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November 16, 2024

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ERCOT Technical Advisory Committee Briefs: March 30, 2022

Committee Approves Task Force to Address Crypto Mining Loads

ERCOT’s Technical Advisory Committee last week approved staff’s request to create a task force to develop policy recommendations for interconnecting large flexible loads, such as cryptocurrency miners that are flocking to the state.

ERCOT has already established an interim process, effective March 25, requiring transmission service providers (TSPs) to submit interconnection studies for large loads that have not been modeled and studied in a completed staff planning assessment and proposing to interconnect to the grid.

The interim process applies to those projects that add 20 MW of demand at a generator within the next two years. Projects that aren’t co-located face a minimum threshold of 75 MW. The rule applies to both new projects and expansions.

The committee debated the Large Flexible Load Task Force’s proposed scope and how deep into the policy weeds its members should get before agreeing to let the group further refine its scope and bring it back before TAC for its April 13 meeting.

“We really need to figure out the reliability issues around these cryptos,” said Bob Wittmeyer, representing Longhorn Power. “Adding things beyond our authority is going to slow down the work of the group.”

“We just want to get this rolling as soon as possible. We’re concerned about how quickly these loads are coming on,” said Woody Rickerson, ERCOT’s vice president of system planning and weatherization. “We have processes to interconnect large loads; that isn’t the issue. It’s this new type of load that’s coming on very quickly that we don’t have the process for.”

The task force will report directly and provide recommendations to the TAC. Staff will lead the group, which will nominate a vice chair for the committee’s approval during its first meeting.

RUC Offer Floor Lowered to $250

TAC members took three separate votes before finally reaching consensus on the Independent Market Monitor’s proposal to lower the reliability unit commitment’s (RUC) offer floor from $1,500/MWh to $250/MWh.

The committee narrowly rejected a proposal to lower the floor to $200/MWh, 17-9 with four abstentions. However, had one of those abstentions been a “yes” vote, it would have passed. A vote to lower the floor to $500/MWh was more soundly defeated, 14-12 with four abstentions, before the $250/MWh compromise passed, 18-8 with four abstentions.

The investor-owned utility segment accounted for 11 of the 12 abstentions, with American Electric Power’s Richard Ross casting a “yes” vote during the final attempt.

The nodal protocol revision request (NPRR1092) also includes a two-hour opt-out provision.

ERCOT established the RUC offer floor when the market construct’s self-commitment was relied upon and RUCs were infrequent. That changed last year with the grid operator’s conservative operations, when it began procuring more reserves to ensure greater grid reliability.

Reliant Energy Retail Services’ Bill Barnes helped hammer out the compromise with Luminant Energy, one of the more vocal opponents to ERCOT’s increased use of RUCs. “We think this addresses concerns about being able to opt-out at the last minute,” he said.

“We’re concerned about out-of-market actions affecting us. We’re not sure whether to start in quick-start mode right now,” Luminant’s Ian Haley said.

Staff still need to provide an impact analysis for the change and committed to do so before the TAC’s meeting this month.

ECRS Resources Face 2-hour Requirement

The committee passed a rule change that requires resources providing ERCOT contingency reserve service (ECRS) to provide two consecutive hours and/or be capable of sustaining four consecutive hours of non-spinning reserve service. The TAC approved NPRR1096 by a 20-3 vote, with seven members abstaining.

Jupiter Power’s Caitlin Smith, who cast one of the opposing votes, filed comments that argued the measure would require a longer duration for an existing service currently awarded on an hourly basis and result in a policy that is not technology neutral. Smith also said the change would narrow the pool of non-spin suppliers and further distorts the market.

“This does seem to be overly cautious and can affect the market by keeping some folks from providing the service,” Sierra Club’s Cyrus Reed said.

The TAC agreed to an action item to review long-duration resources’ solutions that require ERCOT system changes to manage reliability risk related to the provision of ancillary services.

Jupiter recently commercialized its first transmission-connected project, a 100-MW storage facility in West Texas with 200 MWh of duration capacity.

NPRR1096 also requires ERCOT to conduct unannounced tests on energy storage resources providing ECRS and/or non-spin in real time to verify their state of charge.

Helton Replaces Blakey as Vice Chair

Committee members elected Engie’s Bob Helton, a former TAC chair, to replace Just Energy’s Eric Blakey as vice chair.

Blakey, who served as TAC’s vice chair last year, withdrew his nomination for 2022 when ERCOT’s Board of Directors last month declined to confirm his election and that of South Texas Electric Cooperative’s Clif Lange as chair. The board deferred their approval following an executive session. (See ERCOT Board of Directors Briefs: March 7-8, 2022.)

Blakey told members it was his understanding that the directors were uncomfortable confirming him after Just Energy filed a lawsuit in November against ERCOT and the Texas Public Utility Commission. The Canada-based retailer, which filed for bankruptcy after the February 2021 winter storm, is seeking to recover payments that were made by its parties to the grid operator for certain invoices relating to the storm.

Interim ERCOT CEO Brad Jones all but confirmed Blakey’s comments, telling the committee that the directors “had a discomfort because of the relationship with his company.”

“All of the board sees you as a man of high integrity,” Jones told Blakey. “This issue had nothing to do with yourself; it has everything to do with the situation in which we find ourselves.”

“I respect the decision,” said Blakey, who said he intends to remain a TAC member. “Being vice chair is something I’ll always cherish. It’s been an honor.”

Blakey nominated Helton, who served as TAC chair until 2021, as his replacement. Helton was elected without opposition.

“I’ll be glad to help out for the rest of this year,” Helton said, thanking Blakey for his service.

Engie last week filed its own complaint against ERCOT with the PUC, alleging it had not been compensated or credited for ancillary services provided during the emergency alert conditions wrought by the 2021 storm. Jones noted Engie is following ERCOT’s alternative dispute resolution process, which allows an appeal before the commission should its initial complaint be rejected.

The board will have a chance to confirm Lange’s and Helton’s elections during this month’s meeting.

In-person Meetings Return

The meeting was the TAC’s first in person since the COVID-19 pandemic began in 2020 and its first at ERCOT’s new headquarters offices in Austin, as its members acknowledged.

Lange, presiding over his first in-person meeting as the committee’s chair, introduced himself as “the man behind the curtain for the last few years.”

Barnes, sporting a new horseshoe mustache more commonly known as a handlebar, approved the previous meeting’s minutes by raising his nameplate.

“I’m just making sure my card still works,” he cracked.

TAC Endorses 5 Changes

The TAC approved a system change request against three votes from the consumer segment. SCR818 modifies the network model management system and topology processor to incorporate geomagnetically induced currents (GIC) modeling data for maintaining GIC system models in the ERCOT planning area for compliance with NERC reliability standard TPL-007-4 (Transmission System Planned Performance for Geomagnetic Disturbance Events).

Members unanimously approved a combination ballot that included four additional NPRRs:

    • NPRR1116: removes obsolete language from Market Information System Administrative and Design Requirements referencing other binding documents on the system. Those documents are posted to the ERCOT website.
    • NPRR1117: aligns the protocols with SMOGRR025’s revisions allowing losses in short runs of connecting lines to be disregarded where the ERCOT-polled settlement meter is not physically at the point of interconnection.
    • NPRR1122: clarifies that ERCOT will retain all securitization default charge escrow deposits to cover necessary potential future obligations for securitization default charges, and that funds provided for default charge escrow deposits must be sent to the correct account to be properly credited. It also corrects a subscript definition error in the securitization default charge maximum megawatt-hour activity ratio share.
    • NPRR1123: provides for the assessment of securitization uplift charge escrow deposits based on counter-party initial estimated adjusted meter load.
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SERC Alleges Years of Noncompliance by Broad River in $435K Settlement

A whistleblower report unveiled a long history of noncompliance and more than 100 violations of NERC reliability standards at Broad River Energy, SERC Reliability said in a settlement approved by FERC last week that carries a $435,000 penalty (NP22-11).

NERC submitted the settlement with Broad River to the commission in a Notice of Penalty on Feb. 28; FERC indicated in a filing March 30 that it would not review the settlement, leaving the penalty intact.

The settlement stems from multiple infringements of TOP-002-2.1b (Normal operations planning) and TOP-003-3 (Operational reliability data). SERC found that Broad River violated requirement R3 of the former standard — which requires load-serving entities and generator operators to “coordinate [their] current-day, next-day and seasonal operations with [their] host balancing authority and transmission service provider” — and R5 of the latter, dealing with the format and process of delivering data for real-time monitoring and analysis functions.

Broad River’s compliance issues first came to the attention of SERC as the result of an incident that occurred on July 16, 2018. The utility filed a self-report of the incident in November of that year, claiming to have learned of the issue through an anonymous call to the whistleblower line of IHI Power Services, one of Broad River’s contractors.

According to the self-report, Broad River’s BA called the utility to ask it to start one of the five natural gas-fired generating units at its facility in Gaffney, S.C. The utility’s control room operator tried to start Unit 5, but it would not start because of mechanical issues. While Broad River was able to meet the BA’s request by starting another unit, it did not inform the BA that Unit 5 had been taken offline for repairs because the operator “considered Unit 5 to be under troubleshooting and not unavailable as a definitive root cause had not been found.”

Repair work on Unit 5 continued into the night shift, with the BA still not informed that it was unavailable. An operator did not notify the BA of the outage until the following day, more than 24 hours after the problem was discovered, a violation of TOP-003-3. The unit was returned to service in the morning of July 20; Broad River’s self-report said management at the facility did not know it was unavailable until the IHI whistleblower call that day.

Additional Hotline Complaints

In its follow-up investigation, SERC requested IHI’s investigation records and the recording of its hotline call; the contractor provided neither of these, although it did give the regional entity a redacted copy of its investigation report completed in September 2018, which supported the version of events in Broad River’s self-report. However, in April 2019, NERC’s hotline received three anonymous complaints that the utility was “providing false and misleading information and was withholding evidence,” including of additional, unreported similar incidents.

With its suspicions aroused by these allegations, SERC conducted on-site interviews with staff from the facility who were present during the outage of Unit 5, as well as the plant manager at the time of the incident and the former plant manager. The RE found that personnel at the plant lacked knowledge of their reporting obligations under NERC’s reliability standards; in fact, there was “no formal TOP-002/TOP-003 compliance procedure or training for plant personnel” at the time.

SERC also reported finger-pointing between plant management and personnel about who had decided not to declare Unit 5 unavailable and report it to the BA. Both the plant manager during the incident and a predecessor claimed that this was the job of the control room operator; however, SERC found through plant operator logs and interviews that it was Broad River’s practice that “the control room operator contacts the plant manager and the plant manager makes the decision to declare and report a unit as unavailable to the BA.”

In light of these discoveries, SERC suspected that the 2018 event was not isolated and pressed Broad River for a more extensive review. Sure enough, the utility examined its outage logs from January 2016 to June 2019 and found 112 incidents (including the original reported one) where Broad River’s employees did not notify the BA that a generating unit was unavailable. TOP-002-2.1b requirement R3 was enforceable until March 27, 2017, covering 60 of the events; the rest occurred after April 1, 2017, when TOP-003-3 R5 took effect.

Moreover, the investigation found that Broad River received over $130,000 more than it should have during this time period because under its power purchasing agreement, it was paid “partially based on units that were available to run if needed.” This meant that it gained an economic benefit from violating the standards, though SERC acknowledged that considering the overall revenue Broad River received over the relevant years, the monetary “gain was nominal” and unlikely to have been a motive for the violations.

‘Complete Programmatic Failure’

SERC attributed the violations to “a complete programmatic failure [stemming] from a widespread problem with Broad River’s compliance program” that took the form of “vertical organizational silos” separating senior management at the utility from the third-party plant and asset managers at IHI, and plant management from compliance officials.

The RE said this split in management culture led to a lack of oversight of compliance practices from senior officials that amounted to “a culture of compliance that prioritized the PPAs over NERC reliability standards compliance and the reliability and security of the” bulk power system. Broad River also lacked appropriate operating procedures and controls, along with “robust relevant training for those responsible for compliance.”

Not only did the plant and asset managers violate TOP-003-3 and its predecessor on more than 100 occasions, they then tried to hide the extent of the violation from SERC by failing to file a self-report until after the whistleblower had spoken up and by not revealing the other infringements, which at the time of the whistleblower report had been ongoing for more than two years.

“Broad River’s plant and asset manager’s actions resulted in multiple follow-ups for purposes of evidence clarification, the need for on-site interviews with Broad River personnel, and additional data and information requests,” SERC said in the settlement. “The significant time it has taken to fully investigate this alleged violation could have been avoided had Broad River’s agents been fully forthcoming from the beginning.”

SERC said that Broad River’s violation posed a “serious risk” to grid reliability: Because Broad River’s BA depended on the availability information provided by the utility, the lack of data on outages to plant equipment could have led it to make “incorrect decisions and [take] incorrect actions to address real-time system conditions.” The fact that no harm has been attributed to the violation is no excuse, SERC said, because the plant and asset manager made no attempt to correct the issues, meaning they would have likely continued to pose a risk “for an unforeseeable amount of time.”

In addition to the monetary penalty, Broad River agreed to a long list of mitigating actions, which it reported completing on April 13, 2021. The first step in the utility’s plan was to change the operating company and asset management company, and to hire a new plant manager in 2020; the plant’s operation director, the plant manager at the time of the July 2018 incident and the vice president of asset management had already resigned the previous year.

Broad River also took a number of steps to educate personnel about the reporting requirements of NERC’s standards. These include a monthly review by the facility’s compliance manager to ensure operating personnel’s understanding of the requirements, monthly email reminders about the importance of accurate and timely reporting, quarterly reviews of control room logs, public posting of the requirements in the plant’s control room and enhanced training for the NERC compliance manager at the facility.

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IPCC Report Calls for Urgent Action on Climate Change

The world must quickly and radically cut its dependence on fossil fuels or face climate disaster, according to the latest report released Monday by the United Nations Intergovernmental Panel on Climate Change (IPCC).

Diana Urge-Vorsatz (IPCC) FI.jpgDiana Ürge-Vorsatz, IPCC Working Group III vice-chair | IPCC

To even have a chance of limiting global temperature rise to 1.5-degrees Centigrade, the report’s 278 authors say, carbon emissions will have to peak by 2025 and drop, quickly and sharply, 43% by 2030.

“Investing in new fossil fuel infrastructure is moral and economic madness,” UN Secretary-General António Guterres, said in a blistering statement delivered during the online launch of the report.

“Such investments will soon be stranded assets that [are a] blot on the landscape and the blight on investment portfolios.”

Diana Ürge-Vorsatz, a vice-chair of the working group that produced the report, estimated that existing investment in fossil fuels, as of October 2021, could result in $1 trillion to $4 trillion in stranded assets in coming years.

Jim Skea (IPCC) FI.jpgJim Skea, IPCC Working Group III co-chair | IPCC

“This is a climate emergency,” Guterres said. “Climate scientists warned that we are already perilously close to tipping points that could lead to cascading and irreversible climate impacts. We think governments and corporations are not just turning a blind eye, they are adding fuel to the flames. They are choking our planet based on their vested interests and historic investments in fossil fuels when cheaper, renewable solutions provide green jobs, energy security and greater price stability.”

The report, the third and final installment of the IPCC’s Sixth Assessment Report, focuses on climate mitigation measures — from renewables to reforestation and carbon dioxide removal (CDR) technologies — that, it says, must be implemented immediately to slow and eventually reverse the catastrophic impacts of climate change.

“We conclude that without strengthening mitigation efforts, greenhouse gas emissions are projected to lead to warming of 3.2 degrees,” said Jim Skea, co-chair of the working group. “The temperature will stabilize when we reach net-zero carbon emissions.”

Other key numbers in Skea’s opening remarks at the launch event included:

  • As of 2019, GHG emissions were at their highest level in human history — 12% higher than in 2010, the biggest 10-year increase on record, and 54% higher than in 1990. However, increasing climate action is slowing emissions growth, from 2.1% per year in the first decade of the 21st century to 1.3% per year from 2010 to 2019.
  • The decline was particularly noticeable in the energy and industry sectors, where the rate of growth has more than halved.
  • Climate laws that resulted in reduced or avoided emissions are on the books in 56 countries, which together represent more than half of all global GHG emissions.
  • Ongoing price cuts across the renewable energy sector since 2010 — 85% for solar, 55% for wind and 85% for batteries — have led to increases in installed capacity.

The various pathways laid out in the report are by now familiar to the U.S. and global energy industry, with options available in every sector “that can at least halve emissions by 2030 and keep open the possibility of limiting warming to 1.5 degrees,” said Ürge-Vorsatz.

For example, beyond reducing fossil fuels and increasing renewables, “energy efficiency and reductions in energy consumption can be achieved using digital technologies,”  she said. “In this way, it is also possible to decentralize an energy network so that power comes from multiple, localized energy networks rather than one main electricity grid.”

“There is untapped potential here to bring down global emissions between 40% and 70% by 2050, but only if the necessary policies, infrastructure and technologies are in place,” she said.

Ürge-Vorsatz also talked up electrification of transportation and buildings, energy efficient retrofits for existing buildings and tackling hard-to-decarbonize industrial emissions via efficiency, recycling and minimizing waste, along with carbon capture and use of hydrogen.

Political Willingness 

The other two reports in the Sixth Assessment have provided equally strong numbers and dire warnings on the need for action. Issued in February, the second report looked at climate adaptation measures, while the first provided a deep dive into the science of climate change. (See IPCC Climate Report: ‘Half Measures No Longer an Option.’)

A “synthesis report” combining the findings of all three will be issued later this year, IPCC Chair Hoesung Lee said.

But the key challenge lies not in the science or the technology, as Guterres acknowledged, but in the political and financial willingness to commit to immediate action, especially in the midst of the global inflation and rising fuel prices caused by the combined impacts of the COVID-19 pandemic and the war in Ukraine.

Hoesung Lee (IPCC) FI.jpgIPCC Chair Hoesung Lee | IPCC

The report warns that “the continued installation of unabated fossil fuel infrastructure will ‘lock in’ GHG emissions.” According to a footnote, sufficiently abating fossil fuel emissions will require technologies that capture more than 90% of power plant emissions and 50%-80% of “fugitive methane emissions from energy supply.”

“We need to cut global emissions by 45% this decade,” Guterres said. “But current climate pledges would mean a 14% increase in emissions, and most major emitters are not taking the steps needed to fulfill even these inadequate promises.”

Climate politics played out in the release of the report, originally scheduled for 5 a.m. ET on Monday, but delayed six hours, according to multiple media reports, due to last-minute wrangling over the final wording in the Executive Summary for Policy Makers.

On the financing side, Ramón Pichs-Madruga, the working group’s other vice-chair, said that current “financial flows are a factor of three to six times lower” than what will be needed to halve emissions by 2030. “But there is sufficient global capital available … to close investment gaps.”

The ongoing failure of developed countries to meet the $100 billion of investment they promised to developing countries as part of the original Paris Agreement was a flashpoint at the UN Climate Change Conference in Glasgow in November.

As a result, “clear signals from government and the international community, including a strong alignment of public sector finance and policies is critically important,” Pichs-Madruga said, pointing to measures such as “broad-based carbon taxes and emission-trading systems,” that have already proved effective.

“Policy packages and economy-wide packages are better able to achieve systematic change than individual policy instruments on their own,” he said, calling for consensus building across disparate stakeholders.

“When talking about solutions, responding to climate change,” he said, “the starting point is thinking in terms of inclusive actions that consider not only the national governments but also in a variety of stakeholders, including, of course, the local community … but also participation of professional bodies, businesses and different stakeholders.”

Reactions 

Whether this latest report will have a greater impact on U.S. or global action on climate change than its predecessors remains an open question. But environmental and energy groups in the U.S. framed their reactions to the report as putting pressure on Congress to pass the energy tax incentives from the derailed Build Back Better package — in particular for technologies such as carbon capture and nuclear.

Inger Andersen (IPCC) FI.jpgInger Andersen, Executive Director, UN Environment Program | IPCC

Madelyn Morrison, external affairs manager for the Carbon Capture Coalition, said, “This consensus report underscores the critical role that carbon capture and removal technologies and infrastructure must play in managing emissions from existing industrial facilities and power plants, offsetting emissions from hard-to-abate heavy industry, aviation and other sectors, and eventually removing legacy CO2 emissions from the atmosphere. 

“Congress must deliver the full portfolio of federal policy support for carbon management in any forthcoming budget reconciliation legislation, including a direct pay option for the 45Q tax credit,” she said.  

Armond Cohen, executive director of the Clean Air Task Force, praised the IPCC for “formally recognizing the importance of an advanced set of climate solutions like carbon capture, hydrogen and nuclear energy. This problem is bigger than any one sector or solution. It is a fundamental re-tooling of our energy system in record time and we’re going to need more options on the table, not fewer. It’s past time we acknowledge the full scope of the challenge and get to work advancing the full set of solutions we need to meet it.”

John Kotek, senior vice president of policy development and public affairs at the Nuclear Energy Institute, noted that the report calls for a doubling of global nuclear energy generation by 2050.

“We need strong policies that value nuclear energy in driving global economies and place nuclear on a level playing field with wind and solar technologies,” Kotek said. “Governments should also prioritize incentives to deploy new nuclear carbon-free plants, signaling to investors and global banks the significant role of nuclear energy in meeting our carbon-reduction goals.”

Daniel Bresette, executive director of the Environmental and Energy Study Institute, framed the report’s call to fight climate change as an opportunity, first and foremost, “to reduce our dependence on fossil fuels. … To chart this new path, we need a cohesive, coordinated set of policies that are complex and interconnected. This requires Congress to act to deliver these policies here in the United States and provide adequate, equitable financing and financial support for other countries.”

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How 2 Climate Tech Startups Want to Disrupt Steel, Concrete Industries

Alkemy Environmental is preparing to take the next step in its startup journey to commercialize an environmentally friendly concrete aggregate that can lower the carbon footprint of buildings.

“We hold patented technology for recycling industrial waste streams into structural-grade, lightweight concrete aggregates, which are essentially sand and gravel and make up 70% of your standard concrete mix,” Peter Kombouras, CEO of the Somerville, Mass.-based company, said Thursday.

Another 10% of the mix is cement, the production of which is responsible for the bulk of GHG emissions in the concrete industry. Alkemy’s product takes an indirect approach to addressing the carbon intensity of the industry, which accounts for 8% of global GHG emissions.

Through its participation in the Greentown Labs Healthy Buildings Challenge, Alkemy learned that its lightweight aggregate can play a key role in net-zero building design by reducing the load on a building, Kombouras said during a wrap-up event for the challenge.

Reducing a building’s weight means it needs less steel and concrete to reinforce it. And the sustainable aggregate, Kombouras said, lowers the building’s embodied carbon by extending the lifecycle of materials and reducing GHG emissions associated with industrial waste in landfills.

Alkemy can recycle industrial waste streams from plants for waste-to-energy, coal combustion, wastewater treatment, paper production and much more, Kombouras said. The resulting product, he said, is a green building material that meets LEED standards.

Sofia Bethanis, president and chief scientist at Alkemy, developed the waste-recycling solution while at Imperial College London.

“Discussions with our mentors [in the Healthy Buildings Challenge] broaden our vision about the potential applications of our technology and how it fits into sustainable building design and climate-resilient infrastructure,” Kombouras said.

The challenge is a Greentown Labs accelerator program for climate tech startups in partnership with French construction materials provider Saint-Gobain and supported by the Massachusetts Clean Energy Center.

“Buildings account for about half the energy used in the U.S. and about 40% of the carbon emissions,” Greentown Labs CEO Ryan Dings said at the event. “The diversity of the built environment means that we will need a multitude of solutions.”

Five startups participated in the program to discover how their products can support carbon neutrality for buildings. The program provided opportunities for the companies to identify the best avenues for product commercialization and to work with established partner companies with an eye for growth.

Alkemy came out of the program with a plan to work on pilot projects with Saint-Gobain to demonstrate the aggregate technology and potentially retrofit existing Saint-Gobain subsidiary lightweight aggregate plants.

Steel Alternative

InventWood joined the Healthy Buildings Challenge to find the best real-world application for its wood-based alternative to steel.

“We like to think of ourselves as wood alchemists, in that we’re able to transform the chemistry of wood to imbue it with incredible properties,” InventWood CEO Josh Cable said during the event.

While steel is a “wonderful material,” it has “meaningful challenges,” he said. About 7% of annual global GHG emissions are attributable to steel production. InventWood wants to help reduce those emissions with what it calls “metal wood,” an extremely strong material made through a process discovered at the University of Maryland.

Metal wood is made by taking a regular piece of wood and modifying it with a chemical treatment and putting it through a process that aligns the wood’s fibers. The result is a material that is as strong as many types of structural steel, but Cable said it’s 80% lighter and costs 50% less. It also has natural protection against fire, fungus and termites.

With the help of mentors in the buildings challenge, the College Park, Md.-based company identified an initial opportunity for the product and studied the environmental impacts of that application.

“We are planning to work with [Saint-Gobain subsidiary] CertainTeed to commercialize a cladding product that can be a game changer in the built environment,” Cable said. CertainTeed manufactures interior and exterior building products.

In addition to reducing the overall weight of a building, the cladding product will remain dimensionally stable in hot or cold weather. And the wood itself is a carbon dioxide sink, sequestering 1.5-2 kilograms of CO2 per one kilogram of wood.

Cable expects the company to deploy 170,000 cladding panels within two years and expand the product to other building construction applications.

Over the next 30 years, he said, the metal wood product has the potential to avoid 37.3 gigatons of CO2 emissions.

More Solutions

Three other startups completed the Greentown program.

AeroShield of Boston is working on a super-insulating, transparent insert for windows. The company received a National Science Foundation grant last year to research transparent silica aerogels to insulate glass.

Italy-based Enerbrain is developing a way to make heating, cooling and ventilation systems smarter through digital monitoring and control. And Zero, a Cambridge, Mass.-based software developer, wants to enable hassle-free home retrofits that improve comfort and eliminate emissions.

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ISO-NE Sends MOPR Filing to FERC, Teeing up Big Decision

After months of debate by ISO-NE and stakeholders, the RTO’s proposal to revamp its Forward Capacity Market is now in the hands of FERC.

In a detailed filing to federal regulators last week, ISO-NE laid out its reasoning both for eliminating the contentious minimum offer price rule (MOPR) and for doing so after a two-year delay.

The proposal largely reiterates the points that the grid operator has made during a monthslong stakeholder process in NEPOOL, but the document is the first time its entire reasoning has been laid out in one place.

ISO-NE is calling for the creation of a “more nuanced mechanism for evaluating new resource capacity market offers,” exempting both clean or renewable resources and merchant generators from a new resource-specific, buyer-side market power review.

But to avoid a flood of new state-sponsored resources into the capacity market and a corresponding rash of “inefficient retirements,” it proposes a two-year transition period during which the MOPR would remain in effect but up to 700 MW of renewables could get exemptions from it.

“The ISO is concerned that the immediate entry of large quantities of state-sponsored resources could pose an unacceptable risk to the existing resources upon which the region currently relies, prompting the retirement of these resources before the point at which we are in a position to fully ascertain and account for the relative reliability benefits of the retiring resources and the new resources replacing them,” ISO-NE COO Vamsi Chadalavada said in testimony attached to the filing.

A History of Failure

As a backdrop to its latest proposal, ISO-NE lays out a history of admitted failures at accommodating state-sponsored resources into the capacity market.

The 2014 renewable technology resource (RTR) exemption had caps that were too small, and rules too restrictive, to qualify many of the renewable resources trying to get into the capacity market.

The RTO’s Competitive Auctions with Sponsored Policy Resources (CASPR) construct — which created a second, “substitution” auction, in which existing resources can transfer their capacity supply obligations (CSOs) to state-sponsored resources — has also failed to have the intended results. In the four auctions since its implementation, only 54 MW of state-sponsored resources have been awarded a CSO through a substitution auction, the RTO said.

A New Plan

In light of those failures, and with clean energy procurements on the rise even more in the New England states in the last few years, ISO-NE needed a new plan.

Its proposal excludes certain new resources from having their capacity market offers mitigated if they “lack either the ability or the incentive to exercise market power (or both), or because exclusion of those resources will address the inefficient overbuild concerns related to the accelerated state procurement of sponsored resources,” the RTO wrote.

In addition to federally or state-sponsored resources, new projects with a capacity less than or equal to 5 MW, passive demand response resources and new resources that are not receiving revenues outside of RTO-administered wholesale markets from a load-serving entity, state or subdivision of a state will also be exempt from the buyer-side review and any mitigation.

FERC’s Response in the Balance

Now the ball is in FERC’s court, and while sometimes the federal agency’s response is predictable, this is not one of those times.

Arguably the most pertinent question is whether the two-year delay complies with FERC Democrats’ recent pointed, if nonbinding, directive to remove the MOPR “expeditiously.” (See FERC Weighs in as ISO-NE Prepares for Capacity Auction.)

FERC typically responds to filings under Federal Power Act Section 205 within 60 days, and there are a number of ways it could respond, said Ari Peskoe, director of the Electricity Law Initiative at Harvard Law School.

It could approve the filing as is, and it would go into effect. It could reject the filing, keeping the status quo. It could also issue a deficiency letter asking for more information or call for a paper hearing, extending the deadline.

Or, Peskoe said, “it could reject the filing, and with that rejection issue a Section 206 order finding that the status quo is unjust and unreasonable and order ISO-NE to change it. That could be a specific order to put into place an immediate end to the MOPR.”

FERC took that route with PJM’s MOPR in 2018, and the resulting process took another year and a half to complete. But, Peskoe said, because the immediate cessation of the MOPR was already on the table and under discussion in New England, it could likely develop much more quickly.

D.C. politics could end up playing into the decision too: There’s a possible scenario in which FERC ends up split 2-2 in 2023 after approving ISO-NE’s two-year transition. If the RTO were to backtrack at that point on its decision to remove the MOPR altogether, its decision could end up being approved by the split FERC by operation of law.

Eyes on the RTO

The debate over the MOPR removal and especially the transition proposal has generated an unusual amount of scrutiny of ISO-NE and NEPOOL, which often operate under the radar.

In particular, opponents of the delay have cried foul and accused the grid operator of being an impediment to the clean energy transition.

“ISO-NE, New England’s energy operator, just decided to push back letting clean energy into the regional market by two more years,” tweeted Melissa Birchard, senior regulatory attorney for power grid reform at the Acadia Center. “This is a mistake for the climate and sticks consumers with extra costs. FERC should reject this and direct the ISO to let clean energy compete now.”

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FERC Allows ISO-NE 1-month Delay for FCA 17

FERC on Friday agreed to allow ISO-NE to adjust the schedule for next year’s Forward Capacity Auction 17, which was pushed back because of uncertainty surrounding Killingly Energy Center.

In February, the RTO had asked the federal agency to allow it to ignore any dates set for FCA 17 in the grid operator’s tariff or other operating documents, and instead publish a new schedule (ER22-1053).

NEPOOL stakeholders and the New England Power Generators Association supported the ISO’s filing, and FERC signed off on the change.

“The proposed revisions enable ISO-NE to provide market participants with information (such as, for example, final FCA 16 clearing prices) that facilitates their ability to meet the requirements for participating in FCA 17 per the tariff,” FERC commissioners wrote.

The grid operator has proposed a pushed back FCA 17 schedule, which would see next year’s auction take place in March, a month later than the typical February auction.

FCA 16’s final auction results were delayed several weeks by confusion over whether the gas-fired Killingly plant could participate in the auction, but were published in March after it was omitted. (See Highlights from FCA 16: No New Gas, No Big Storage.)

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West Coast Wind Faces Big Challenges

SAN FRANCISCO — Offshore wind is expected to progress steadily in California over the next decade, but panelists at last week’s Pacific Offshore Wind Summit in San Francisco expressed concern that the infrastructure needed to support floating wind farms could lag development plans.

New to offshore wind, the West Coast will need to build high-voltage transmission lines, port facilities and assembly areas for massive wind turbines. The region lacks a trained workforce for offshore wind and a dedicated, on-time supply chain. And it still must develop a strategic plan, as required by last year’s California Assembly Bill 525, to make offshore wind part of its 100% clean energy initiative.

Eli Harland 2022-03-29 (RTO Insider LLC) FI.jpgEli Harland, California Energy Commission | © RTO Insider LLC

“We’re going to develop a strategic plan under AB 525, but it will only mean anything to the industry and to the climate if there’s a way to implement that strategic plan,” Eli Harland, adviser to California Energy Commission member Kourtney Vaccaro, said in a panel on regional cooperation.

“That’s not going to get done with a couple of people in the Energy Commission pushing it forward,” Harland said. “That’s going to take a resource commitment that, if we don’t make it, we’re going to find ourselves really behind when the industry takes off, and we’re not going to be ready for construction and operation.”

Stakeholders at the conference said a best-case scenario would be for the infrastructure work to happen in the years between a pending lease auction and the start of construction.

The West Coast’s first offshore lease auction will be held later this year for two areas off Northern and Central California, Amanda Lefton, director of the Bureau of Ocean Energy Management (BOEM) told the audience, prompting spontaneous applause.

“Let me be clear,” Lefton said. “We are going to hold a statewide offshore wind energy lease sale in California this year. The sale will offer up wind energy areas in the northern and central coasts, and these areas will enable the buildout of significant new domestic clean energy over the next decade or more. This will also help California reach its carbon-free energy goal by 2045.”

The California auction is part of the Biden administration’s goal to develop 30 GW of offshore wind by 2030, Lefton said.

“We plan to release a proposed sale notice later this spring,” she said. “This notice gives you all the first look at the [proposed] terms and will ask for feedback on important initiatives for … labor agreements, credits for domestic supply chain investments, engagement with tribal nations and ocean users, and working with the commercial fishing industry.”

Panelists at the conference, hosted by trade group Offshore Wind California and organizer Infocast, addressed challenges including port construction, transmission coordination and supply chain issues.

Transmission

The two wind energy areas that BOEM plans to auction this year have distinct transmission states.

​Neil Millar 2022-03-29 (RTO Insider LLC) FI.jpgNeil Millar, CAISO | © RTO Insider LLC

The Morro Bay Wind Energy Area in Central California is “well-positioned” because it’s already served by transmission lines to the defunct Morro Bay Power Plant and the soon-to-be retired Diablo Canyon Power Plant, the state’s last nuclear generator, Neil Millar, CAISO vice president of infrastructure and operations planning, said in a panel on transmission and interconnections.

There already is ample transmission capacity for the 3 GW that Morro Bay wind is expected to generate and more when Diablo Canyon closes, Millar said.

A growing movement of scientists and elected officials has argued for keeping the 2,256-MW Diablo Canyon plant open for reliability’s sake during California’s clean energy transition. If that happens, it will significantly limit available transmission capacity.

The Humboldt Bay Wind Energy Area, in contrast, requires “starting from scratch” to carry the 1.6 GW it is anticipated to generate, Millar said.

“It’s all about Humboldt,” he said.

Unserved by major transmission lines, the Humboldt area on California’s sparsely populated North Coast would require a new line that crosses rugged mountains to connect to the Pacific AC Intertie, one of the state’s major north-south transmission corridors, or an undersea cable that surfaces near San Francisco, he said.

The Humboldt area is being examined as part of CAISO’s new 20-year transmission outlook and in collaboration with the California Public Utilities Commission and the Energy Commission, Millar said.

Coordinated transmission, instead of the serial connections that became a problem for East Coast wind, is a priority on the West Coast, panelists said.

Since late February, when BOEM announced three new wind energy call areas in southern Oregon, there has been talk of coordinating transmission links between the two states. (See Energy Bar Weighs OSW in Oregon, California.)

“The growing Pacific Coast scale of this, which has just been expanded [with BOEM’s Feb. 24 announcement] … sets in motion a whole set of speculation about coordination across the region,” Adam Stern, executive director of Offshore Wind California, said at the time.

In far northern California, there are potential wind-farm areas off the coast near Crescent City, Arne Jacobson, director of the Schatz Energy Research Center at Cal Poly Humboldt, said. If those areas are eventually slated for wind development, transmission coordination with the southern Oregon areas might be an efficient solution, he said.

The Port of Coos Bay in southwest Oregon is also hoping to play a role in offshore wind, port CEO John Burns said in a panel on seaport facilities and staging areas. Once a major timber port, it still owns 1,000 acres that could be used to support offshore wind.

Ports

In the seaport session, panelists said that while Humboldt lacks transmission, it has what wind developers consider a nearly ideal bay and spacious quayside to assemble turbines and transport them to sea.

The Port of Humboldt Bay recently received a $10.5 million grant from the Energy Commission to begin upgrading its facilities for wind development.

The funds will help the Humboldt Bay Harbor, Recreation and Conservation District revitalize the historic timber port on the state’s Redwood Coast, beginning with preliminary engineering and design work. The money will also be used to attract matching grants from the federal government.

A new marine terminal is being planned to handle heavy cargo vessels and floating platforms. Humboldt Bay lacks the bridges and other impediments to developing wind ports in larger deep-water harbors, such as San Francisco and San Diego bays.

In Humboldt, the port is “foundational infrastructure” that might be ready for wind deployment in five to six years, about the same timeframe as the permitting process for sites in the Humboldt Bay Wind Energy Area, Jacobson said.

New transmission to Humboldt is likely to take longer, he said.

Larry Oetker, executive director of the Humboldt Bay harbor district, offered a similar assessment.

Seaport facilities panel 2022-03-29 (RTO Insider LLC) Alt FI.jpgFrom left: Larry Oetker, Humboldt Bay harbor district; Kristin Decas, Port of Hueneme; and John Burns, Port of Coos Bay | © RTO Insider LLC

“Our goal is to have all the permits and to be ready to go within the next few years,” Oetker said. “We want the work to be ready when the offshore wind industry is ready, and we don’t want the port to be an obstacle. And so simultaneously [with technical studies] we’re working on workforce development and transmission upgrades. Because in the end, the transmission upgrades and the offshore wind leases and future offshore wind leases are going to dictate the amount of port investment that’s going to be needed.”

In Central and Southern California, it is less clear which ports will be primary staging areas for the Morro Bay wind fleet.

The Port of Long Beach in Los Angeles County, one of the world’s busiest container ports, is interested in playing some part, possibly in conjunction with other ports that have different strengths, Matt Arms, the port’s director of environmental planning, said.

Kristin Decas, CEO of the Port of Hueneme in Ventura County, made a pitch for its potential to be the best staging area for Morro Bay. The deep-water harbor is home to Naval Base Ventura County and is a major entry port for cargo ships carrying cars and bananas.

“Right now, we sit as the sixth leading port on the West Coast for commercial cargo,” Decas said. “We are actually moving more cargo than Portland and Boston right now. We’re the fourth largest container port in the state of California.”

When panelists were asked if building a new port made sense, Decas said building a new port is a “heavier lift” than building a wind farm.

“I don’t think that’s going to be your answer,” she said.

Supply Chain, Floating Turbines

Several panels addressed supply chain issues, including a session on cabling and mooring. Whether the supply chain can provide “just in time” delivery for West Coast wind development remains doubtful, panelists said.

Bill Wall, project director at LS Cable Systems America, which made undersea cable for the first U.S. wind farm, Block Island, and subsequent projects, said his company has a two-to-three-year backlog in its factories, making delivery times uncertain.

Tom Fulton, head of renewables and mooring development at marine energy and infrastructure firm Acteon, asked audience members to imagine how much room it would take to store equipment for even a 1-GW wind farm if the equipment could not be installed promptly.

Developers are expecting to install enormous 15-MW floating turbines off the West Coast, each more than 900 feet tall with blades longer than a football field. A 1-GW wind farm will require 67 towers along with miles of anchoring and mooring gear. The links in an anchor chain weigh half a ton; polyester cable used instead of chain is a foot thick, Fulton said.

The floating platforms will be in water 2,000 to 4,000 feet deep, but that should not be a problem, panelists said.

Oil platforms have operated at such depths for years, Fulton said.

Henrik Stiesdal, CEO of offshore wind developer Stiesdal A/S, acknowledged floating wind is still in its infancy as an industry but said the technology has been proven since 2009. The West Coast won’t require entirely new designs, he said as part of a panel on floating turbines.

Asked for final thoughts on floating offshore wind, Stiesdal said, “It’s the future,” while other panelists commented that it is a way to harness large amounts of wind energy and to use its scale as a means of producing clean power.

California hopes to eventually have 10 GW or more of offshore wind.

Aaron Smith, chief commercial officer of wind developer Principle Power, said: “I agree with you guys, but it’s also going to take a lot of coordinated effort to build the capabilities to make this happen, so we really need to focus and get started now.”

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SPP Stuns with 90.2% Renewable Penetration Mark

SPP set the energy Twitterverse on fire last week when it announced it had become the first regional grid operator to temporarily serve more than 90% of its demand with renewable energy.

“Remember when they said that at 20% the whole thing would come crashing down?” tweeted Joshua Rhodes, an energy researcher at the University of Texas. “Ninety percent.”

Rhodes noted the 20% figure was an annual number and that 90% was an instantaneous number. “In the end, 90% instantaneous is a new U.S. record and worth recognition!” he said.

“It is indeed noteworthy — it’s awesome,” said Aron Patrick, manager of research for Kentucky utility LG&E and KU Energy.

The record came at 2:42 a.m. CT March 29, when renewable energy set a new penetration mark of 90.2%, breaking the old mark of 87.6% set in May 2021. Wind accounted for 88.5% of the renewables, breaking the previous wind record of 84%, also set last May.

SPP also set new renewable and wind production records. The RTO produced a record 23.8 GW of renewable energy at 9:25 p.m. on March 28, bettering the previous high of 21.8 GW set Feb. 15. At 10:34 p.m. that same evening, SPP produced 22.9 GW of wind energy, topping the previous high of 21.8 GW set on Feb.15.

With SPP’s system demanding around 25 GW during the off-peak periods, the numbers came as no surprise to RTO staff. A cold front that swept through SPP’s 14-state footprint, bringing wind gusts as high as 60 mph, also played a role.

CEO Barbara Sugg told RTO Insider the records were an example of staff’s increased ability to forecast both load and wind production.

“That speaks to the tools that we have in place for forecasting,” she said after delivering a keynote address during the Gulf Coast Power Association’s MISO South-SPP conference. “It speaks to the training and the systems that the operators have because that amount of volatile, non-dispatchable generation consuming that much of the load requires everybody knowing exactly what’s going on and having the systems in place to be able to manage through it.”

“In a decade’s time, our region has gone from thinking of 25% renewable-penetration levels as nearly unreachable to a point where we regularly exceed 75% without reliability concerns,” SPP Senior Vice President of Operations Bruce Rew said in a statement.

“It’s important to realize that reliability is more important than achieving a renewable goal,” Sugg said. “You’re setting a new record, right? We have to maintain reliability.”

The RTO has about 31 GW of installed wind capacity with another 66 GW of renewable resources in its generator interconnection queue. SPP’s footprint includes the high-wind regions of the Dakotas, Kansas, Missouri, Nebraska, Oklahoma and Texas, giving staff a huge pool of resources to draw from.

“There is a lot of wind in our footprint and a lot of desire for that demand to be harnessed into energy,” Sugg said. “We just have to be sure that the transmission rates can support it, and that we can figure out how to balance the desire for [wind energy] with the requirement to maintain reliability. It’s a delicate balance.”

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NYISO Management Committee Briefs: March 30, 2022

Ready for Next Winter

NYISO expects by next winter to meet the recommendations made in the joint FERC–NERC report on the February 2021 winter storm in the Midwest and Texas to protect critical natural gas infrastructure from manual and automatic load shedding and to prohibit use of such critical infrastructure loads for demand response, COO Rick Gonzales told the Management Committee on Wednesday.

“The NERC Board of Trustees directed the development of reliability standards consistent with the report recommendations in anticipation of this coming and next winter,” Gonzales said. “Normally it would take much longer through the NERC standard development process, but the directive by the NERC board is to have those standards developed again in time for the coming and the following winter, consistent with the recommendation time frames identified in the report.”

The ISO presented stakeholders its work on the recommendations at the Installed Capacity Working Group meeting Feb. 3, saying it intends to implement the rules on Nov. 1, the first day of the 2022/23 winter capability period.

In addition, the ISO requested that resources meeting its proposed definition of critical infrastructure load not be registered in its DR programs for the 2022 summer capability period.

Staffing Recruitment Improves

NYISO has started to make significant progress in terms of recruiting talent for several open key staff positions, CEO Rich Dewey told the MC.

“We’re still looking at a vacancy rate as we sit here today of about 9%, but of the 56 open positions, we have had accepted offers on 17 of them, so that’s a pretty successful recruiting month,” Dewey said.

Those new people need to be onboarded and brought up to speed, trained and acclimated to the ISO, but the progress is encouraging, he said.

NYISO has adopted a hybrid approach to working and has not identified any specific number of days that people are required or mandated to be in the office.

“We’ve asked each of the department heads to identify those positions and those work functions where it’s more efficient or effective to do it in person and, when flexibility is warranted or justified, allow people the choice of where they want to work,” Dewey said. “It varies by job and by department and will be monitored and tracked and adjustments made to the extent we need.”

Board Seeks 10% Increase in Compensation

Following a tri-annual structured compensation review, the NYISO Board of Directors intends to increase its members’ pay by approximately 10%, or 3.33%/year for the period.

The board reviews its compensation every three years and compares it to market forces to assess whether it is consistent. According to the ISO agreement, any change to board compensation can only happen after notifying the MC.

“I wanted to inform the Management Committee today of those plans and then if there’s any comments, questions or concerns, give the committee the opportunity to voice those, and then the board will take that under consideration when they meet in April before they finalize those changes,” Dewey said.

The current annual retainer of $65,000 per director would increase to $71,500; the retainer for being vice chairman or committee chair would go from $10,000 to $12,500; and the board committee meeting day stipend of $5,000 would increase to $5,500.

“This was anticipated when we put the budget together for 2022,” Dewey said. “The changes that the board is proposing are going to be accommodated within that budget that’s been placed, so I’m not coming here today to seek additional funds.”

Real-time BPCG Eligibility Changes

The committee unanimously recommended that the board approve tariff revisions to the real-time bid production cost guarantee (BPCG) payment provisions.

In order to close a loophole whereby units may receive inappropriate real-time BPCG payments under certain circumstances, the new tariff language adds an exception to the eligibility criteria for units placed out of merit for reliability below a self-scheduled wattage level, said Mark Buffaline, senior settlements analyst at the ISO. (See “Real-time BPCG Eligibility Changes,” NYISO Business Issues Committee Briefs: March 16, 2022.)

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Md. General Assembly Sends Climate Solutions Bill to Hogan

A legislative showdown is brewing over Maryland Senate Bill 528, the Climate Solutions Now Act, which would require the state to cut its greenhouse gas emissions to net zero by 2045, convert its vehicle fleet to electric and establish distribution system planning to help achieve these and other clean energy goals.

Gov. Larry Hogan (R) is expected to veto the bill, and Democrats in the General Assembly are expected to override that veto, allowing the bill to become law before the legislative session ends on April 11.

The main question now is how close to the wire the likely veto and override will occur. In a statement released March 10, Hogan slammed the bill as a “reckless and controversial energy tax.” Senate Democrats, however, pushed the bill through a final 32-15 vote on Thursday, with substantial amendments from the House of Delegates, to get it to Hogan’s desk on Friday.

The vote in the House was similarly veto-proof, 95-42. Under state law, Hogan has six days, not counting Sunday, to sign or veto the bill, or let it become law without his signature. If he holds the anticipated veto until the sixth day, April 7, Democrats will have a tight window for the override.

In addition to the 2045 net-zero target, the bill’s key provisions include:

  • an increase in the state’s interim target for emissions reductions, from 40% in 2030 to 60% in 2031.
  • the establishment of a Climate Catalytic Capital Fund that will be used to start a green bond program and help finance and leverage private investment for a range of emission-reduction and clean energy programs. Initial allocations for the fund would be $5 million a year for 2024 to 2026.
  • a $50 million electric school bus pilot program that will allow utilities to test out the use of vehicle-to-grid technologies at times electric buses in the program are not in use.
  • a steady phase-in of EVs in the state’s passenger car fleet, with 100% of all new purchases electric or hybrid by 2028 and 100% of all other light-duty vehicles electric by 2033.

The House Amendments

The school bus pilot and the distribution planning requirements were part of the 50-page package of amendments passed in the House on March 29. Under the new planning provisions, beginning in December 2024, the Public Service Commission would have to submit a yearly report to the General Assembly on the “current status of electric distribution system evolution.”

As listed in the bill, specific goals of distribution planning would include the incorporation of a range of distributed energy resources, such as electric vehicles, energy storage, demand response and non-wires alternatives.

But the House amendments also softened or cut some of the bill’s core initiatives.

Cut entirely from the bill were net-zero school provisions requiring that, from 2023 to 2033, at least one new school in each school district be built to net-zero standards.

The Senate’s provisions on building performance standards were another casualty. They would have required that new or renovation projects built with at least 25% state funding meet high-performance building standards developed by the Maryland Green Building Council. Emission-reduction targets for large commercial buildings and multifamily dwellings were also cut, from 50% to 20% in 2030, and a net-zero target for 2035 was completely eliminated.

The House amendments also rebranded the Maryland Climate Justice Corps in the original Senate version as the Chesapeake Conservation Corps. The goal in both cases is to provide education and job training programs to help develop “green career ladders” for youth and young adults, but with a shift in focus from environmental justice to environmental conservation.

For example, while a primary purpose of the Climate Justice Corp was to “promote climate justice and assist the state in achieving its greenhouse gas emissions-reduction targets,” the corresponding goal of the Conservation Corps is to “promote, preserve, protect and sustain the environment.”

Reactions

Tweeting out an announcement of final passage of the bill, Sen. Paul Pinsky (D), SB 528’s chief sponsor, called it “a victory,” pointing to the 60% emission-reduction target for 2031 and the 20% target for cutting building emissions.

“It’s no question that climate change presents an existential threat,” House Speaker Adrienne A. Jones (D) tweeted on Friday. “We passed Climate Solutions Now to have more aggressive greenhouse gas-reduction goals and reduce our carbon footprint faster.”

Environmental groups also stayed focused on the positive impact the bill will have.

“We owe it to future generations of Marylanders to address the root causes of the stronger storms, rising sea levels and higher temperatures that threaten their quality of life, and this bill is a strong step toward doing so,” Josh Kurtz, executive director of the Chesapeake Bay Foundation, said in a statement released after the House passed the bill.

“The Climate Solutions Now Act takes concrete steps that are good for our economy and all our communities,” said Kim Coble, executive director of the Maryland League of Conservation Voters. The bill will, she said, “put Maryland on the path to lead the nation once again in addressing climate change in a responsible, achievable and equitable manner.”

Beyond his initial statement in March, Hogan has made no subsequent comments on the bill.