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November 16, 2024

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MISO Members Doubt Severity of Long-term RA Alarm Bells

DALLAS — MISO members appeared skeptical at their quarterly meetings that the RTO is destined to face capacity shortfalls before 2030.  

MISO Advisory Committee members at a March 20 meeting cast doubt on predicted shortcomings from both NERC’s 2023 Long-Term Reliability Assessment and MISO’s latest version of its Reliability Imperative report. 

MISO was elevated to a high-risk area by NERC late last year; the agency predicted the footprint would grapple with a 4.7-GW shortfall by 2028.  

And last month, MISO warned that members are powering down dispatchable units too quickly and aren’t building equivalent generation able to pick up the slack on the grid. (See MISO Publishes Call to Action to Bypass Danger in Reliability Imperative Report.) 

Minnesota Public Utilities Commissioner Joseph Sullivan said capacity shortages projected in NERC reports haven’t transpired, while some regions previously designated as low risk have experienced blackouts. He said state commissions and utilities have cooperated to delay retirements and ensure resource plans are sufficient.  

The Michigan Public Service Commission on March 15 cited resource adequacy worries when it rejected Consumers Energy’s early termination requests on two power purchase agreements with biomass plants. The commission said that “relying on unpredictable markets for replacement supply outside of a comprehensive integrated resource planning process in this manner entailed an unacceptable level of risk.” 

Sullivan also said the Organization of MISO States and MISO’s annual RA survey “affords more context and granularity” than NERC reports.  

The Union of Concerned Scientists’ Sam Gomberg agreed that states historically have kept the lights on and that NERC’s projected shortfalls haven’t emerged.  

“I think there’s a lot of reactionary effect when we see our region in red. But it’s NERC’s job to keep these fires lit. … This is not to obviate the sense of urgency,” Gomberg said. “I want to emphasize the role of the states.” He said he had faith that states will help MISO “get over the hump” of turbulent years of thermal retirements and replacement with clean power sources. He also said NERC’s report seemed flawed because it relies on a drop in resource additions by 2028.  

The Union of Concerned Scientists’ Sam Gomberg | © RTO Insider LLC

Gomberg also said he noticed MISO is working on several initiatives NERC suggested.  

“Perhaps the sky is not falling, but it does help emphasize to regulators that our plans in place are working,” WEC Energy Group’s Chris Plante said.  

But Michelle Bloodworth, of coal trade organization America’s Power, said it’s well known that solar and wind generation cannot provide the six operating attributes MISO has singled out as critical to the system. She said the premature retirement of mostly coal resources is connected directly to the reliability crisis.  

MISO has defined six system reliability attributes as vital to the system, including availability, rapid start times, the ability to deliver long-duration energy at a high output, and providing voltage stability, ramp-up capability and fuel supply certainty. (See MISO: Attributes Work Won’t Result in New Obligations on Retirements, Interconnection Queue.)  

Bloodworth said it’s a wake-up call that NERC raised MISO from “elevated” to “high risk” in its latest assessment. She advised MISO to be “cautious about any thermal generation that is retiring, not just coal.”  

Clean Grid Alliance’s Beth Soholt said both the NERC Long-Term Reliability Assessment and MISO’s Reliability Imperative struck an unnecessarily catastrophic tone.  

“I think our sector would rather have a tone of ‘this is what needs to be done’ rather than ‘the sky is falling’ alarmist [rhetoric],” she said.  

Soholt also said MISO and states could do more to make sure energy storage can serve as a source of dispatchable power in the fleet transition.  

However, Bloodworth said she commended the “sober” tone because there is cause for concern, with 19 GW of MISO’s coal fleet set to retire in the next five years and even new natural gas investment threatened by EPA’s proposed carbon emissions rule.  

“A megawatt is only as good as the people it’s delivered to,” Bloodworth said.  

Gomberg said coal use is “devastating from the cradle to the grave” in terms of toxic environmental and deadly public health consequences.  

“The quicker we can move on from coal, the better,” he said.  

Yvonne Cappel-Vickery, the clean energy organizer for the Alliance for Affordable Energy, said it would be helpful if utilities were more open with customers about their resource plans.  

Travis Stewart, representing the Coalition of Midwest Power Producers, said in addition to new resources, MISO needs new transmission, especially merchant HVDC lines.  

“You can read that same headline for the past 10 years,” OMS Executive Director Marcus Hawkins said weeks earlier about MISO and NERC warning about a pending shortfall in the next three to four years.  

But state regulators are working relentlessly to ensure that “MISO’s worst nightmare doesn’t come true,” Hawkins said at the Gulf Coast Power Association’s March MISO-SPP conference. However, Hawkins said new load growth and the hastening fleet transition means different factors are at play in estimating capacity adequacy.  

“We’ve had quite an erosion in our resource adequacy,” MISO CEO John Bear told board members and stakeholders at MISO’s March 21 board meeting.  

Bear said the grid operator is going to have to ensure it conducts sufficient analysis to be confident in its decisions’ safety before moving ahead on more RA initiatives. Nevertheless, he said, moving ahead is a must.  

Bear predicted MISO won’t have glowing news to share in its next RA survey due in summer in partnership with OMS. He said RA concerns are compounded by significant load additions across the footprint and system stability concerns.  

“I want to remind people, as we move forward, there are going to be very new risks,” Bear said.  

Iowa Utilities Board member and OMS President Josh Byrnes agreed the RA risks are real, and the solutions are complex; however, he urged fellow commissioners and members to “stay positive.”  

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FERC Accepts NYISO Proposal to Coordinate Queue, Transmission Processes

FERC on March 19 approved NYISO’s proposed tariff revisions aimed at harmonizing its generator interconnection and transmission planning processes (ER24-951). 

The changes are intended to improve coordination between NYISO’s Class Year study in its Large Facility Interconnection Procedures with the facilities study for transmission projects under its Transmission Interconnection Procedures. Additionally, the revisions amend the base case inclusion rules in the ISO’s Small Generator Interconnection Procedures to ensure more precise accounting of identified interactions. 

NYISO argued the changes will prevent transmission projects from being studied in isolation from projects in the interconnection queue or undergoing overlapping evaluations, thereby improving the efficiency of each process. 

The ISO’s proposal included revising security posting requirements for transmission projects. Developers will be required to post security for upgrades before, rather than after, executing a transmission interconnection agreement. This change is expected to reduce the need for restudies of network upgrade facilities, which should make it easier for projects to be included in the existing system representation for the next Class Year study, the ISO argued. 

“We find that [the revisions] would accomplish the purposes of Order No. 2023 by improving the efficiency of NYISO’s interconnection request process and the accuracy of the models used in NYISO’s interconnection studies,” the commission said. “This will contribute to increasing the overall efficiency of the interconnection process, which will help ensure that interconnection customers are able to interconnect to the transmission system in a reliable, efficient, transparent and timely manner.” 

The proposal had been in development since 2022, before Order 2023 was issued, as one of the ways NYISO sought to unclog its interconnection queue. After Operating Committee approval in December of that year, several events led the ISO to delay bringing it before the Management Committee, including Order 2023 itself, as it wanted to ensure the proposal did not conflict with the order. The MC unanimously endorsed the proposal in October. (See “Interconnection & Transmission,” NYISO Management Committee OKs $195M Budget, 5.6% Rate Increase.) 

NYISO submitted an interim, “partial” compliance filing for Order 2023 in November. The deadline for its full compliance filing is April 3. The order, issued in July, directed grid operators to change their interconnection procedures from first-come, first-served to first-ready, first-served. 

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Report Calls for More Policies to Bolster Domestic Solar Manufacturing

The U.S. needs to take action beyond incentives from the Inflation Reduction Act and the CHIPS and Science Act if it wants to create a truly domestic solar manufacturing industry, according to a report released by the Solar Energy Manufacturers for America (SEMA) Coalition on March 20. 

SEMA’s members produce solar panels and their components in the U.S.; they include firms such as First Solar, Q-Cells and REC Silicon. The organization hired Guidehouse Insights to produce the report, “Inflection Point: The State of US PV Solar Manufacturing & What’s Next.” 

The IRA generated a lot of excitement about increasing the domestic share of the solar supply chain, with policies such as a 10% bonus to the investment tax credit for using domestic panels, but the country’s competitors have responded, SEMA Executive Director Mike Carr said on a webinar. 

“Without a U.S. policy response to the current influx of imports in both components and finished products, resulting in significant oversupply, recent factory announcements will likely not come to fruition,” the report said. “While the groundwork has recently been laid for a strong domestic solar manufacturing ecosystem, significant gaps remain and present a threat to its long-term viability.” 

Solar has gotten cheap enough that utility-scale capacity should make up about 40% of all generation installed this year, and that share could grow to 60% over the next decade, the report said. Higher prices from higher tariffs and other policies incentivizing domestic consumption would not be enough to derail that, SEMA argued. 

“This steady state of deployment is really kind of disconnected from the module prices,” Carr said. “Those have bounced around a fair amount in recent years, including hitting new lows this year, and it really doesn’t affect the trajectory one way or another.” 

The effective duty rate on imported solar has dropped from 9.6% in 2021 to just 0.4% last year, but even a ban on imports would not be a boon for domestic manufacturing, as this year’s demand is vastly outweighed by supply because of stockpiling, said Guidehouse Senior Research Analyst Peter Marrin. 

“Even if these imports stopped today, we still have a huge problem. … We have about 2.4 to 2.7 times the amount of module supply relative to demand,” he said. “So, we’re that overstocked.” 

Solar photovoltaic panels’ supply chain starts out with turning mined quartz into high-quality polysilicon; pulling that into ingots; slicing wafers from the ingots; producing PV cells; and then assembling the module. China dominates the global manufacturing of all those steps, but its share is highest in ingot and wafer production. 

“The U.S. currently could produce enough polysilicon to make about 20 GW of crystalline silicon products each year, but the country lacks critical next-step manufacturing facilities for the various refinement and component fabrication steps in the solar cell manufacturing process,” the report said. “The U.S. also lacks capacity to manufacture ingots, wafers and cells, and therefore is entirely dependent on global suppliers for these components.” 

A decade ago, the U.S. had nearly a dozen facilities involved in ingot and wafer production that each could produce up to 500 MW annually, but those since have shuttered and now those highest-cost parts of the manufacturing process are the least subsidized by the IRA, the report noted. 

“As a direct result of IRA provisions, the U.S. is seeing a significant increase in announced cell manufacturing and module assembly capacity,” the report said. “If even half of this announced capacity comes online, the U.S. could produce enough cells and modules to meet nearly 100% of its new solar demand through 2027.” 

Those domestically produced panels and modules still would rely on Chinese wafers and polysilicon, leaving the industry vulnerable to price shocks and possible disruptions from geopolitical disputes. 

“Domestically produced solar modules can be roughly 30 to 50% more expensive to produce than imported ones, but various provisions in the IRA aim to reduce this gap by promoting economies of scale and vertical integration,” the report said. “Focusing investments on developing the cutting-edge equipment, knowledge and workforce needed for a strong domestic supply chain can further reduce these costs in time.” 

Beyond tariffs and enforcing anti-dumping trade laws, policymakers can move the ball forward by setting stronger standards for bonus tax credits and using federal procurements to induce demand for domestic production, the report said. The 10% bonus tax credit has not been implemented ideally, Carr said, and the Biden administration has seemed receptive reviewing it.

“More than more than half of the value of the module can be produced outside of the United States, and you can still have your module considered domestic,” Carr said. “And we think … that is not really a recipe for success.” 

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NERC Standards Teams Pushing to Meet FERC Deadlines

The team developing a reliability standard requiring internal network security monitoring (INSM) at some grid cybersystems saw two “big wins” in the recent ballot round for the standard despite it failing to reach the threshold for passage, leaders said at the monthly meeting of NERC’s Standards Committee on March 20. 

Stakeholders returned the proposed standard, CIP-015-1 (Internal network security monitoring), with a 48.52% segment-weighted vote for approval in the ballot round that ended earlier that week, short of the necessary two-thirds majority. (See Industry Sends Back NERC Cyber Monitoring Standards.) FERC has ordered NERC to submit standards requiring INSM by July 9. 

Valerie Ney, the standard development team’s vice chair, reminded SC members that the result represents a significant improvement over the last ballot round in January, when CIP-007-X (the team’s previous attempt at adding INSM to an existing standard) received a segment-weighted vote of just 15.42%. She observed that the choice to create a new standard received overwhelming support, with 97% of respondents who expressed an opinion on the change approving. 

Ney noted that stakeholders were also supportive of the SDT’s decision to remove electronic access control or monitoring systems and physical access control systems from the standard’s applicability list when they fall outside an entity’s electronic security perimeter. Comments on this change were 100% supportive.  

Thad Ness, the SDT’s chair, acknowledged that the authors “got a lot of feedback” on the requirement that entities identify the network locations facing the greatest security risks and how they will develop their monitoring capabilities, and said the next iteration may have to “be a little clearer on that front.” He also mentioned that respondents pointed out “operational limitations” with the standard’s communication requirements, in that some substations “might not have a strong bandwidth to get this data and move it around.” 

“We really thank the industry for providing some really good comments,” Ness said. “I do believe this is going to have an abbreviated posting [timeline] for the next round … so we are up to the task of doing any outreach to make sure the industry is aware of what we’re doing with the changes and can get the support for this.” 

The SDT will meet March 21 to discuss its next moves. 

IBR, Cold-weather Ballots Approved

Committee members at the meeting voted unanimously to post four other proposed reliability standards for ballot and comment periods. 

First up were two standards under development by Project 2020-02 (Modifications to PRC-024 — generator ride-through). The project is intended to address performance issues identified in inverter-based resources, causing generators to trip offline unexpectedly and potentially cause grid stability challenges. 

PRC-029-1 (page 60 in the agenda) is a new standard that creates ridethrough requirements specifically for IBRs, while PRC-024-4 (page 14) updates ridethrough requirements found in the existing PRC-024 standard applicable to synchronous resources. Both standards will be posted for a 25-day comment period; the committee authorized shortening the typical 45-day period at its December 2023 meeting because the project is responding to FERC Order 901, which imposed a Nov. 4, 2024, deadline for IBR performance standards addressing IBR performance issues. 

Also approved for a 25-day comment period was PRC-030-1 (Unexpected inverter-based resource event mitigation) (page 83), under development by Project 2023-02 (Analysis and mitigation of BES IBR performance issues). The proposed standard, also developed in response to Order 901, would require “analysis and mitigation of unexpected or unwarranted protection and control operations from IBRs.” SC members approved a waiver for this project at the December meeting as well. 

Finally, the committee authorized the posting of TPL-008-1 (Transmission system planning performance requirements for extreme weather events) (page 96) for a 45-day initial formal comment period. This standard would require entities to develop benchmark planning cases based on previous extreme cold or hot weather events, use those cases to plan for future extreme events, and develop corrective action plans when performance requirements for extreme heat and cold are not met. 

Project 2023-07 is also developing this standard in response to a FERC directive, in this case Order 896 requiring a standard to be submitted by December 2024 addressing cold weather performance concerns. Although the SC did grant the project a waiver allowing shortened comment and ballot periods, the SDT elected not to pursue this option. NERC Manager of Standards Development Jamie Calderon explained that “the team wanted to ensure that there [were] substantive comments” to help shape their work in the coming months. 

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Calif. Looks to Streamline Process for Issuing NEVI Funds

California officials are exploring how to improve the dispensation of hundreds of millions in federal funding to build a public network of electric vehicle charging stations.

At a March 12 workshop, officials from the state’s Energy Commission (CEC) and Department of Transportation (Caltrans) sought feedback on how dispensation worked during the first round of grant solicitations from the National Electric Vehicle Infrastructure (NEVI) program, which aims to build a national network of chargers to encourage EV uptake.

A part of the federal Infrastructure Investment and Jobs Act (IIJA), NEVI will provide $5 billion to states to build 500,000 direct current (DC) fast chargers that will enable data collection, reliability and long-distance travel in zero-emissions vehicles. California’s share of the funding is expected to be $384 million allocated over five years (See Federal Plans to Electrify Highway Corridors Advancing.) 

The first tranche of funding was released in October 2023 and awards are expected to be granted in late April. The second round of funding is slated to be released in August, and applications are due by November to the Joint Office of Energy and Infrastructure.  

The workshop provided an opportunity for the CEC and Caltrans to present and solicit feedback on the proposed structure and requirements for the second NEVI grant funding opportunity based on comments received about the first solicitation.  

Structure of the Plan

EV charging projects must meet basic requirements to be eligible for NEVI funding. Key among them is the requirement for stations to be publicly available, located no more than one mile from a highway designated as an “alternative fuel corridor” and placed no more than 50 miles apart from each other. The stations also must contain at least four DC chargers of at least 150 kW per port.

Under the 2023 California NEVI Deployment Plan, designated highway corridors are broken into segments containing one or more charging stations. Groups of corridor segments then are identified by geography and ranked to fund the highest-priority areas first. Only private entities, including investor-owned utilities, are eligible to bid into the competitive solicitations to build, own and operate charging stations.

Speaking at the workshop, Jane Berner, strategic investment analyst at the CEC, identified 21 corridor groups in California ranked by characteristics that determine whether the segment is high-priority, including the percentage of the corridor located in a disadvantaged or low-income community, the number of chargers needed along the corridor to complete the 50-mile range requirement and whether the area interlaps with tribal land.

NEVI requires that at least 50% of funded chargers be in disadvantaged or low-income communities and at least 40% in Justice 40 communities, those that are marginalized by underinvestment or overburdened by pollution.  

California’s first solicitation awarded $40,500,000 in grants to six corridor groups. The second round of solicitations offers $110,220,000.

At the workshop, planners discussed two options for establishing corridor groups in the second round: two-part and standalone projects. The two-part project plan would involve breaking 16 corridor groups into priority-based halves. Participants would complete one application to build stations in as many corridor groups as they choose and could be awarded up to three areas. This approach offers available funds more manageably and enables faster deployment and advanced planning, Berner said.  

The standalone option is smaller, involving application to only one corridor group, which could enable a larger applicant pool, Berner said.  

Ranking the corridors by the two-part project structure, a group consisting of Bay Area interstates and I-80 to Sacramento received the highest score, followed by Southern California I-8 and I-10 to the state’s eastern border, and Northern coastal corridors.  

Stakeholder Feedback

Kristian Corby, deputy executive director of the California Electric Transportation Coalition, asked to work with the CEC and Caltrans on utility verification forms — required to inform the level of grid readiness for a project site — to ensure utilities can respond to the volume of forms in a timely manner.

“PG&E got something like 70 requests for completing that form in the lead-up to the past solicitation deadline,” Corby said. “That type of inundation is very difficult for the utilities to process quickly and to give the applicants good information, so we’re working on some recommendations for that.” 

Corby also was concerned that allowing participants to choose between higher- and lower-ranked groups in the two-part project structure would leave out some areas, though he suggested lower-priority groups could be offered as standalone projects.  

“This does open up, I think, the risk that we might get some particularly lower-ranked corridors that maybe no one applies to,” Berner said. “We’ll have to figure out how we’ll handle that case and it think it would probably be that we would just handle them separately.”  

The CEC and Caltrans are developing California’s 2024 NEVI deployment plan. Comments on the plan are due March 25.

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Granholm Receives Chilly Reception at CERAWeek 2024

HOUSTON — A year ago, attendees at S&P Global’s CERAWeek warmly greeted U.S. Energy Secretary Jennifer Granholm with a standing ovation for her role in passing the Inflation Reduction Act (IRA) and its $369 billion in energy security and climate change investments. 

Granholm’s CERAWeek audience offered only tepid applause during her annual appearance March 18, an apparent response to the Biden administration’s January permitting pause for new LNG terminal projects. 

Acknowledging the elephant in the room, CERAWeek Chair Daniel Yergin began his interview with Granholm by asking her, “The LNG pause: What is it and what isn’t it?” 

She responded by pointing out the pause was enacted to study the environmental effects of approved LNG projects. The U.S. remains the world’s largest LNG exporter at 14 million Bcf, Granholm said. She said an additional 12 million Bcf is under construction and 48 million Bcf has been authorized, with an additional 22 million Bcf authorized but waiting on final investment decisions. 

“This pause does not touch any of that. This is just a pause to see what the future could bring,” Granholm said. “We have a responsibility under the Natural Gas Act to approve authorizations for LNG if they are in the public interest. This study is like other studies we’ve done in the past, just assessing where we are so that we can move forward.” 

Turning to Yergin, she said, “Dan, I predict that when we sit here next year — she says with confidence — this will be well in the rearview mirror.” 

Noticing the muted response in the ballroom, Granholm added, “I think that’s an applause line.” 

U.S. Sens. Joe Manchin (D-W.Va.) and Dan Sullivan (R-Ala.) piled on later during appearances with Yergin and in a visit to the media center. 

U.S. Sen. Joe Manchin | © RTO Insider LLC

“The pause needs to be paused,” Manchin said, calling the move a “political gesture” and saying the environmental study has not yet been conducted. 

He noted LNG production has gone from nothing in 2016 to 14 million Bcf today and natural gas prices are still $2/MMBtu or less. 

“I’m afraid that the market will be shorted here. The United States consumer will pay more, or the economy in the United States could be threatened. None of that’s ever been discussed,” Manchin said. “The pause has to be stopped until the facts of what we’re dealing with support the target. You just don’t throw a curveball and scare the bejesus out of the markets and our allies.” 

Sullivan said the pause was the talk of last month’s Munich Security Conference, where he co-led a bipartisan group of a dozen U.S. senators. He disputed recent comments Granholm made before Manchin’s Energy and Natural Resources Committee, when Sullivan said she “essentially said our allies weren’t that concerned [about the pause].” 

“That’s not what we’re hearing in Asia and in Europe. Every ally that we spoke to [in Munich] had major concerns about the Biden administration’s LNG moratorium. I mean, the most senior German officials, [European Union] officials, everybody,” he said. “It’s not the time to be taking away one of the most critical weapons that we have provided our fellow allies in Asia and in Europe, and that’s American energy. A lot of us think it’s about domestic politics, but it’s having serious consequences with regard to our national security and the national security of our allies.” 

The pause is driving interest and potential investment in countries like Qatar, Sullivan said. In a letter he co-wrote with three other Republican senators intended for John Podesta, the administration’s senior adviser for international climate policy, Sullivan said the Middle Eastern country plans to expand its LNG production, which could result in control of 25% of the global market by 2030. 

U.S. Sen. Dan Sullivan | © RTO Insider LLC

Noting that Russia reached out to Germany after the pause’s announcement, Sullivan said, “That is exactly the opposite of the policies that we’ve been trying to undertake in a bipartisan way after the brutal invasion of Ukraine, which is to enable our allies to get off Russian oil and gas. This is a strategy that is upside down in terms of what we’re trying to do as a country.” 

Granholm and the senators did reach common ground on improving the energy infrastructure permitting process. a task that sometimes seems insurmountable. 

“We keep talking about getting a permitting bill, we keep trying to have it, but it’s hard to get cooperation,” Granholm said. “There is some bipartisanship around permitting reform and moving quickly. We’re doing what we can on the executive side.” 

As an example, Granholm said, the administration has instituted a two-year “shot clock” permitting transmission on public lands.  

“We’d love to see that kind of shot clock for all kinds of permitting in the U.S.,” she said. 

Asked about his energy committee’s objectives for the rest of the year, Manchin, who chairs the committee, said, “I’ve got to get permitting done. I’m doing everything we can. We want to get it done. And I think people are concerned about it. We are so close.” 

Manchin said he enjoys not just the administration’s support, but the support of all stakeholders. 

“Everybody’s supportive,” he said, “but what happens is everybody is supportive of any good idea, but they end up letting the perfect be the enemy [of the] good.” 

“It’s critical to the country, critical to every state,” Sullivan said of the reform. “You talk to any mayor in America, you talk to any governor in America, it doesn’t matter what party, they know that it’s killing us that it takes some nine years to permit a bridge. It’s imperative that we get it done, and I do think there’s a political will. It just makes sense.  

“There’s a whole bunch of ways in which we can tighten up our permitting system that makes our country stronger and all our research development projects … so I’m going to keep pressing it as long as I’m in the U.S. Senate.” 

Back in the ballroom, Granholm said the IRA, described last year as a “big carrot,” is being “gobbled up voraciously” by investors.  

“It’s just amazing how the tax credits are doing the work of reshoring manufacturing and making that happen,” she said, reminding attendees that the IRA is also a jobs program. “It’s really so gratifying to see that we now have an industrial strategy in this country and that we’re not just going to be passive bystanders to the loss of manufacturing jobs.” 

She also announced the release of DOE’s latest Pathways to Commercial Liftoff report, focused on geothermal energy, and the new Regional Energy Democracy Initiative. REDI is meant to empower communities to work with businesses, community groups, academic institutions and philanthropists to “weave” equity and justice into DOE-funded clean energy projects. 

The initiative will begin with a pilot program along the Texas and Louisiana Gulf Coast but could expand with DOE’s plans to award more than $8 billion for carbon-reduction and clean energy infrastructure projects.  

“Ultimately, we have two clear goals: first, meet the needs of today, and second, move quickly and intentionally for the realities of tomorrow,” Granholm said. “It’s a question of will. I know there may be some in this room who would prefer to wait and see or to maybe push the burden of tackling climate change onto others. But let’s be clear. Consumers are calling for change. Communities are calling for change. Investors are calling for change.” 

Granholm called on her audience to help manage the transition “responsibly and with urgency” and to provide opportunities for investors, communities and workers. She said they have the power to increase their companies’ investment returns and “heal our planet.” 

“But make no mistake, what we are witnessing now, what we are participating in, is historic,” she said. Dropping a reference to the musical “Hamilton,” Granholm closed by saying, “You are going to be able to tell your grandchildren that you were in the room where it happens. It is a once-in-a-lifetime challenge and a once-in-a-lifetime opportunity.” 

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Calif., Quebec, Wash. to Explore Linking Carbon Markets

Washington state could be closer to joining the California-Quebec carbon market after the three governments issued a statement March 20 saying they will explore linking their cap-and-trade systems. 

The announcement came about a year after Washington held its first quarterly auction of carbon allowances following its cap-and-invest program’s launch in January 2023.  

California implemented cap-and-trade in 2013, followed by Quebec in 2014, with the two subnational governments merging their systems in 2014. Advocates of adding Washington to the mix cite the expectation that a larger market would increase liquidity in allowances and reduce costs for businesses and other organizations needing to meet greenhouse gas reduction targets.  

“Linking the California-Quebec carbon market and the Washington carbon market would enhance the ability of all three jurisdictions to work together to develop and implement cost-effective programs to fight climate change, while allowing each jurisdiction to maintain authority over its own program’s design and enforcement,” the March 20 statement said. 

In a linked market, allowances issued by each government could be used by businesses in any of the three jurisdictions to comply with their emissions caps.  

“The three jurisdictions would host joint auctions, and market participants could trade across jurisdictions — so allowance prices would be the same across the jurisdictions,” the statement said. “Each government would retain authority over their respective programs, but businesses would gain access to a larger pool of allowances.” 

‘Mutual Interest’

Wednesday’s joint statement notes the three jurisdictions already are cooperating by “sharing best practices regarding program design and implementation” through their membership in the Western Climate Initiative. A shared market would deepen that cooperation significantly.

“Though Washington has formally expressed interest in joining the California-Quebec carbon market, today’s joint statement is the first time that all three governments have expressed their mutual interest in forming a shared market,” Caroline Halter, spokesperson for the Washington Department of Ecology, which oversees that state’s program, told NetZero Insider via email

Details around integrating the markets will have to be hashed out among the three governments. 

“The three jurisdictions are following their respective processes to explore linking carbon markets. If the three jurisdictions enter into an agreement to link, linkage would then be attained through updates to regulations adopted by each jurisdiction,” the statement said. 

Washington already has advanced on that front. Last month, lawmakers in both Democrat-controlled houses passed a bill along party lines to align the state’s carbon market regulations with those of the California-Quebec market. While Republicans warned against linkage, House Majority Leader Joe Fitzgibbon (D) argued that New York, Massachusetts and Maryland are watching Washington’s efforts with the idea of creating their own cap-and-trade programs to eventually join the bigger market. (See Bill to Link Wash. Cap-and-trade with Calif.-Quebec Passes Both Houses.)  

The earliest the proposed linkage could take place is 2025. Lurking in the background is a Republican-backed November referendum in Washington on whether to repeal cap-and-invest, which critics have blamed for the state’s relatively high gas prices. 

In the auctions held last year, Washington carbon allowance (WCA) prices ranged from $48.50 to $63.03, reaching levels significantly above those in the California-Quebec market. But the first auction of 2024 held earlier this month saw prices for WCAs drop sharply to $25.76, well below the clearing price of $41.76 in the most recent California-Quebec auction.  

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MISO Members Send off OMS Leader Hawkins to Wisconsin PSC

DALLAS — Outgoing Organization of MISO States Executive Director Marcus Hawkins appeared before the RTO’s Advisory Committee for a final time before starting as a member of the Wisconsin Public Service Commission. 

At the March 20 Advisory Committee meeting, Chair and Indiana Utility Regulatory Commissioner Sarah Freeman jokingly introduced Hawkins as OMS’ “short-term” executive director. 

Wisconsin Gov. Tony Evers (D) appointed Hawkins to the Wisconsin PSC the previous week. Hawkins’ term begins April 8 and runs until March 1, 2027. 

“The OMS executive director has resigned his position effective April 5,” Hawkins said to laughter while delivering a final report before the committee. 

Hawkins said he hopes OMS has a “challenging task” ahead of it in selecting a candidate from a qualified pool. 

“If you want, reach out to me. I have some unique insights into that position,” he joked. 

“You have moved OMS forward, and you have left it in a better place than you found it. … You have taken it to a different level,” Robert Kuzman, MISO’s head of stakeholder relations, told Hawkins, eliciting applause. Kuzman added he’s eager to work with Hawkins in his new role. 

“We look forward to continuing our work together,” Freeman seconded. 

OMS is accepting applications for a new executive director through March 29. 

Hawkins has been with OMS since 2016, joining the organization as its director of member services and advocacy. He was promoted to executive director two years later. Before his time at OMS, Hawkins was a senior engineer at the PSC and a program manager and engineer at the Wisconsin Energy Conservation Corp. 

Hawkins holds a bachelor’s in nuclear engineering and a master’s in mechanical engineering from the University of Wisconsin-Madison. 

In a statement at the time of the announcement, Hawkins said he was proud to return to the commission “during such a critical time of rapid change in the utility industry.” 

Hawkins’ appointment occurs two months after Wisconsin’s GOP-controlled Senate refused to confirm former Public Service Commissioner Tyler Huebner’s PSC nomination, though he had been performing duties unconfirmed for four years until that point. The Senate’s refusal to confirm Huebner continues a pattern of Republican senators rejecting Evers’ picks to state commissions and boards. (See Wisconsin Senate Votes to Fire Commissioner Huebner 4 Years into Job.) 

Hawkins will exit the organization before OMS holds its annual Resource Adequacy Summit on May 14-15 in Ames, Iowa, in partnership with Iowa State University. Until his departure, Hawkins will continue to organize the summit. 

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ISO-NE to Study Offshore Wind Points of Interconnection

Building on its 2050 Transmission Study, ISO-NE plans to study the effects of shifting two offshore wind points of interconnection (POIs) from Maine to Massachusetts and analyze regional offshore wind interconnection points, the RTO told its Planning Advisory Committee (PAC) on March 20. 

The 2050 Transmission Study found the transmission upgrades to meet the region’s projected 57-GW 2050 peak load will cost $22 billion to $26 billion. One key constraint identified by the study was the region’s ability to send power from renewables in Maine and New Hampshire south to meet load in the Boston area. (See ISO-NE Prices Transmission Upgrades Needed by 2050: up to $26B.) 

These results are partially contingent on where ISO-NE has modeled offshore wind projects connecting to the grid, locations that are hardly set in stone. 

The finalized Gulf of Maine Wind Energy Area released March 15 (see BOEM Designates Gulf of Maine Wind Energy Area.) is located farther south than ISO-NE initially expected, with much of the lease area “as close, or closer, to Boston as it is to Maine,” Dan Schwarting of ISO-NE told the PAC. 

In response to stakeholder feedback, ISO-NE is proposing to essentially rerun the 2050 Transmission Study with two POIs shifted from Maine to Massachusetts to see if it would reduce the scale and cost of transmission upgrades.  

“These changes result in very little change in the mileage of offshore cables but are expected to significantly reduce stress on the Maine-New Hampshire and North-South interfaces,” Schwarting said.  

Schwarting added that ISO-NE does not expect the changes to eliminate the need for north-to-south upgrades, but that the RTO anticipates “at least some of the upgrades would fall off the list.” 

Additionally, ISO-NE will conduct a “high-level screening of various offshore wind points of interconnection” to provide general information on transmission constraints at different POIs and outline “how much offshore wind can realistically be interconnected into different parts of New England before major transmission upgrades are required.” 

This analysis will be based on loads projected for 2033, instead of projections out to 2050, given the uncertainty of projecting generation and load data beyond 10 years. While the 2050 Transmission Study modeled offshore wind at reduced output levels “to ensure that load could be reliably served during low-wind peak conditions,” the POI screening will study wind projects at their full nameplate capacity. 

ISO-NE will study the POIs up to a capacity of 2,400 MW to determine “an approximate maximum interconnection size before major transmission upgrades are required.” 

While ISO-NE’s loss-of-source limit constrains single points of interconnection to 1,200 MW, the RTO is leading an effort with PJM and NYISO to study raising the limit to 2,000 MW. 

ISO-NE is planning to study sites independently and then consider combinations of feasible POIs to see which can be used concurrently and which are “mutually exclusive,” Schwarting said. 

Schwarting emphasized that the screening “is not a full interconnection study and does not replace the need for such a study.” 

Several stakeholders supported the proposals but cautioned that transmission-system constraints are just one factor in the selection of a POI.  

“There’s a whole lot that goes into interconnecting offshore wind at a particular site,” said Dave Burnham, director of transmission policy at Eversource. “[ISO-NE] is really only looking at a sliver at what it’s going to take.” 

Bob Stein of Signal Hill Consulting Group said moving interconnection points from Maine to Massachusetts could bring political challenges due to the local economic benefits that are expected to accompany POIs. 

“There’s a potential political problem with what good engineering suggests we should do,” Stein said. 

ISO-NE is asking for stakeholder feedback on the proposal by April 4, and anticipates results “at some point in quarter three of 2024.” 

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BOEM Proposes Second OSW Auction in Gulf of Mexico

The federal government is teeing up a second wind energy auction in the Gulf of Mexico. 

The U.S. Bureau of Ocean Energy Management on March 20 proposed a lease of four areas totaling 410,060 acres off the Texas and Louisiana coastlines.  

The proposed sale notice will be published in the Federal Register on March 21, triggering a 60-day public comment period in which BOEM hopes to receive feedback on the size and location of the proposed lease areas, and on potential lease revisions to include hydrogen production with the electricity generated there. 

Also, BOEM is considering lease stipulations requiring that historically underserved communities be considered and engaged early and often in the development process. 

If BOEM decides to go through with this second auction, it would publish a final sale notice. 

BOEM and some industry observers had expressed optimism for the first Gulf of Mexico wind auction, in August 2023, but it drew minimal interest. (See Gulf of Mexico Wind Energy Auction Falls Flat.) 

Only one of the three lease areas offered drew bids, and the winning bid by RWE Offshore US Gulf was just $5.6 million — much less than winning bids submitted for lease areas off the Atlantic and Pacific coasts. 

August 2023 was not a good time for the emerging U.S. offshore wind industry — early movers off the Northeast Coast were struggling mightily with supply chain, financial and infrastructure constraints. 

But beyond that, the Gulf of Mexico presents challenges of its own: weaker winds, softer seabed geology and an annual hurricane threat. 

After the first Gulf auction fizzled, research firm Clearview Energy Partners flagged other factors for its clients: Electricity is relatively inexpensive in the Gulf Coast region and there is not a strong push by state leaders to get electrons flowing from sea to land. 

Production of green hydrogen might be a key motivator for offshore wind development in the region, Clearview wrote, but at the time, the IRS had not issued guidance on the Inflation Reduction Act’s clean hydrogen tax credit. 

The IRS has since issued proposed guidance and may finalize it before a second auction. This could offer developers a clearer picture of the potential economics of offshore wind in the Gulf. 

BOEM said it would use new, more efficient software for the second Gulf auction.  

BOEM Director Elizabeth Klein said in a news release: “We look forward to receiving feedback from tribes, other government agencies, ocean users, local communities and others to minimize any impacts to natural and cultural resources, reduce potential conflicts with ocean uses, and maintain a healthy marine ecosystem.”