator. (See Mass. Democrats Take on ISO-NE over MOPR.)

“Instead of a renewable energy superhighway for the modern era, our grid is a one-lane road that would still be recognizable to Henry Ford,” Markey said in kicking off the meeting.

He also noted that Massachusetts trails North Dakota in renewable energy generation and that he’s carefully watching news about ISO-NE possibly reviving winter reliability programs to subsidize fossil generators, as well as a FERC investigation into the RTO’s role in capacity market fraud. (See ISO-NE Weighs Reviving Reliability Programs for this Winter and Developer in ISO-NE Hit with FERC Fine for Capacity Market Fraud.)

George said that ISO-NE is “committed to having full conversations with the region” about the markets and decarbonization goals of the states, touting the grid operator’s recent vision statement and its work on the Pathways to the Future Grid study.

Who’s Responsible for Fixing the Markets?

George defended the role of the markets in growing the region’s renewable energy footprint, arguing that siting has been a primary challenge and that states need to step up in finding ways to get projects built.

“There’s a lot that has come on in places where it’s easier to site,” she said.

Another factor George cited: developer recalcitrance.

“Our markets are open to all of these resources to come in. It’s just a question of when the developers want to come in,” she said.

And she repeated a frequent ISO-NE refrain about the importance of natural gas for the region’s near future.

“Natural gas isn’t necessarily an evil thing. It’s providing reliability. It’s oftentimes at lower cost, and it’s going to be here for the foreseeable future. We don’t have enough [clean energy] resources ready to go. They haven’t even tried to come into the market because of their development timelines,” George said.

Greg Cunningham, a vice president at the Conservation Law Foundation, pushed back by noting ISO-NE’s failure to move forward on requests from the states to create a central clean energy mechanism.

“I blanch a little bit when I hear ISO-NE saying the region needs to act,” he said. “The states have, in essence, petitioned ISO-NE to make change, to make it happen. And it’s not. And that’s where principal frustration lies.”

“When we do make a decision, we get criticized,” George shot back. “When we say we’re going to listen to people, we get criticized. At some point, you have to reconcile those positions.”

She reiterated that the RTO has been supportive of a net carbon pricing solution for the region, which would rely primarily on states to enact; the states have been reluctant because of political challenges associated with carbon pricing.

Jeremy McDiarmid, vice president at the Northeast Clean Energy Council, floated a solution at a higher level: add the transition to clean energy to the list of legal responsibilities of RTOs, in addition to maintaining reliability and markets.

“ISO could provide leadership to the states with their voice and their actions,” he said.

Transparency at the Forefront

An oft repeated subject at the meeting was transparency, an area where ISO-NE is widely thought to trail behind its counterparts in other regions of the country. NEPOOL’s stakeholder meetings are not open to the public.

“It saddens me to say that ISO-NE is an outlier in terms of public accessibility,” said Tyson Slocum, a consumer advocate and director of Public Citizen’s Energy Program. “At PJM, any member of the public can attend any of the meetings for free and be able to speak at the meetings where deliberations about tariff design and market design are taking place.”

Amy Boyd, director of policy at the Acadia Center, said that it’s “crucially important for the communities who are going to be … ultimately the consumers of both the energy and air that all of this affects to be involved in a lot of those discussions.”

“Right now, most meetings on regional decisions are not public, nor understandable by the public. Statements made in those meetings are not publicly reported,” Boyd said.

She laid out one concrete idea for starting to address the lack of transparency: that ISO-NE include in all of its proposals information about the expected impacts on state policy, including decarbonization, consumer costs and environmental justice.

“Including a short assessment of the impacts that ISO sees would help states and consumers openly discuss the benefits and tradeoffs of proposals on the table before them,” Boyd said.

Rebecca Tepper, chief of the energy and environment bureau in the Massachusetts Attorney General’s Office, said that ISO-NE should find ways to bolster participation from the states, including possibly funding a position through its tariff to serve as an interface with consumer advocates.

George noted that NEPOOL is a separate entity from ISO-NE, and one that actually predates it, with its own governing rules.

But Slocum, Markey and others in the room didn’t accept that fact as absolving the grid operator from responsibility.

“ISO-NE could say publicly and firmly, we need a stakeholder process that any member of the public could participate in,” Slocum said. Or the grid operator could ask FERC to change the stakeholder process to prioritize inclusion, he said.

Markey called the New England energy stakeholder process one that is “controlled by the priesthood of experts.”

“We’ve got to break up NEPOOL. They’ve got a vice-like grip over this secretive process,” said Markey, saying he’d like to see a poll of NEPOOL members to find out which of them are opposed to more transparency and public participation.

Looking Forward at 25

As George was facing down questions about ISO-NE’s future, the grid operator itself was preparing to release a document looking ahead and painting its role in a rosier light.

Major New and Retiring Resources Map (ISO-NE) Content.jpgNew England’s major new and retiring resources. | ISO-NE

The RTO published its Regional Electricity Outlook on Tuesday, the 25th anniversary of its inception.

The presentation lays out four key pillars for the region’s future: “significant amounts of clean energy resources, sufficient balancing resources to ensure reliability, a reliable fuel supply or energy storage reserve, and a robust transmission system.”

It puts forward graphics about the resources that are coming to the grid in New England and leaving it. And it describes the vulnerabilities that ISO-NE has been worrying over and working on fixing, like fuel constraints and extreme weather.

“Over the last 25 years, ISO New England has laid the foundation to support the four pillars discussed in this report, and the region is already well along the path to a clean energy future,” wrote CEO Gordon van Welie and Board of Directors Chair Cheryl LaFleur. “As we keep our eyes on the horizon, New England has an opportunity to serve as a model for what a sustainable, reliable and efficient transition can look like.”

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DOE Changes Funding Rules to Help Diablo Canyon Stay Open

The U.S. Department of Energy approved rule changes Thursday meant to allow California’s last nuclear plant to apply for federal aid so it can keep operating beyond its scheduled retirement date.  

Pacific Gas and Electric plans to shut down its Diablo Canyon Power Plant in phases starting in 2024, but Gov. Gavin Newsom is hoping to keep it running to deal with potential capacity shortfalls over the next four summers.

Newsom’s cabinet secretary Ana Matosantos wrote to Energy Secretary Jennifer Granholm in May, asking that DOE amend its eligibility criteria for the Biden Administration’s $6 billion Civil Nuclear Credit Program (CNC), funded under November’s Infrastructure Investment and Jobs Act. The program is meant to assist nuclear plants at risk of closure for economic reasons.

In an April guidance, DOE had said CNC funding is for nuclear plants that participate in competitive energy markets and do not recover more than 50% of their costs from cost-of-service ratemaking. PG&E recovers its Diablo Canyon costs from customers under rate cases approved by the California Public Utilities Commission and would not qualify for CNC funding under that interpretation.   

In her letter, Matosantos requested that DOE’s guidance be changed to exclude the cost-of-service requirement. The state is facing a shortfall of 1,800 MW during peak summer hours after solar goes offline, she wrote. Diablo Canyon provides 8.5% of in-state generation and is needed beyond its planned retirement date to maintain reliability as it transitions to 100% carbon-free energy, she said.

The department’s April guidance was “overly broad, especially where cost-of-service does not cover the costs for which funding is being sought.” For Diablo Canyon to “extend operations, it would incur significant transition costs over the next four years to perform necessary studies, invest in plant enhancements, and obtain licenses and permits. Yet there is no existing cost recovery mechanism for those transition costs” when PG&E sells output from the plant into CAISO’s wholesale electricity market, she said.  

Extending operations at Diablo Canyon would “cause significant economic losses” for PG&E “of the sort that the Civil Nuclear Program was designed to address,” Matosantos contended.

DOE issued a proposed guidance amendment for public comment by June 17, and on Thursday it announced it was making the changes requested by Newsom’s office “given the request’s potential applicability to reactors nationwide.”

“The amended guidance revises the eligibility criteria to replace the requirement that a nuclear reactor applying for credits under the CNC Program not recover more than 50% of its costs from cost-of-service regulation or regulated contracts,” the department’s Office of Nuclear Energy said in a statement. “This change affects the eligibility of reactors who may apply in the first round of awards.”

DOE also extended the application deadline for the first round of CNC funding to Sept. 6.  

“The amended CNC Guidance supports the intent of President Biden’s bipartisan infrastructure law to keep the reactors online that sustain local economies and today provide our nation’s single largest source of carbon-free electricity,” Assistant Secretary for Nuclear Energy Kathryn Huff said in DOE’s statement.

PG&E has yet to commit to keeping Diablo Canyon open and has previously said it plans to move forward with the plant’s scheduled retirement, but in comments to DOE it agreed with the governor’s requested rule changes and asked for a 75-day extension to apply for CNC funding. A budget trailer bill signed last week by Newsom allocates $75 million toward keeping the plant open.

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ERCOT Briefs: Week of July 4, 2022

Peak Demand Hits Record 77.7 GW as Summer Heat Returns

The heat is back on in Texas after a brief respite, with ERCOT again setting records as peak demand reached the extreme estimates of the ISO’s resource assessments issued this spring.

The Texas grid operator set a new high for peak demand Tuesday when load averaged 77.5 GW during the hour-long interval ending at 5 p.m. CT. Load was as high as 77.7 GW at one point, breaking the previous record of 76.6 GW set just last month.

The record is not expected to last long. ERCOT is projecting load to exceed 76 GW each day into next week, topping out above 80 GW on Monday. That would smash staff’s spring prediction that summer load would peak at 77.3 GW in August.

When staff issued its final seasonal assessment of resource adequacy in May, they assumed an extreme scenario of demand hitting 81 GW and thermal outages exceeding 4 GW, leaving about 6 GW of reserves. About 7.1 GW of thermal resources were offline Tuesday morning.

ERCOT Meteorologist Chris Coleman on Wednesday said this week could potentially be the hottest for the system this summer. Temperatures will gradually build all week, with highs between 103 degrees Fahrenheit and 109 degrees common over most of the state, he said.

The ISO on Tuesday issued the summer season’s fifth operating condition notice (OCN), its lowest-level market communication in anticipation of possible emergency conditions, because forecasts indicate temperatures will be above 103 degrees in the North Central and South Central weather zones. The OCN is effective Thursday through Tuesday.

ERCOT set four marks for peak demand in June, the last coming on June 23 at 76.6 GW. The previous record had been 74.8 GW, set in August 2019.

PUC OKs DER Pilot Project

Texas Commissioner Will McAdams last week unveiled a three-step proposal for a distribution-level pilot project on distributed energy resources. The process begins with a July 11 workshop at the Public Utility Commission to establish goals and scope. The workshop has yet to appear on the PUC’s calendar.

McAdams said during a June 30 open meeting that he has drawn up a list of 32 entities that might participate in the voluntary pilot project. He is also accepting requests from other entities, including those in ERCOT’s non-opt-in regions.

Noting that nearly 3 GW of distributed generation is already in the ERCOT footprint, McAdams recommended creating a task force to discuss and observe the pilot’s implementation and to discuss obstacles the PUC may have to put aside. He is also urging that a target implementation date, based on stakeholder feedback, be set.

PUC Chair Peter Lake said, “Nothing teaches like experience, so the sooner you get something in the field, the more you learn faster.”

McAdams and fellow commissioner Jimmy Glotfelty are also pushing a parallel proceeding to more efficiently interconnect DERs at the distribution level (51603).

Tesla has been pushing the pilot project as a means of “harnessing” the full potential of DERs as load-modifying and exporting devices dispatchable under ERCOT’s command and control. It recently conducted a virtual power plant demonstration in North Texas in which it aggregated about 60 customers into a single load zone. The company collaborated with ISO staff to set parameters specific to the grid operator’s operations and dispatch rules.

“This is not about one company,” Glotfelty said. “We want this to be broad and diverse.”

ENGIE, Viridity Appeal vs. ERCOT Proceeds

The PUC last week approved an appeal by ENGIE and Viridity Energy Solutions of ERCOT’s alternate dispute resolution determination regarding ancillary services’ settlements during the February 2021 winter storm. The commission directed ENGIE and Viridity to supplement their complaint with additional information during its June 30 open meeting (53377.)

Viridity alleges that it was not compensated for providing responsive reserve service (RRS) during the storm and is owed between $64.7 million and $140.55 million. ENGIE claims it was improperly charged about $47.7 million for failing to provide RRS as required.

Both parties filed their arguments in writing, but the PUC rejected the request for an oral hearing. As is standard practice, the commission declined to give a reason for the denial. It has yet to file an order with details on future actions.

An administrative law judge in May rejected ERCOT’s assertions that the appeal was administratively incomplete.

Steam Unit Goes Seasonal

ERCOT has received notifications from two generation resources that they will soon be suspending operations.

Greenville Electric Utility System told the ISO on July 1 that one of its steam units, GEUS 1, is ending year-round operations to become a seasonal unit, with its operations period running from June 1 until Sept. 30

The unit has a summer seasonal net max sustainable rating of 17.5 MW. It went into operation in 2010.

Last month, OCI Solar Power told the grid operator a 1 MW storage system will be decommissioned and retired permanently as of Nov. 17. The battery is part of OCI’s Alamo solar facility for San Antonio’s CPS Energy.

It is part of OCI’s Alamo Project that provides CPS Energy with 573 MW of solar power. It was the largest solar-PV project in the U.S. when it was developed. Alamo 1 began commercial operations in 2013.

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Electric School Bus Pilot Awaits NJ Governor’s Signature

A bill (A1282) sent to the desk of New Jersey Gov. Phil Murphy last month would create a three-year, $45 million pilot program to test the use of electric school buses in 18 school districts.

The bill, which passed the state Senate on June 16 and the General Assembly three weeks earlier, would require the New Jersey Department of Environmental Protection (DEP) to create the program, under which six districts or contractors each year would take students to school with electric buses to assess the reliability and effectiveness of using them in place of diesel-powered vehicles.

The performance of the buses would be evaluated on factors such as costs, maintenance, fuel use and speed, and data would be collected and submitted to the DEP. At least half of the districts or contractors would be in low-income, urban or environmental justice communities.

Within six months of the end of the program, the New Jersey Board of Public Utilities (BPU) and New Jersey Economic Development Authority (NJEDA) would give the governor a report that includes an estimate of the buses’ emissions benefits and “an analysis of the potential costs and benefits of using electric school bus batteries for storing power to be returned to the electric grid or to school buildings during periods of peak electric power demand,” according to the bill.

The report would also include “recommendations regarding the establishment of grant and loan programs to provide assistance to school districts and school bus contractors for the replacement of their bus fleets,” the legislation states.

Murphy’s office declined to comment on whether he would sign the bill, saying it does not comment on pending litigation. But the state’s Energy Master Plan calls for the state to prioritize the replacement of fossil-fueled public transportation fleets with electric vehicles, especially in environmental justice communities.

In a sign of the scale of the challenge facing New Jersey, Atlas Public Policy, a D.C.-based research and consulting firm, told a forum in October that the state had 15,703 school buses in 2019, and none were electric.

But electric buses are likely to be more cost efficient than diesel in the future, Atlas said. The fuel cost per mile for an electric bus will drop from $2.83 in 2020 to about $1.87 in 2030, at which point it will be cheaper than the cost of diesel, about $2.45/mile, it said. (See NJ Floats New Electric Bus Plan.)

Partisan Divide

The bill is seen by Democrats and environmentalists as a major step forward in the state’s introduction of electric buses.

The Senate Budget and Appropriations Committee on June 6 approved the bill 8-4, with Republicans saying they had concerns about the fact that the state still has no estimate of the cost of implementing the Energy Master Plan.

Before the vote, Sen. Declan O’Scanlon (R) said he had “deep concern about the fact that we are years in now of discussion of the Energy Master Plan, and the administration rolling something out, and we have no idea of the cost. … We have no idea about how quickly we can get New Jersey’s substandard electrical grid up to speed,” he said.

“I get it, moving in this direction is a good idea,” he said, calling his vote “almost a protest vote.” He added that the pilot program “ultimately doesn’t get us very far. Maybe we should be thinking more holistically about the grid and about helping our whole fleet transition.”

Committee Chair Paul Carlo (D) said he also had reservations but would back the bill nevertheless.

“I think the appropriation is a lot of money here until we can prove a plan of how we can implement this and fund it,” he said. But he added that “I believe that the concept is the right thing to move forward and … a step in the right direction.”

Sen. Patrick Diegnan Jr. (D) expressed no such doubts.

“We have got to get started on this. We have to start this process,” he said. “If we wait for the perfect solution, it will never get done. This is the perfect vehicle to try and see how it works.”

Environmentalists, who have long urged state officials to accelerate their efforts to get electric buses into school districts, also welcomed the bill’s passage, saying the state has no time to lose.

“We should be ramping up [electric bus use] as quickly as possible,” said Doug O’Malley, state director of Environment New Jersey, who said the sheer size of the dollar commitment shows that the pilot will have an impact. (See Environmentalists Call for Faster Transition to Electric Buses in NJ.)

“This is $45 million to get electric school buses on our roads. So this is not a small pilot,” he said. “This generation in New Jersey school children should be the last that has to breathe dirty diesel fumes on their way to school. Electric school buses are here. Other states are mandating their use, and New Jersey should catch up.”

New York is “working to transition their entire school bus fleet” to electric buses by 2035, Anjuli Ramos-Busot, director of the Sierra Club New Jersey, told the committee, noting that the plan will go before voters in November. She said the New Jersey pilot is solidly funded, with money from the state’s Societal Benefit Charge, which is levied on all ratepayers to pay for energy investments, and from the Regional Greenhouse Gas Initiative (RGGI).

“This bill is a jumpstart for electric buses in New Jersey,” she said.  While it will be a long way from transitioning the state’s entire school bus fleet to EVs, “It does provide us with a program specifically designed to understand the ins and outs of electric school buses in all regions, geographies and population areas in this state.”

Bill Beren, transportation chair for Sierra, said that New Jersey is “lagging very far behind other states in the region” when it comes to electric school buses. The state has allocated only $25 million of the RGGI funds to buy 77 electric school buses, while Montgomery County, Md., has signed a contract to replace all 250 diesel school buses in their fleet, he said in a release the organization put out in advance of the Senate vote.

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ISO-NE Sends New DER Interconnection Proposal to FERC

ISO-NE sent new proposed rules on distributed energy resource interconnection to FERC for approval last week.

Currently, some DERs use the ISO-NE interconnection process, while others use distinct state interconnection processes, a disconnect that the grid operator says “results in multiple coordination problems and inefficiencies that in some cases result in adverse outcomes for DER developers.”

To solve that problem, ISO-NE is proposing that all new DERs proceed through the applicable state processes.

Transmission owners are currently responsible for determining whether new DERs have to use the state or RTO process, and they use different mechanisms and assumptions, ISO-NE said. The large number of DERs coming online has also made it “increasingly difficult for the [TOs] to track the status of thousands of feeders throughout New England.”

During NEPOOL stakeholder meetings, an ISO-NE official called the process “extremely challenging and time-consuming.” (See “DER Interconnection Process,” NEPOOL Transmission Committee Briefs: March 23, 2022.)

ISO-NE requested that its tariff revisions become effective on Aug. 28.

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MISO Monitor Prescribes 5 New Fixes in Annual Market Report

MISO is currently evaluating five new recommendations from its Independent Market Monitor that include transmission reconfiguration plans, reducing out-of-market commitments, a future-looking dispatch model and ensuring the RTO only pays for real load reductions.

Monitor David Patton, Potomac Economics’ president, issued five new recommendations last month as part of his 2021 State of the Market report.

The Monitor says MISO should:

  • work with its transmission owners to identify and implement economic transmission reconfiguration plans to better manage congestion;
  • evaluate and restructure its unit commitment process to reduce out-of-market commitments and ensuing make-whole payments;
  • develop a multi-hour, look-ahead dispatch and commitment model to better manage fluctuations in net load and decisions on using storage resources;
  • improve rules around demand participation in energy markets so that MISO only pays for load reductions that occur; and
  • consider classifying load-modifying resource (LMR) curtailments as short-term demand in pricing models and the unit dispatch system.

The last recommendation comes after Patton noticed that LMRs are allowed to set real-time energy prices long after emergency conditions have passed. He said that’s because of MISO’s extended marginal locational pricing (ELMP) model respecting resources’ ramp rates, which makes it impossible to replace a large volume of LMRs within a single dispatch interval. He said if the RTO would treat LMRs as an operating reserve demand in the ELMP model, it would eliminate the need for other resources to ramp up and replace them.

Patton said he also believes an hours-ahead dispatch model will be a “key component of the MISO markets’ ability to economically and reliably manage the transition of its generating portfolio.”

MISO’s out-of-market commitments and the associated revenue sufficiency guarantee costs increased “substantially” in 2021, Patton said in calling for staff to examine their commitment process.

“Our analysis indicated that most of these commitments were not ultimately needed to satisfy MISO’s energy, operating reserves and other reliability needs,” he said.  

Finally, Patton said MISO should get a better handle on its demand response resources.

“In the past few years, we have identified a number of cases where demand response resources or energy efficiency resources were paid substantial amounts for load reductions that were not realized,” he said in the report.

While he said some of the problem is because of “conduct of the resources,” he also said some of the issue can be ascribed to “suboptimal tariff and settlement rules.” MISO could use better settlement calculations “to ensure that the estimated load reductions truly represent the additional load that would have existed but for the demand response resource,” Patton said.

MISO is set to review with stakeholders the report’s recommendations and its initial response during an Oct. 13 Market Subcommittee meeting. MISO spokesperson Brandon Morris said the grid operator’s executive leadership will deliver a formal response to the recommendations during the Board of Directors’ Markets Committee meeting in early December.

Under its tariff, the RTO has 120 days to make a public response to the annual report’s recommendations.

In the meantime, MISO and its transmission owners continue closed door meetings of the new Reconfiguration for Congestion Cost Task Team (RCCTT) that was formed at the beginning of the year. The group focuses on plans to reroute transmission flows during times of heavy congestion costs and could address Patton’s first recommendation. (See “RTO Forms Task Team for Tx Reconfigurations,” MISO Planning Subcommittee Briefs: Feb. 8, 2022.)

The nonpublic RCCTT maintains a monthly list of the footprint’s top congested constraints.

Some stakeholders have said MISO is about a decade away from significant new transmission that can manage increasing congestion. Reconfiguration plans are desperately needed in the interim.

Patton delivered a state-of-the-market presentation last month where he focused on his longstanding recommendation that MISO adopt a sloped demand curve in its capacity auction. (See MISO Warming to Patton’s Sloped Demand Curve.)

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Independent Power Producer Sees Risk from Wash. Cap-and-trade

The non-utility owner of a Washington gas-fired power plant says the facility faces unfair treatment under the state’s pending cap-and-trade program, scheduled to go into effect at the start of next year.

Representatives of Grays Harbor Energy Center, owned by independent power producer Invenergy, voiced concerns last month that the 620-MW plant will not receive an initial allocation of free cap-and-trade allowances from the state, unlike utility-owned generators in Washington.

“All the state’s power plants need to be on the same footing,” Grays Harbor Energy representative Torey Mielke said during a June 21 public hearing to discuss cap-and-trade program rules, which are being developed by Washington’s Department of Ecology.

Plant manager Chris Sherin contended that the state’s other natural gas power plants produce 35% more carbon emissions on the average than Grays Harbor Energy Center.

“The Washington Climate Commitment Act is structured to allocate no-cost allowances directly to utilities. Utilities may then use those no-cost allowances for compliance under the law for the emissions from utility-owned natural gas facilities or other sources,” Invenergy told NetZero Insider in an email. “Grays Harbor Energy Center, which is the state’s least carbon-intensive natural gas facility, is not eligible to receive no-cost allowances directly as it is an independently owned natural gas facility.”

Grays Harbor Energy officials have also expressed concern about their plant having to compete with out-of-state power producers that don’t have to spend money on carbon-combating measures that are required in Washington.

The Ecology Department acknowledged that Grays Harbor Energy is the only gas-fired power plant in Washington that is not owned by a public utility, which means it does not receive the same no-cost carbon allowances as the utility-owned power plants. The carbon emissions are calculated the same way for both utility-owned plants and non-utility-owned plants, they noted.

There is a chance that Grays Harbor could lobby the legislature to make the financial aid the same for both types of gas-fired plants, the agency said. 

Rules Take Shape

The details of Washington’s new cap-and-trade program will continue to be tweaked until it goes into effect on Jan. 1, 2023.

The Department of Ecology held a series of public hearings last month to help nail down the regulations to implement the Climate Commitment Act, passed by the legislature last year.

Changes made so far to the regulations include requiring participants to be subject to Washington’s courts and state administrative tribunals in disputes, said Kay Shirey, the project’s rule development leader at the Ecology Department. 

About 25% of Washington’s carbon emissions won’t be covered by the cap-and-trade law, Shirey said. These include emissions from agriculture, businesses emitting fewer than 25,000 metric tons of carbon a year, landfills, aviation and most marine vessels. 

Washington was the second state to adopt a cap-and-trade law after California, which is in a cap-and-trade pact with Quebec. Washington’s auctions will be handled by the Western Climate Initiative (WCI). No timeline has been set for Washington to link up with the WCI.

A 2021 Ecology Department report put the state’s CO2 emissions at 99.57 million tons in 2018.  A state law calls for overall emissions to be reduced to 50 million tons by 2030, 27 million tons by 2040 and 5 million tons by 2050.

Under cap-and-trade, carbon emitters would have to acquire allowances for specific amounts of carbon pollution, which they can buy, sell or trade with other businesses. The maximum volume of statewide emissions would decrease over time.

The Ecology Department’s plan calls for an undetermined number of emissions allowances to be auctioned four times a year to smokestack industries. The first two auctions are scheduled for the first half of 2023, and the state will set the number of allowances 60 days prior to the auctions.

Companies would bid on the allowances in clusters of 1,000 individual allowances. The number of allowances will be decreased over time to meet 2035 and 2050 decarbonization goals. If Washington chooses to join the California-Quebec pact, it would expand its purchase and trading territory to those two areas.

For each auction, a specific number of allowances would be made available to bidders. All bids must be above a certain price level set in advance by the state. 

The highest bidder would get first crack at the limited number of allowances, while the second highest bidder would get the second crack, followed by additional iterations. The auction ends when the last of the designated number of allowances is bid upon. Then all the successful bidders pay the same clearing price set by the lowest successful bid.

Bidding companies are limited to acquiring 4% to 10% of the total number of allowances, depending on various criteria.

Companies will also be allowed to bid on offset credits that are used to preserve urban and rural forests, which absorb carbon from the atmosphere.

Washington has already begun selling forest-related carbon credits. The Washington Department Natural Resources’ duties include managing the state’s trust lands with the mission of producing revenue from property for various programs such as education. The agency routinely auctions off trees on its lands to be harvested for timber.

A new DNR program will set aside 10,000 acres of forests — with trees that began growing prior to 1900 — that have the potential to be harvested. Offset buyers will bid on carbon credits to keep those carbon-absorbing forests intact. This enables the DNR to achieve its mission of producing revenue from its older forests without having to harvest them for timber.

The new state program has identified 2,500 acres on DNR trust lands to be set aside this year in Whatcom, King, Thurston and Grays Harbor counties, stretching from northern to southern Puget Sound. Another 7,500 acres are scheduled to be identified next year. 

Meanwhile, three owners of urban forests in King County this month sold more than $1 million in carbon credits to Regen Network Development, a Delaware-based blockchain software company. (See Seattle-area Communities Auction Carbon Credits to Preserve Forests.)

Regen is collecting carbon credits from King County to offset its contributions to greenhouse gas pollution elsewhere when its overall carbon footprint is calculated. 

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NJ BPU to Probe 2nd Ocean Wind Delay Case

The New Jersey Board of Public Utilities (BPU) on June 29 agreed to hear a petition filed by developer Ørsted seeking to override Cape May County officials who it says have not responded to its efforts to secure local approvals for the Ocean Wind 1 offshore wind project.

Ørsted is seeking approval to run an underground transmission line from its turbines to the shoreline at Ocean City to a substation in the next town, including through land owned by Cape May County. The developer is seeking to secure permission under a new law passed by the legislature last year and enacted in July that gives the BPU authority to override local government officials in land-use questions concerning offshore wind projects if the board finds that the land is “reasonably necessary” for the project’s construction.

The five-member BPU voted unanimously at its monthly meeting to take up the case and assigned board President Joseph Fiordaliso as the hearing officer.

The Ocean Wind 1 petition follows a similar petition filed by Ørsted in March seeking to override officials in Ocean City who oppose the project. The BPU on June 24 held closing arguments in that case. (See NJ City Calls for Delay to Ocean Wind 1.)

The Ocean City case is the first test of the new law, which was enacted in July, and both cases could provide a roadmap for the difficulties facing other projects in the future. The 1,100-MW Ocean Wind project, which was approved in 2019, was the first of three approved offshore wind farms by the state so far. The BPU has also approved the 1,148-MW Ocean Wind 2 and the 1,510-MW Atlantic Shores, and the state expects to hold three more solicitations for a total of 7,500 MW by 2035.

Obtaining Consent

Ørsted’s latest petition states that in order to advance, the project needs to obtain “certain easements” across property owned by Cape May County and “certain consents” from the county. The project needs a temporary 18-month easement and a 30-foot wide permanent easement, both in Ocean City, the developer’s May 20 petition says.

The project also needs the county’s consent as part of the application for 10 permits needed for the project to advance, the petition says.

Ocean Wind “must have the legal authority and/or consent from Cape May County to perform the project activities on the properties owned by the county,” it says. “Cape May County has been unwilling to provide consents needed for any [New Jersey Department of Environmental Protection] permit applications.”

In a June 7 motion asking the BPU to decline and dismiss the petition, Cape May County argued that Ørsted’s move was premature. Although the new law requires the offshore wind project to make its request to the local government and then wait 90 days for a response before filing any petition, the developer had made only “vague, ambiguous and expressly conditional” requests that don’t meet the definition of “request” under the law, the county said.

Ocean Wind 1 “has not supplied all required information and documents in order for the county to provide consent,” the county also said.

Michael Donohue, the attorney for Cape May County, told RTO Insider that the county is “not against wind-generated electricity.”

“Living in one of the last nearly pristine environments in the state, the people of Cape May County are all extraordinarily engaged when it comes to preserving that environment and its flora and fauna,” he said. “The county is not attempting to delay project approvals.

“The brand new statute in question seeks to transfer the authority of the five, duly elected County Commissioners to the unelected members of the BPU,” he said. “We think it is important that any process that leads to such a result be fair, impartial and unbiased and that it should afford the people of the County of Cape May substantial due process.”

Responding to Cape May’s argument in a June 20 brief, Ørsted said it had been in discussion with the county for two and a half years, and the county had no basis for claiming that the request lacked specificity. The country’s motion to dismiss was “little more than an attempt to delay” the project, the company said.

“The county’s arguments and certification alleging the inadequacy of the [petition] rest not on objective facts, but rather on subjective conclusions that the notice was inadequate,” Ørsted said. The developer added that the law does not require it to “request” the environmental permitting consents, only to “consult” with the county, which Ørsted did in “various meetings and correspondence with the county.”

PSE&G Infrastructure Spending

The board also approved Public Service Electric and Gas’ (NYSE:PEG) Infrastructure Advancement Program (IAP), in which the utility will spend $511 million over four years to replace aging electric equipment, upgrade substations and install electric vehicle infrastructure.

The last of those will “begin preparing the grid for the rapid transition to EVs and enable a greater blend of renewable energy resources by increasing the reliability of the state’s electric grid down to the street and neighborhood level,” PSE&G said in a press release.

The proposal will cost the typical residential electric and gas customer about $1.50/month in 2026, PSE&G said.

PSE&G initially petitioned for an expenditure of $850 million, starting in 2022 and concluding in 2026, with about 85% of the funds to go to electric projects and the remainder for gas projects, the BPU order approving the program said.