ATLANTA — With NERC’s newest cold weather standards having passed their final ballot and ready for submission to the organization’s Board of Trustees, a member of the team that drafted the standards on Wednesday reminded stakeholders that the work of protecting North America’s grid from winter weather has only begun.
The new reliability standards EOP-012-1 (Extreme cold weather preparedness and operations) and EOP-011-3 (Emergency operations) were submitted to industry stakeholders for their final ballot Sept. 23 and passed Sept. 30, along with their implementation plan. Trustees are expected to approve them at the board’s upcoming meeting in New Orleans, after which they will await acceptance from FERC.
Speaking at the North American Generator Forum’s annual Compliance Conference at NERC’s headquarters, David Lemmons, co-founder of consulting firm Greybeard Compliance Services and head of NAGF’s Cold Weather Working Group, jokingly observed that “it’s going to take a few days” for the standards to take effect. He was referring to the fact that EOP-011-3 will not be enforceable until 18 months after the commission grants its approval, while EOP-012-1 will not fully take effect for more than six years from that point.
Joining Lemmons was Occidental Power Services’ Venona Greaff, who outlined some of the changes that utilities can expect in EOP-012-1 and EOP-011-3. Greaff served on the standard drafting teams for both Project 2021-07, which drafted the new standards, and its predecessor Project 2019-06, which created three cold weather standards approved by FERC last year. (See FERC Approves Cold Weather Standards.)
The latest project was initiated in response to NERC and FERC’s joint inquiry into the winter storms of February 2021 that knocked thousands of megawatts of capacity offline in Texas and left households across the state without power for days. (See FERC, NERC Release Final Texas Storm Report.) Recommendations from the report include requiring generator owners (GOs) and operators (GOPs) to build or retrofit generating units to operate to specific ambient temperatures and weather, and to perform annual training on winterization plans.
The two standards passed last month comprise Phase 1 of the overall cold weather strategy and were developed under an accelerated schedule in hopes of getting them before FERC sooner. (See NERC Standards Committee Fast Tracks Cold Weather Project.) Now that their development is finished, the organization plans to move to Phase 2, which will address more recommendations from the report such as specifying the role of GOs and GOPs, as well as balancing authorities, in determining generator capacity, along with requirements protecting natural gas infrastructure from load shedding. NERC currently hopes to finish this stage by next year.
Although the SDT did not add these elements to its remit in order to avoid delaying completion, the members did take “some steps in Phase 1 to address some of the things that we’re going to have to address in Phase 2,” Greaff said. In particular, she noted the FERC-NERC report’s recommendation that GOs “identify cold-weather critical components and systems for each generating unit.” Greaff said the team decided to go ahead and create specific definitions of relevant terms so that “when we get to Phase 2, we [will] already have a foundation layer” to build on.
New Jersey pension funds would be forced to divest from the largest 200 publicly traded fossil fuel companies under a controversial bill approved by the state Senate Environment and Energy Committee last week as the fall legislative session gathered pace.
The bill was one of five clean energy bills heard by the committee Thursday, including one that would stipulate how much time electric vehicle chargers installed with state incentives should be available for use, and one that would require utilities to plan for the growth in the use of distributed electric resources.
The committee voted 3-2 along party lines to move the disinvestment bill, S416, forward, sending it the Senate Budget and Appropriations Committee. The legislation, which has not moved in the General Assembly, would require the State Investment Council and the director of the Division of Investment to divest any stock, debt or other security investment from companies with large oil, gas or coal reserves within 12 months of the law’s enactment.
The Division of Investment manages seven public pensions that support the retirement plans of more than 800,000 members with a total, as of May, of $92.9 billion.
“What’s proposed here is sending a signal to the fossil fuel world and industry that we’ve got to find different ways to live and you, the companies that produce these fossil fuels, have to help us,” said committee Chair Bob Smith (D), who sponsored the legislation. He acknowledged that it is a “controversial bill.”
Sen. Edward Durr (R), who voted against the bill, said he feared that enacting the legislation would have “unintended consequences.”
“I think our voice is greater when we are invested into a company, and we have leverage,” he said. “Plus I believe it sends a signal of [the government] picking winners and losers, and I disagree with that.”
The bill’s advance comes nearly a year after the State Investment Council codified a strategy to pressure the companies it’s invested in to reduce their emissions, including an in-house assessment of emission-reduction efforts across its entire portfolio and participation in shareholder pressure tactics. (See NJ Pension Fund Backs Climate Strategy.)
Opponents of the bill include the American Petroleum Institute; the New Jersey Society for Economic, Environmental Development; and the New Jersey Chamber of Commerce. Supporting the bill are environmental groups Clean Water Action, Environment New Jersey and the League of Conservation Voters.
“We live in a capitalist society,” said Ed Potosnak, the league’s executive director. “And one of the ways that we shift what corporations do is by voting with our wallets.”
By disinvesting, the state would send a message to fossil fuel companies that “we want you to succeed … in a future that is ever increasingly ravaged by the effects of climate change” by adopting a “new operating model,” he said.
But Dennis Hart, executive director Chemistry Council of New Jersey, said the “short sighted” bill “removes New Jersey from influencing the direction of the fossil fuel industry.” He said the state’s corporations are already working hard to develop new technologies that will help mitigate climate change, and selling shares would take “the state away from the ability to influence these companies.”
“It’s similar to somebody saying, ‘I decided not to vote because I’m sending a personal message,’” he said. “I think that’s a bad policy.”
Raymond Cantor, a lobbyist for the New Jersey Business & Industry Association, noted that the pension fund is already underfunded, and now is the wrong moment to do “anything other than making sound investments.”
“From a fiduciary responsibility, the state should be making sure that its pension is invested in sound, legal investments, and should not be taking public policy and these types of concerns into the equation,” he said.
Barbara Powell, co-chair of Divest NJ, which was formed to push for the reduction in the pension fund’s investment in fossil companies, said the profits from the companies are a “negligible” part of fund returns.
“Staying invested in a sector whose days are numbered is not a fiduciarily responsible policy,” she said.
Meter Collar Adapters
The committee also unanimously approved a bill, S3092, that would require electric public utilities to authorize the installation and operation of meter collar adapters.
The small electronic device, which is installed between a residential electric meter and meter socket, facilitates the deployment and interconnection of an on-site electric generation source. That enables the customer to isolate their load and use backup power.
The bill would require an electric utility to approve or disapprove a meter collar adapter for installation in its service area within 60 days of a manufacturer submitting a request.
Zachary Kahn, senior policy adviser for Tesla, said that no utility at present allows the use of meter collar adapters, and he urged the committee to approve the use of a device that he said would simplify and speed up the process of installing residential storage and backup power.
“Meter collar adapters provide an immense opportunity to expedite the clean energy transition by allowing energy storage, solar and even EV chargers to be installed in a fraction of the time and at a fraction of the costs at residences,” he said.
The committee also unanimously backed legislation, S3102, that would direct the New Jersey Board of Public Utilities (BPU) to require that any electric service equipment installed with a state incentive should be operational 95% of the time. The BPU would have to develop and implement a process of monitoring incentive recipients to ensure that they are compliant.
Committee Chair Smith, a bill co-sponsor, said the bill stemmed from a media report that some chargers are “out of commission” 60% of the time.
“That’s unacceptable,” he said. “So this bill sets the standard for the uptime, meaning that it has to be working a certain percentage of the time to get any kind of government support.”
However, Nicholas Kikis, vice president of legislative and regulatory affairs for New Jersey Apartment Association, said that 95% is “too high.” The operators of chargers that do not reach that standard would get 18.5 days to reach the required uptime “or the incentive could be clawed back,” Kikis said. Such a penalty, he added, could dissuade people from seeking government support and so reduce the development of new chargers.
That issue is especially concerning given the state’s goal that by 2030 EV chargers be installed in 30% of all multifamily apartments, he said. “There’s right now insufficient incentives” to reach that goal, he said.
Preparing for Distributed Power Sources
Finally, the committee approved a bill, S2973, that would require electric utilities to submit integrated distribution plans (IDPs) to the BPU. Such a plan, developed by the utility, outlines the physical and operational changes to the transmission and distribution system needed to adapt to the use of DERs.
Introducing the bill before a unanimous vote, Smith said that the reason for creating an integrated distribution system is that it “makes for a stronger grid.” It would first require the BPU to develop criteria for the IDPs, and utilities would have to submit them within a year.
The bill, which Smith co-sponsored, has not moved in the Assembly. It is supported by Environment New Jersey and the Natural Resources Defense Council and opposed by the New Jersey Utilities Association.
Also opposing the bill, the New Jersey Division of Rate Counsel argued that the timeline for review of the IDPs is too short — 90 days — and includes a “lack of stakeholder involvement.”
In addition, the Rate Counsel said in an Oct. 5 letter to the committee, the bill should take the BPU process into account more.
“Rate Counsel would prefer sufficient time for thoughtful deliberation of the issues involved in the IDP approval process,” it said. It also “believes the board and stakeholders should be afforded no less than 180 days of review and approval of the submitted IDPs.”
The Rate Counsel also planned to oppose a second bill, S2978, that would revise the state’s renewable energy portfolio standards out of concern that it would be expensive for ratepayers. However, the bill — which has not advanced in either the Senate or Assembly — was pulled by Smith, the primary sponsor, who concluded after receiving stakeholder input that “it needs some adjustment.”
The bill would revise the RPS requirements for Class I renewable energy, starting in 2030. It also would require that after 2030, at least 50% of the renewable energy certificates used by an entity to satisfy the RPS requirement for Class I energy be generated in New Jersey. In addition, the bill would require that from 2045, 100% of energy sold at retail in the state would be from Class I renewable sources.
MISO told stakeholders Wednesday that it plans to add a sloped demand curve in its capacity auction and will make a FERC filing in the second quarter of 2023.
The RTO’s Mike Robinson likened a sloped demand curve to his attempt to make an avocado-and-jalapeño-based gazpacho, but not having enough avocados to make the soup. He said when he went to the grocery store, he found surplus avocados priced at a quarter apiece and bought extra for the next night’s poke bowls.
That behavior showed that extra items beyond what is necessary still hold value.
“We’re trying to recognize the value of that additional capacity beyond the planning requirement,” he said during a Resource Adequacy Subcommittee (RAS) meeting. “The additional 100 MW have reliability value beyond the reliability target, and we should reflect that in a cost-effective manner.”
Robinson said a sloped curve will make the auction more “sustainable” in the long run, sending price signals to plants to keep operating or reflecting the additional risk if capacity doesn’t cover their requirements. He said staff and stakeholders must figure out how to translate marginal reliability into dollar values.
MISO says the incremental value of capacity might consider the avoided value of lost-load pricing and avoided high-priced emergency purchases.
Robinson said that over the last 10 years, the grid operator has been experiencing a “significant decrement” in its supply, which could have been helped with “some elasticity” in the demand curve.
“If we’re going to do this auction, let’s do it right with prices that value capacity,” Robinson said. “We can do better than having a straight line, vertical demand curve.”
Staff in July committed to a series of discussions with RAS over how the RTO might restructure its capacity auction with a sloped demand curve, among other changes. Some stakeholders said MISO needs to issue more detailed supply and demand data on a regular basis ahead of capacity auctions. (See MISO Promises Stakeholder Discussions on Capacity Auction Reform.)
The RTO is holding auction-reform discussions as it begins organizing its first seasonal capacity auctions. In late August, FERC approved the grid operator’s plan to hold four simultaneous auctions for the 2023-24 planning year using an availability-based resource accreditation that relies on the presumptive riskiest hours in a season. (See FERC OKs MISO Seasonal Auction, Accreditation.)
MISO’s Durgesh Manjure said “some of the parts and plans are evolving” in implementing a seasonal auction and accreditation. Staff plans to publish draft accreditation values — based on a unit’s availability over the past three years and filtered by the RTO’s preselected, predicted risky hours — in November, with final numbers by mid-December. The grid operator has also scheduled office hours to answer questions about the new auction process.
At stakeholders’ request. MISO will allow mid-year capacity accreditation for new resources that will serve as replacement capacity.
CONE Goes Up
MISO has upped its cost-of-new-entry (CONE) for generators heading into the 2023-2024 planning year.
The highest CONE value is in eastern Missouri’s Zone 5 at a little more than $300/MW-day, the first time it has crossed that threshold. The lowest value can be found in East Texas and Louisiana’s Zone 9, at $257.75/MW-day.
MISO said CONE values swelled on “significant increases in base project capital costs and the weighted average cost of capital.” It said it used actual and expected inflation estimates to calculate the estimates.
Boston Metal has figured out a way to turn iron into steel without using coal, thanks in part to the Department of Energy’s high-performance supercomputers, which helped the Massachusetts-based startup model the superhigh temperatures — 1,600 degrees Celsius — needed for the decarbonized process.
“There are the electric chemical elements; there is the material fluid dynamics element. You have liquid metal; you have liquid electrolyte; you have oxygen bubbling through all of that,” said Adam Rauwerdink, the company’s senior vice president for business development. “This thermal modeling is a key element that you want to ensure you have all of your liquid metal and your liquid electrolytes in a molten form, that you’re not getting solid corners or freezing of the surface layers.”
Rauwerdink was speaking at DOE’s High-Performance Computing for Energy Innovation (HPC4EI) online workshop on Friday, where the focus was on the potential for high-performance computers (HPCs), and the ultrafast processing and simulations they offer, to overcome the challenges of decarbonizing heavy industry in the U.S. by 2050.
“We use computer simulations to short-circuit the usual Edisonian approach” — engineer-speak for trial and error, said Aaron Fisher, the HPC4EI project manager at Lawrence Livermore National Laboratory.
In other words, researchers and technology developers can use the computers to simulate and test models of new equipment, new materials and new processes and iterate at warp speed through the trial-and-error phase of project development, without running up costs for repeated lab or field demonstrations.
U.S. manufacturing is in the midst of a technological revolution, Fisher said. “This revolution, instead of being powered by machinery, is being powered by the great expansion of our ability to [collect] data and process it and predict the outcomes, using that data. The data revolution is leading us to new ways of producing things … it’s allowing us to rethink how we develop manufacturing processes themselves.”
The HPC4EI program provides $300,000 awards to companies, allowing them to work with researchers at DOE’s national labs, which house a wide range of supercomputers. Oak Ridge National Laboratory’s Summit system, for example, has been ranked as one of the fastest computers on Earth, capable of processing 200,000 trillion calculations per second.
Since it was started eight years ago, HPC4EI has funded close to 150 projects, working with more than 80 companies of all sizes, from startups to major corporations, Fisher said. The companies benefit from smarter product designs and faster time to market, while also improving efficiency and saving money, he said.
Researchers at the labs also benefit “by cutting their teeth on a new class of problems that they may not have thought of before. This leads to new thinking and computational methods.”
Fisher cited a number of HPC4EI projects, such as working with ArcelorMittal to reduce the amount of natural gas needed to reheat steel slabs before they are rolled out into sheet metal. The program also paired up Raytheon and Oak Ridge National Lab for “microstructural phase field simulations” that resulted in the manufacture of lighter airplane parts, which could eventually help airlines save on fuel costs.
In the case of Boston Metals, DOE provided early funding and technical support for the company’s development of its molten oxide electrolysis process for making steel. As described on the company website, the process involves an electrolyte containing iron ore, which is electrified to 1,600 degrees Celsius, splitting off the oxygen from the ore to produce liquid metal.
The company is working toward its first commercial-scale plant in 2025, with investors that include Bill Gates’ Breakthrough Energy Ventures, utility-funded Energy Impact Partners and The Engine, a venture fund that, like Boston Metal, began as a spin-off from the Massachusetts Institute of Technology.
The impact could be significant. According to Rauwerdink, the 2 billion tons of steel produced with coal worldwide per year pumps 3.5 billion tons of CO2 into the atmosphere, or about 8% to 10% of all global CO2 emissions.
Scaling the technology on a global basis, which is part of Boston Metal’s long-term plan, will require even more sophisticated computer modeling, he said. “You just keep adding additional levels of complexity to your modeling.”
Scale up or Scale out?
DOE has recently intensified its focus on industrial decarbonization, for example, releasing an Industrial Decarbonization Roadmap last month, with plans and milestones laid out for the country’s five most carbon-intensive industrial sectors — iron and steel, chemicals, cement, food and beverage production and petroleum refining.
These industries and other manufacturing and industrial sectors account for 33% of U.S. energy consumption and 30% of carbon emissions, the roadmap said, citing figures from the Energy Information Administration.
DOE’s Advanced Manufacturing Office (AMO) will also be split in two, with one office still focusing on advanced manufacturing and a second targeting industrial decarbonization, according to Robin Miles, HPC4EI director at the Livermore Lab.
“We now have a really unique time to be able to change the way we have been doing things for centuries or, in some cases, millennia, and really rethink what that means,” said Joe Cresko, AMO’s chief engineer. “We’re going to really need to do a lot of research and development, and expedite that, accelerate that, and have a deeper understanding about the options and impacts of making these changes.
“High-performance computing is a really important part of that,” Cresko said. Continuing business as usual could result in a 17% increase in U.S. carbon emissions by 2050, he said.
Supercomputers can analyze multiple paths and options for reaching net-zero — and the tradeoffs each may entail, he said. “We need to ensure reliable and electrified services, which means you need to be able to integrate into the grid intermittent energy sources. We need to consider the ability to use hybrid and dual-fuel sources [and] more efficient heat transfer at all scales.
“Modular approaches may be a way to really transform some of the operations that are done at very large economies of scale,” Cresko said. “Instead of scaling up, can we scale out? What [do] those processes look like as we begin to change?”
Next-gen CSP
Cresko and others at the workshop see HPC playing a central role in accelerating the scaling and commercialization of still emerging technologies — such as green hydrogen, carbon capture and sequestration, and concentrated solar power — that are increasingly seen as vital for achieving a net-zero economy in the U.S. by 2050.
While once considered a promising and possibly better technology than photovoltaic solar, concentrated solar power (CSP) lost momentum in the U.S. after a few large projects were completed in the Southwestern desert — most notably the 386 MW Ivanpah project near Las Vegas. PV was cheaper, easier to permit, simpler to operate and less environmentally disruptive.
Total global capacity for CSP currently stands at about 7 GW, according to Avi Shultz, DOE program manager for CSP. The technology uses large mirrors, called heliostats, to reflect and concentrate sunlight onto a tank at the top of tower, Fluid in the tank is heated to very high temperatures, 500 degrees or more, to produce steam that can then run a turbine or be stored for later use.
While no major CSP plants are under construction in the U.S., China is in the process of building 30 CSP projects, as a form of storage for larger installations combining PV and wind energy. Renewed interest in the technology has also surfaced in Australia.
DOE’s efforts to rebuild U.S. innovation and competitiveness in the technology, specifically as a potential source for process heat for heavy industry, could breathe new life into the U.S. market. The department recently released a roadmap for next-generation heliostat production and awarded $24 million in funding for a range of projects, such as developing CSP technologies to be used to decarbonize the production of cement and limestone.
Decarbonizing heavy industry could require CSP projects that can produce heat at 700 degrees Celsius, Shultz said. DOE also wants to cut the levelized cost of CSP, with 12 hours of storage, from its 2020 rate of 9.5 cents/kWh to 5 cents/kWh by 2030.
A team at NREL is “trying to model the field-level wind forces in the heliostat field, which … [can] become extremely complex and nonlinear,” Shultz said “This really calls out for computational analysis. The number of power metrics and variables in ways you can optimize these systems becomes very, very quickly unmanageable. So really clever computational approaches to solving and optimizing heliostat fields both at the component level and at the overall field and operational level really are necessary to hit our targets for cost and performance.”
ISO-NE is proposing changes to its winter fuel security plan, the Inventoried Energy Program, to answer a court order and, more significantly, account for the swirling global natural gas markets.
The IEP is set to be in place for the 2023-2025 winter seasons and will compensate resources for the inventoried energy they hold on winter days that hit a certain low-temperature threshold.
Coal, biomass, hydropower and nuclear generators will no longer be eligible for the program, after the D.C. Circuit Court of Appeals found that they would get $40 million in windfall payments for storing energy they would have kept anyway. (See Court Strikes a Blow to ISO-NE Winter Plan.)
In a presentation to the NEPOOL Markets Committee on Wednesday, ISO-NE Regulatory Counsel Kathryn Boucher laid out the grid operator’s relatively simple response to the court ruling and subsequent FERC order, which clarifies that those asset types can’t be included in the program.
ISO-NE is planning to put forward a compliance filing in mid-November.
Tweaking the Program to Address Market Changes
On a separate track, the grid operator is looking to make longer-term changes to the IEP to try to attract more market participants to use the program and help increase the region’s reliability.
“Increased global competition for oil and LNG has changed these markets relative to when the IEP was first designed,” ISO-NE’s Craig Martin said in a presentation to the MC.
The grid operator is proposing to change how the IEP payments are calculated and how gas contract eligibility works under it. It is working with Analysis Group to recalculate forward and spot rates for the 2023/2024 winter, using updated energy market pricing and LNG contract structures.
It’s also calling for a change in the terms of the program that state that “no limitations” can exist on when gas can be called.
And ISO-NE is proposing modifying the price eligibility threshold, which was included to “prevent contracts with very high incremental costs to buying gas from being eligible.” The shift from a Henry Hub/Algonquin Citygate metric to a Dutch Title Transfer Facility metric will “reduce the risk of gas contracts unintentionally being rejected due to potential price deviations between the cost of procuring LNG and domestic gas markets,” Martin said.
ISO-NE is also looking at potentially changing the duration of inventoried energy required from 72 to 120 hours and increasing the temperature point that triggers the program.
“ISO believes these updates will increase the quantities of inventoried energy attracted to the region for winters 2023/24 and 2024/25,” Martin said.
The grid operator is looking to get to a final NEPOOL vote on the changes in January 2023.
The New York City Department of Buildings (DOB) last week proposed new rules to carry out a 2019 local law aimed at reducing carbon emissions from the city’s largest buildings.
The agency also identified the 27,000 buildings that will be covered by Local Law 97 (LL97) and subjected to the first compliance deadline scheduled for 2025.
Enacted by the New York City Council three years ago as part of the NYC Accelerator program, LL97 established greenhouse gas emissions standards for most city buildings that exceed 25,000 square feet by requiring improved energy efficiency. The law also imposed stricter emissions reporting requirements on the covered buildings.
The rules proposed last week are intended to clarify and strengthen LL97 by setting building emission factors until 2050, simplifying administrative reporting processes, detailing formula for calculating a building’s annual emissions or energy usage, and setting up rules governing renewable energy credits (RECs) that property owners can buy to help meet targets.
The buildings subject to the rules range from government and military installations to religious centers, grocery stores and business offices, with the largest structures requiring initial compliance by 2024 followed by stronger limits in 2030.
LL97 was designed to cut emissions from the city’s largest buildings by 40% by 2030 and 80% by 2050. RECs, which were written into the law, could be bought by proprietors to help meet their emissions targets and would be used to help fund other renewable efforts or projects.
REC Rules ‘Far Too Weak’
Under the rules, the RECs can be generated by state renewable projects and are intended as economic tools to help building owners offset the emissions generated from electricity supplied by natural gas and avoid hefty non-compliance costs as they begin to bring their stocks into LL97 compliance.
Specifically, credits could be used to fund Tier 4 projects, such as the Clean Path New York and Champlain Hudson Power Express, which have seen recent implementation delays. (See NYSERDA Seeks 1-Year Delay for Tier 4 RECs)
In an email to NetZero Insider, DOB Press Secretary Andrew Rudansky said “this first batch of proposed rules” clarifies that building owners can only apply RECs to offset emissions from electricity use, preventing them from using RECs to offset other types of emissions associated with their buildings.
“The department will be releasing additional rules on how the use of RECs is limited in the future. Our rulemaking process will continue to be informed by careful study by the department’s Bureau of Sustainability along with close collaboration with our partner agencies, the Climate Advisory Board, the Local Law 97 Working Groups and also with state government officials,” Rudansky said.
Additionally, Rudansky said the DOB is “currently working with stakeholder partners to study RECs” and noted that credits have “always been part of the Local Law 97 equation,” pointing to language in the original law as evidence.
That language stipulates that a “deduction from the reported annual building emissions shall be authorized equal to the number of renewable energy credits purchased by or on behalf of a building owner.” It also requires that the resources generating eligible RECs be located in or directly deliverable to the New York grid operator’s New York City load zone; that the RECs be solely owned or retired on behalf of the building owner; and that they be generated in the same period as the reporting year.
“Covered buildings claiming deductions for renewable energy credits under this section must provide the department with the geographic location of the renewable energy resource that created the renewable energy credits. The [DOB], in consultation with the mayor’s office of long-term planning and sustainability, shall promulgate rules to implement this deduction,” the law states.
Despite the clarification, some environmental groups were still unsatisfied with the RECs provision.
In an online statement, a coalition of local organizations protested the new rules saying that although “Mayor [Eric] Adams is taking positive steps,” the current rules around RECs are “far too weak” and that moving forward the administration should “tightly limit RECs so they cover only up to 10% of a building’s total pollution.”
The DOB will be hosting an online public hearing on the proposed rules on Nov. 14. Public comments can be submitted to DOBRules@buildings.nyc.gov, while stakeholders can learn more about how to meet emissions targets through the NYC Accelerator program.
NYISO’s proposed dynamic reserve requirements could result in significant changes in transmission flows and reduced costs, according to the findings that FTI Consulting presented to the NYISO Installed Capacity Working Group (ICAPWG) last week.
FTI’s Scott Harvey described how each element of the dynamic reserve design, first published in a white paper in December 2021, could result in reduced costs of meeting load, while maintaining reliability and meeting reserve targets.
The ISO’s project was conducted to see if dynamically scheduling reserve requirements or procurements for generators could support New York’s Climate Leadership and Community Protection Act (CLCPA) by allowing more economic clean energy to be imported into the state, which would better align market outcomes with system operations. (See NYISO Exploring Dynamic Reserves.)
Summary of FTI Consulting examination of new dynamic reserve project | FTI Consulting
NYISO’s existing operating reserve requirements are static; the white paper argued that a dynamic approach would “allow for appropriate reserves to be procured to cover the largest contingency,” while also allowing “for more reserves to be scheduled in cost-effective areas to meet the reliability needs,” which has become increasingly important as more intermittent generators are installed.
FTI’s study highlighted how dynamic reserve requirements can save money by replacing imported megawatts during periods of constraint with those directly from generators in load pockets.
Mark Younger, president of Hudson Energy Economics, commented how the proposal “is a pretty significant change from how things are currently done,” as it would “make contingency based on the actual loading of the unit rather than its capacity,” which he believes the ISO should make “very clear to stakeholders.”
FTI plans to return later in the year to share more examples of how dynamic reserve requirements will impact the system, including instances where intermittent resources are in load pockets.
Tariff Revisions on CRIS
NYISO also continues to work on proposed tariff revisions that would modify its rules for deactivated facilities with unexpired capacity resource interconnection service (CRIS).
The ISO’s Juan Sanchez told the ICAPWG that stakeholder feedback received on the tariff revisions discussed at previous meetings were mostly requesting additional “clarification around the rules.” The project is investigating ways to tighten the rules for CRIS retention where it is not fully utilized, while also increasing capacity deliverability headroom and potentially lowering the cost of market entry for future facilities. (See NYISO Proposes Changes to CRIS.)
Summary of proposed tariff revisions for the CRIS expiration evaluation project | NYISO
NYISO wants to modify the rules and processes for deactivated facilities with unexpired CRIS by allowing them to voluntarily relinquish their full CRIS at any point in time simply by notifying the ISO. It would develop a standardized notification form, which, once received, would prompt it to stop including the facilities in future deliverability studies.
The revisions would also expire partial CRIS rights for transmission facilities limited from using their full CRIS because of physical limitations in neighboring control area systems. This provision would apply to transmission facilities that are not meeting ISO procedures because their net megawatt output is not reaching full capability, reducing their CRIS to the maximum monthly amount of energy demonstrated during a consecutive three-year period starting from initial synchronization.
They would also allow for same-location CRIS transfers to have the same flexibility as those between different locations. Units in the process of shutting down, or mothballing, would be allowed to transfer part or all their CRIS to a same-location facility even while the unit is deactivating.
Doreen Saia of Greenberg Traurig raised the point that the revisions need to take physical withholding rules into account because there will be facilities “not necessarily retiring until some future point” but are remaining on the grid for the near future and requesting CRIS transfers.
Saia argued that a challenge will emerge when the ISO “puts their marker in the sand to do a physical withholding assessment” and there will be units whose reliability status is unclear but are requesting an “ex ante determination,” making forecasts unclear for stakeholders.
NYISO will return to a future working group meeting to share any additional feedback it receives from stakeholders concerning the new tariff language. It asks that all comments be emailed to Sanchez (jsanchez@nyiso.com).
The U.S. Department of Energy on Monday granted the Tennessee Valley Authority a voucher from its Gateway for Accelerated Innovation in Nuclear to study future sites for advanced nuclear reactors.
The DOE’s Office of Nuclear Energy’s announcement gives TVA access to the expertise and research resources of the Oak Ridge National Laboratory. TVA and the lab plan to find candidate sites appropriate for future nuclear reactors, using the Oak Ridge Siting Analysis for power Generation Expansion (OR-SAGE) tool to explore suitable locations.
South Carolina-based Elementl Power also received a similar voucher for siting assessment.
“As part of TVA’s ongoing exploration of advanced nuclear technology, we look forward to working with the U.S. Department of Energy Office of Nuclear Energy, Oak Ridge National Laboratory and other partners to help lead the nation toward a decarbonized future,” TVA said in an emailed statement to RTO Insider.
TVA did not elaborate beyond the DOE’s press release on potential sites or their size.
TVA has a goal to reach net-zero emissions by 2050. CEO Jeff Lyash has said decarbonization efforts will require license extensions at its three existing nuclear plants, adding small modular reactors, and considerable investments in energy storage and carbon capture and sequestration. TVA said earlier this year it will add a GE Hitachi small modular reactor by 2032 at the Clinch River Nuclear site near Oak Ridge, Tenn. (See TVA Defends Rates, CO2 Reduction Plans in House Inquiry.)
The New York State Energy Research and Development Agency (NYSERDA) last week selected six real estate partnerships to join a $50 million effort “to help advance a climate-friendly building stock” in the state.
Gov. Kathy Hochul announced the selections, saying the partnerships will improve building efficiency across New York by implementing heating and water decarbonization systems in 5.6 million square feet of existing high-rise stock, part of the $50 million Empire Building Challenge (EBC).
According to a statement, the EBC promises to “usher in a new era for high-rise buildings” by retrofitting 131 buildings that have signed up to be carbon-neutral and publishing playbooks with best practices for other building owners to replicate and retrofit the 70% of state’s buildings constructed prior to existing energy codes to low-carbon standards.
Hochul’s announcement also noted that energy startup accelerator The Clean Fight was selected as administrator for the $10 million dollar Empire Technology Prize program, which will support entrepreneurs developing technologies that disrupt the energy industry and increase the deployment of low-carbon retrofits in tall commercial or multifamily buildings.
The real estate teams were selected through a competitive solicitation that sought developers who will advance eight showcase buildings as part of the EBC.
The six partnerships chosen last week represent the second group of real estate businesses selected for the program, following a first cohort of 10 selected in April 2021 to achieve carbon neutrality in their building stock, with Vornado, Empire State Realty Trust and Rudin Management Company committing their entire portfolios to reaching neutrality.
The program has received strong support since, allowing New York to retrofit older buildings with green technologies instead of demolishing them.
Barriers and Challenges
New York has struggled to weatherize the more than 90% of buildings in the state that are expected to still be standing by 2050.
The state’s Climate Action Council (CAC) recently found that buildings are the largest source of greenhouse gas (GHG) emissions in New York, responsible for one-third of annual emissions statewide.
Furthermore, New York’s building stock tends to be inefficient.
Due to poor insulation and energy efficiency codes, buildings leak heat during winter and cold air in the summer months. It will be particularly difficult to decarbonize sectors of the built environment that are high-rises in cold climates, such those that dominate New York City’s skyline, since they both cover lots of ground and interact with extreme weather significantly more than smaller neighboring structures.
CLCPA estimations of GHG emissions by sector with buildings representing more than 25% | Climate Action Council
These challenges became clear during Superstorm Sandy in 2012, which caused approximately 35,000 housing units to lose power, heat or hot water for extended periods, if not permanently. More recently, a snowstorm in April caused power outages across the state, leaving more than 150,000 utility customers in the cold.
An analysis by rental consultancy RentHop found that the number of winter 311 heat or hot water complaints was 25.6% higher this past winter than last.
These challenges became particularly acute after the three days of heavy rain last week that exposed flaws in many New York buildings.
Specifically, the impact of the rain forced Councilwoman Julie Won from District 26 of Western Queens to join residents of Woodside Houses to demand permanent heating fixes to their development because residents immediately lost heat and hot water in the deluge and are now worried about freezing during what is expected to be a frigid winter with higher average energy costs.
The issue has become so important that Hochul has promised that New York will initiate the nation’s first gas ban in new construction by 2027, while the state Senate has gone a step further and proposed implementing the ban in 2024 for small buildings and 2027 for larger buildings.
But there are significantly fewer new buildings being constructed than the total existing stock within New York, making it critical to weatherize the millions of currently emitting buildings.
Heat Pumps a Priority
One notable method of decarbonizing the building sector would be use of retrofitted heat pumps, heating plants and connected water delivery systems.
Conventional heating and cooling systems account for 37% of energy consumption and 32% of greenhouse gases in New York, but clean heating and cooling systems — such as heat pumps — could significantly reduce the state’s carbon footprint.
Heat pumps are up to four times more efficient than conventional heating systems because they transfer heat rather than generating, making them cleaner, cheaper and healthier. More specifically, heat pumps move heat from the cool outdoors into the building during the heating season and then out of the building to the outdoors during the cooling season.
Air-source heat pumps operate via ducts that connect to an indoor unit that vents compressed outdoor air throughout the house in a controlled manner.
Ground-source — or geothermal — heat pumps extract heat from the ground or a nearby water source into the home during freezing weather through underground piping systems, then reverse the process during warmer months.
Compared to conventional systems, heat pumps have longer life expectancies, supply more consistent and steady outputs, allow for weather adaptability, can connect to intermittent or on-site storage systems, and produce fewer emissions.
New York has invested heavily in heat pumps, as seen in its NYS Clean Heat program, which emphasizes using the devices to increase building energy efficiency and reduce emissions compared with natural gas heating. State assembly members, such as Sandra Galef (D), have been hosting public meetings specifically devoted to heat pumps to promote their energy efficiency to constituents.
Despite the benefits, heat pumps suffer the disadvantage of having high upfront costs, requiring special planning permissions, and being sometimes difficult to install.
However, the CAC estimates that 1 to 2 million efficient homes will need to be electrified with heat pumps by 2030 to achieve CLCPA mandates, which does not consider taller high-rise buildings, the subject of the governor’s recent announcement.
EBC Benefits
The EBC is working to develop long-term capital plans that achieve carbon neutrality, while devising scenarios to scale the solutions within their partners’ portfolios.
A recent analysis from the Urban Green Council estimated that EBC partners could invest more than $250 million, which would bring the total funding to $300 million flowing into the energy-efficiency retrofit market, creating 2,600 high paying jobs, cutting 175,000 tons of carbon from New York’s emissions, and expanding improvements in almost 50,000 NYC buildings.
Furthermore, the CAC’s Just Transition Working Group found that the building sector will account for more than half of the jobs added in the clean energy subsectors from 2019 to 2030, and estimated that building sector employment will rise to roughly 366,000 by 2040, which would double the 2019 total workforce.
The CAC also estimated $9 billion in health benefits from energy efficiency interventions in low- and moderate-income homes, on top of the benefits from reduced fossil fuel combustion. Among those benefits is the reduction in carbon monoxide poisonings; leaking home heating systems are the primary cause of these poisonings the U.S., accounting for 1,500 emergency department visits and 160 hospitalizations in New York alone.
Potential health and cost benefits could be even more vital for disadvantaged communities, which are disproportionately affected by asthma and contain homes that may be more likely to have unvented or piloted gas stoves. The CLCPA has explicit provisions committing to target the electrification of environmental justice communities.
In an email to NetZero Insider, NYSERDA Vice President of Clean and Resilient Buildings Susanne DesRoches said “the Challenge will improve the building façades, increase ventilation, and deploy modern heating systems that will directly benefit the approximately 800 families that currently live in these showcase buildings.”
EBC partners “provide affordable housing to tens of thousands of New Yorkers, so the potential impact of carrying these lessons through their portfolios is huge,” DesRoches said. She added that, given the number of New Yorkers who live in aging structures, “each and every one of these buildings can learn from the solutions being advanced through Empire Building Challenge and, when the time is right, apply these solutions.”
Next Steps
Hochul has committed to achieving two million climate-friendly homes by 2030 and the EBC public-private partnership between NYSERDA and its real estate partners is expected to aid in that endeavor.
DesRoches said the “Empire Building Challenge is about moving from planning to action in addressing harmful emissions from the existing building stock in New York State in support of Gov. Hochul’s commitment.”
NYSERDA said its plans to release a competitive funding opportunity in which the real estate partners can submit proposals for up to $3 million for projects that showcase highly replicable approaches to decarbonize heating and hot water systems in existing buildings. Meanwhile, the first-round cohort have begun implementing their demonstration projects and are sharing updates online, while actively working to develop long-term plans for carbon reduction.
Additionally, NYSERDA said it is working with The Clean Fight to launch the Empire Technology Prize, which it views as a way to bring new technologies to market and accelerate the pace of building decarbonization.
Supply chain delays have hindered Pacific Gas and Electric’s progress replacing aged infrastructure, increasing the risk of equipment failure and wildfires, according to the independent monitor hired to keep tabs on the utility’s fire-prevention efforts.
The global pandemic’s supply chain slowdowns have hit U.S. electric utilities such as PG&E with “lengthened lead-times associated with ordering and receiving various goods,” Denver-based Filsinger Energy Partners said in its first report on the utility, issued Monday. “For example, due to the effects of global supply chain issues, lead times for certain transformers have increased from 38 weeks to approximately 38 months.”
That’s a problem because much of PG&E’s equipment has outlived its useful lifespan, it said.
Across the utility’s transmission, distribution and gas divisions, Filsinger, the independent system monitor (ISM), “has observed numerous PG&E asset ages that are significantly older than the related industry average useful life and the related PG&E average age of asset failure.”
“For example, PG&E reported having certain [substation] equipment with an average age of 60 years and an average industry service life of 40 years (i.e., 20 years older than the industry average),” it said. “Further, PG&E reported an average age of failure for this equipment as 70 years with 47% of this equipment exceeding this average age of failure.”
Two other types of assets have exceeded average service lives and industry standards by years or decades, it said.
“If only utilizing asset age to determine an asset’s useful life, PG&E would have to purchase and install over 2,000 components of the aforementioned equipment in order to bring the asset age of the equipment in these three categories down to the PG&E average age of failure for each equipment type,” it said. “A significantly higher investment would be required to get each asset category reduced to the industry average.”
Global supply chain problems, however, are delaying the utility’s equipment replacement programs.
“The emerging risk relates to the volume of assets that have the potential to fail within close time proximity to one another,” the report said.
The ISM
The California Public Utilities Commission required PG&E to pay for an ISM as a condition of approving its bankruptcy reorganization plan in May 2020. The CPUC selected Filsinger, which started work after PG&E exited probation and the oversight of a federal monitor in January. (See PG&E Ends Probation as a ‘Menace to California,’ Judge Says.)
Filsinger is expected to file reports every six months under its five-year contract. Its first report broadly cataloged the problems and progress of PG&E in trying to prevent its transmission and distribution systems from igniting more wildfires.
Catastrophic blazes blamed on PG&E equipment failures included the 2018 Camp Fire, the state’s deadliest and most destructive wildfire that began when a century-old C hook broke on a high-voltage line, causing the jumper conductor to fall onto the steel tower. The resulting electric arcs rained molten steel and aluminum, which sparked the grass and brush below.
The fire destroyed the town of Paradise in hours, killed 84 people and led to PG&E’s January 2019 bankruptcy filing and its guilty pleas in June 2020 to 84 counts of involuntary manslaughter.
State fire investigators have found that PG&E equipment caused massive and highly destructive fires in 2017, 2019, 2020 and 2021. The utility is now under investigation by the U.S. Forest Service for its possible role in igniting the Mosquito Fire, which started Sept. 6 and burned through 77,000 acres of forestland in the Sierra Nevada foothills east of Sacramento.
“The USFS has indicated to Pacific Gas and Electric [in] an initial assessment that the fire started in the area of the utility’s power line on National Forest System lands and that the USFS is performing a criminal investigation into the 2022 Mosquito fire,” PG&E told the Securities and Exchange Commission Sept. 26. Two days earlier, “the USFS [had] removed and took possession of one of the utility’s transmission poles and attached equipment,” it said.
The utility has made progress in some areas, the monitor’s report said, including its use of “enhanced powerline safety settings,” which increase fault-detection sensitivity and quickly de-energize lines that experience problems such as changes in current. The EPSS protocol also disables the automatic reclosing of circuit breakers.
PG&E said the expansion of EPSS in high-risk fire areas has greatly reduced potential ignitions from lines contacting trees and other fire dangers.
“From the implementation of EPSS in late July 2021 through October 2021, PG&E reports a 40% reduction in ignitions as compared to the past three-year average, and an 80% reduction in the CPUC-reportable ignitions as compared to the past three-year average for the same period,” the report noted.
The downside is that use of EPSS and the intentional blackouts known as public safety power shutoffs have significantly increased the number of outages and affected customers in high-threat fire areas, it said.
In a statement Monday, PG&E said “we welcome the oversight provided by the Independent Safety Monitor team. We agreed to this structure when we emerged from Chapter 11 in 2020, believing it would bring additional transparency to our critical safety work.”
The utility’s revamped “leadership team has intensified its focus on fostering an environment that encourages coworkers to raise concerns on any topic, especially around safety and risk, so that we can address things that need to be fixed or made safe,” it said. “The monitor team helps to build upon this culture and brings an enhanced level of openness and transparency to our efforts to provide safe and reliable energy in the face of evolving climate and wildfire risk.”
The company repeated its intent to underground 10,000 miles of power lines in regions at greatest risk of wildfires. The CPUC’s approval of that effort and billions of dollars in ratepayer funding remain uncertain, however.
