NYISO staff Thursday briefed the Installed Capacity/Market Issues Working Group on the schedule for the ISO’s initiative to develop market participation rules for internal controllable lines.
With no internal controllable lines currently operational in New York, the ISO has only some “bare bones” rules in the capacity market that could structure participation of internal unforced capacity deliverability rights (UDRs), said Amanda Myott, energy market design specialist. There are no related rules for energy market participation.
New York in September selected two transmission projects as Tier 4 renewable resources under its Clean Energy Standard. If approved by the Public Service Commission, the 1,300-MW, 174-mile Clean Path New York transmission project is likely to be the first internal controllable line in the state. (See Two Transmission Projects Selected to Bring Low-carbon Power to NYC.)
NYISO will begin by developing energy market rules and then, based on those rules, evaluate if there are any needed revisions to capacity market rules for UDRs.
“Modeling of internal controllable lines within resource adequacy studies will also be an important consideration when determining ICAP market rules,” Myott said.
The working group will discuss energy market designs through April before beginning to talk about the capacity market that same month. The goal is to have a completed proposal by the end of the year.
TAC Members Look for Direction on Governance Structure, Stakeholder Process
ERCOT market participants again expressed their concerns last week with potential changes to the stakeholder process following discussions during last month’s Board of Directors meeting.
The newly reconstituted board reviewed the grid operator’s corporate governance structure and project portfolio and discussed bylaw revisions and other changes. The directors also pressed staff on the many system projects they are working on. (See “Board Discussions,” Texas PUC Pushes ERCOT on Market Changes.)
It followed a tense Technical Advisory Committee meeting in July, when members pushed back against interim CEO Brad Jones’ proposal to convert the committee into one “comprised of senior-level members from each ERCOT member organization.” An August workshop to discuss TAC’s future membership and its interaction with the incoming board was canceled. (See “Members Push Back Against Revamped TAC Structure, Conservative Ops,” ERCOT Technical Advisory Committee Briefs: July 28, 2021.)
TAC currently has 30 members comprising primarily subject-matter experts representing six different market segments. Some members argued last summer that adding officer-level representatives would only slow the committee’s work down.
Morgan Stanley’s Clayton Greer, representing the independent power marketer segment, asked during TAC’s Jan. 31 meeting whether the board, which met in lengthy executive sessions during the two-day meeting, had given any direction to “reformat” ERCOT’s stakeholder process.
“It sounded like they wanted some change, but there was no direction,” Greer said.
South Texas Electric Cooperative’s Clif Lange, TAC’s chair, attended the board meeting. He told Greer that what he heard was more informational for the board and intended to give the directors comparisons between ERCOT’s and other grid operators’ governance structures.
“Nothing I heard that day gave us any direction for us to do anything at this point,” Lange said. “It’s certainly within the purview of the board to determine how they want to establish their committees and subcommittees. I didn’t get the feeling from the room that there was any immediate move to want to do that.
“Whether board members are discussing that offline, something we’re not privy to, that could be ongoing,” he added.
Greer noted the “pile of stuff that we go through as stakeholders” and asked again whether there was a plan to create a better process or methodology for managing change requests.
“The work that gets done … it can be managed any number of ways,” he said. “We selected [the current process] … because for the most part, it’s been effective. It gives a fair hearing to everything and gives everybody a chance to vote on these things. Without a problem statement or understanding what we’re doing wrong, I don’t get how we can get to a better spot without direction.”
Lange allowed that ERCOT’s stakeholders are “keenly interested” in any decisions the board may make on the stakeholder process’ future, telling RTO Insider that he is optimistic the board “still finds value in the collaborative efforts of stakeholders, ERCOT and the” Public Utility Commission of Texas.
“It would be a shame if the stakeholder process was abandoned or significantly diminished, since extraordinary work products have come forth from that collaborative process over the last 20 to 25 years, including the nodal market design and implementation, real-time co-optimization, and ancillary services redesign,” Lange said. “That all occurred while meeting the challenges of tightening reserve margins and with the unmatched integration of significant renewable and storage assets.
“ERCOT does a great job in identifying reliability and market flaws and in defining the objectives that they want to target to address those findings, but they don’t always have the in-house capability to understand the full ramifications of their objectives,” he said. “Stakeholders collectively see the full range of impacts, including financing, development and construction; wires and generator operation; the retail markets; and ultimately the impact to consumers. It is this expertise, combined with the expertise and policy direction provided by ERCOT and the PUCT, that helps to provide a more comprehensive solution. I strongly hope the new board finds value in the stakeholder process and the debate that has allowed for some very good and comprehensive solutions to be developed.”
ERCOT has already responded to the board discussion by creating a Technology Working Group that provides a forum to share information; review, analyze and develop best practices; and improve market participants’ and the grid operator’s information and operational technology systems and software applications.
The group will be independent of the TAC subcommittee structure, similar to the Regional Planning Group and the Gas Electric Working Group. It’s scheduled to hold its first meeting Thursday.
Staff Rushes Firm-fuel Product
ERCOT staff have drafted a nodal protocol revision request (NPRR1120) that creates a firm-fuel reliability product as directed by state legislation last year and the PUC.
The commission’s first phase in redesigning the ERCOT market calls for a standalone, auction-based product that is procured similar to ERCOT’s black start program. The PUC sees the firm-fuel product compensating dispatchable generation resources that meet a higher standard of “firm” winter-weather resilience and reliability and serving as a stopgap should weatherization not be incorporated into a load-serving entity obligation. (See PUC Forges Ahead with ERCOT Market Redesign.)
Kenan Ögelman, ERCOT’s vice president of commercial operations, told TAC that in order to deliver the service by next winter, staff are focusing on the “long pole in the tent,” which is completing the settlement and billing system’s changes. He said additional requirements will be reflected in a request for proposals that will quickly follow the NPRR’s approval.
“We’re going to take more time to develop and will put those parameters into the RFP to procure the service, Ögelman said. “The commission has asked for more time to weigh in on those parameters.”
Greer pointed out that TAC would be expected to pass the NPRR’s language regardless of its accuracy. “I don’t know how you create a straightforward RFP unless you have on-site storage capacity,” he said, adding that coal piles and nuclear rods should also be considered.
“There is an interest is going beyond on-site fuel oil. We want to leave that possibility open, but that would require another RFP and potential protocol language,” Ögelman said. “There are going to be gaps in the RFP that will make the RFP pretty not standard and non-substantial. There are a lot of requirements for the resources that will have to be in the RFP to get this NPRR through.”
Members and staff agreed to set up a workshop to hash out further details on the NPRR and RFP. In the meantime, the Protocol Revision Subcommittee is scheduled to vote on the NPRR during its Wednesday meeting. Staff hope to have the board consider the measure during its March 7-8 meeting.
RUC Usage Skyrockets
ERCOT’s heavy use of reliability unit commitments (RUCs) last year as part of its conservative operations approach resulted in 4,052 instructed resource-hours and 3,853.1 effective resource-hours, an 18-fold increase from 2020. The bulk of those hours (3,361, or 87%) came to meet capacity needs during the latter half of the year, when the grid operator began deploying more resources sooner to improve the system’s reserve margin following last February’s disastrous winter storm.
The difference between “instructed” and “effective” values is because of resources starting up, shutting down, partial hour instructions or otherwise not being dispatched.
ERCOT only called for 224 RUC instructed resource hours in 2020, resulting in 220.1 effective hours.
Reliability unit commitments have soared with ERCOT’s conservative approach to grid operations. | ERCOT
“Compared with previous years, the size of resources getting RUC’ed has not changed much,” ERCOT’s Dave Maggio said.
Last year, ERCOT issued approximately $5.3 million in make-whole payments, almost exclusively covered through capacity-short charges. The total RUC claw-back charge was about $3.1 million.
The Independent Market Monitor is sponsoring NPRR1092, currently before the Protocol Revision Subcommittee. The measure would reduce the $1,500/MWh RUC offer floor, designed for a market construct where RUCs were expected to be self-committed.
Texas PUC Chairman Peter Lake supports the NPRR and has filed a memo siding with its $75/MWh offer floor. He said that will still allow resources to increase offers in accounting for higher fuel prices and will be consistent with non-spinning reserves’ price floor.
“We expect to expect to see improved performance of self-committed resources,” IMM Executive Director Carrie Bivens said.
Stakeholders Eye Load Resources
TAC and staff agreed to work together in creating a task force and scheduling a workshop to address load resource issues as Texas becomes a haven for cryptocurrency miners and other loads that can add energy to the grid. Several stakeholder groups have discussed load resource issues, including how to price them and whether or they are controllable resources.
Texas Gov. Greg Abbott and U.S. Sen. Ted Cruz (R) have led the charge in encouraging Bitcoin miners to set up shop in the state, where their ability to shut down quickly can help the grid during scarce conditions. The Texas Blockchain Council lobbying group says there are already more than two dozen crypto miners in the state.
“Clearly, when the governor and a U.S. senator invite cryptos to come to town, we need to figure out quickly how we can get them reliably connected to the grid,” energy consultant Bob Wittmeyer said. “This issue is much bigger than crypto, which can potentially add hundreds of megawatts to the grid in a period of months. We need to move pretty expeditiously here. We’ve got [transmission and distribution] issues, different metering configurations, co-location issues and issues with resources that choose not to be controllable load resources. We really need to talk about this from multiple levels.”
Several stakeholder groups have already discussed issues surrounding load resources and floated a scope document for the task force. Staff said they need time to better understand the issues before hosting a “meaningful” workshop.
“We need a basics-type of discussion on what these loads are,” Greer said. “It sounds like a lot of these business plans for these guys involve co-locating with either energy storage or generation, or both.”
TAC agreed with Lange’s proposal to have stakeholders and staff begin laying out ideas and bring them back for the committee’s Feb. 23 meeting. The workshop will be held at the TAC meeting, and the task force could be established in March.
Staff Work to Improve Communications
ERCOT staff worked to ease members’ concerns as last week’s winter storm approached, telling them that internal and external communications have both been improved.
“Right now, everything is business as usual at ERCOT,” Chris Schein, interim communications leader, said in providing TAC an update on the grid operator’s efforts.
Schein said ERCOT now conducts daily calls with market participants’ communicators; it has set up a regular cadence for external messages; and it has completed internal and external audits of its communications practices. The internal audit looked back at ERCOT’s communications during the storm, and the external audit looked forward at best practices to address insufficient staffing, inconsistent messaging, uncertainty among the market’s communicators and flawed energy emergency alert (EEA) communications.
The grid operator had fewer than two staffers devoted to media communications during last year’s storm, “insufficient for an organization the size of ERCOT,” Schein said. Outside contractors will help it “dial up or dial down” communications as needed, he said.
ERCOT has made changes to improve its communications. | ERCOT
“Frankly, ERCOT, under the leadership of Brad Jones, has clearly communicated that we are going to be aggressive in calling for conservation alerts,” Schein said. “It’s an effective tool for ERCOT to use. We’ve been working very hard the last seven months with the news media so they understand conservation alerts do not mean EEAs.”
Mark Dreyfus, who represents several cities in the commercial consumer segment and who requested the update, said communication is a two-way street and that many of his constituents need to trust the messages they’re receiving from ERCOT during an emergency.
“I just don’t think we’re there because of the dramatic loss of trust in the community that occurred [last year] with the storm,” Dreyfus said. “We have to engage with those groups to ensure ERCOT is a trustworthy source of information.”
Indeed, a recent University of Houston survey found that if there are more power outages because of cold weather, 70% would hold the grid operator responsible.
Schein agreed ERCOT lost trust during last year’s winter storm. “I’m not making any judgments as to whether it was worthy or not, but it happened,” he said.
“Building trust takes years; losing trust takes seconds. We are in the process of rebuilding trust. It will take time,” Schein said. “We’re at a phase now where it’s trust and verify. We not only have to say things; we have to live up to things so these various audiences will look at us and say, ‘Yes, they did what they said they were going to do.’”
Lange Re-elected TAC Chair
Committee members re-elected Lange and Just Energy’s Eric Blakey to serve once again as their chair and vice chair, respectively, this year.
ENGIE’s Bob Helton, who nominated Lange and Blakey, said he did so because their leadership during a “very difficult year … got us to some places we needed to go.” Helton, who has served as both chair and vice chair, said he looked forward to working with them to finish up ERCOT’s market designs and other issues.
“We have a lot of ground to cover, particularly with the ongoing market-reform issues and anything else that pops up that is unforeseen now,” Lange said. “We’re looking forward to another great year, and a challenging year, for sure.”
Members also confirmed TAC’s subcommittee chairs and vice chairs for 2022:
TAC unanimously approved its combo ballot, which included two other binding document revision requests (OBDRRs) related to recent PUC orders to reduce the high systemwide offer cap (HCAP) from $9,000/MWh to $5,000/MWh and to raise the operating reserve demand curve’s (ORDC) minimum contingency level from 2,000 MW to 3,000. Both changes were effective Jan. 1. (See PUC Forges Ahead with ERCOT Market Redesign.)
OBDRR037 caps the power balance penalty curve at $5,001/MWh (the HCAP plus $1/MWh), effectively setting the curve’s price at its maximum value when violations are above 100 MW. The measure also reduces the generic transmission constraint shadow-price cap for base case voltage violations from $9,251/MW to $5,251/MW. Gray box language describes how the curve will work with the new HCAP upon real-time co-optimization’s implementation.
OBDRR038 updates the ORDC’s minimum contingency level to 3,000 MW within the relevant methodology document.
The combo ballot also included seven NPRRs, two Nodal Operating Guide revision requests (NOGRRs), an additional OBDRR, two modifications to the Retail Market Guide (RMGRRs), three system change requests (SCRs), and single changes to the Planning Guide (PGRR) and the Verifiable Cost Manual (VCMRR).
NPRR1095: contains revisions that the Texas Standard Electronic Transaction (Texas SET) Working Group has determined are necessary to support the Texas SET V5.0 improvement list.
NPRR1098: establishes reactive power capability requirements for new DC ties interconnecting to the ERCOT system and existing DC ties replaced after Jan. 1.
NPRR1099: grants ERCOT greater authority to move a resource node in the network operations model when deemed necessary to properly reflect point-of-interconnection (POI) changes or resource retirements.
NPRR1102: allows ERCOT to adjust back-casted non-interval data recorder load profiles.
NPRR1111: expands the use of the security-constrained economic dispatch (SCED) base point below the high dispatch limit flag to signify that ERCOT has instructed an intermittent renewable resource (IRR) or DC-coupled resources not to exceed its base point.
NPRR1113: adjusts the real-time ancillary service imbalance payment/charge’s definitions to prohibit double-counting of the regulation-up schedule when calculating capacity in the imbalance settlement for controllable load resources available to SCED.
NPRR1114: establishes processes to assess and collect securitization uplift charges to qualified scheduling entities representing LSEs pursuant to one of the PUC’s two debt obligation orders (52322).
NOGRR234: revises the guide to be consistent with NPRR1098’s reactive power capability requirements for DC ties, specifying DC tie operator responsibilities related to real-time operational voltage control.
OBDRR034: allows ERCOT to move network operations model resource nodes for POI changes or resource retirements.
PGRR099: provides that an entity will not be eligible to begin or maintain a generator interconnection or modification (GIM) if it or any other owner of the project meets any of the company ownership (including affiliations) or headquarters criteria listed in the state’s Lone Star Infrastructure Protection Act. Any entity that seeks to initiate a GIM will be required to submit an attestation confirming that it does not meet the statutory criteria.
RMGRR166: revises the timing for retail electric providers to access the daily switch hold files that are posted by the transmission and/or distribution service providers.
RMGRR169: updates the Texas SET’s continuous service agreement (CSA) bypass validations at ERCOT; allows for rejection of move out (MVO) transactions if the CSA owner and MVO competitive retailer (CR) do not match; allows ERCOT to issue a move in transaction for the appropriate CSA CR when an MVO is submitted; and revises the inadvertent gain process to align with SCR817’s proposed MarkeTrak enhancements.
SCR816: unlocks congestion revenue right bid credit on the same day auction results are posted.
SCR817: adds validations/requirements to existing MarkeTrak subtypes, revises existing workflows and suggests new subtypes to align with current market practices for more efficient issue resolution.
SCR819: improves dispatch of base points to resources to account for the ramping of un-curtailed IRRs.
VCMRR032: clarifies that the average run time per start is calculated by dividing the total running hours by the total number of starts during the 20-consecutive-day period. It ensures that at a minimum, one start will be used in the calculation of the average run time per start when the resource is operating on the first interval of the first day of the 20-consecutive-day period.
Residents of the Finger Lakes region in New York joined environmentalists and energy experts Wednesday in opposing a proposed facility that would convert manure from nearly 7,000 dairy cows to renewable natural gas and truck it 70 miles to a pipeline (21-G-0576).
Bluebird Renewable Energy (BRE) in November petitioned the Public Service Commission for a certificate of public convenience and necessity and lightened regulatory regime for the project, which would transport anaerobic digester biogas from Aurora Ridge Farm in Cayuga County via a 5.5-mile pipeline to a processing facility on Sunnyside Farm.
A second pipeline, approximately 1,500 feet in length, would transport raw biogas from the Sunnyside’s own digester to the processing facility.
“Bluebird has provided no emissions analysis showing that piping the biogas, processing it, compressing it, trucking it, reheating it, injecting it into the interstate gas pipeline system and then combusting it as RNG would result in lower emissions,” Josh Berman, a senior attorney with Sierra Club, said at a PSC hearing ahead of the Feb. 11 deadline for comment. “Indeed many of these proposed additional steps risk significantly increasing emissions because they are highly energy intensive and introduce the possibility of methane leaks.”
Moreover, even if there were initial reductions associated with the project, BRE proposes to sell the environmental attributes of its RNG into two out-of-state low-carbon fuel programs: the Federal Renewable Fuel Standard Program or the California Low Carbon Fuel Standard, Berman said.
“If Bluebird commodifies its environmental attributes into one of these programs, any climate benefits will be properly accounted for in that program; it cannot be double-counted as an additional climate benefit for New York,” he said.
BRE argued in its proposal that because of its participation in both programs, the annual production from the project, anticipated to be approximately 172,000 MMBtu of RNG, would displace 926,143 gallons of diesel fuel consumed by the transportation sector.
BRE is a subsidiary of DTE Energy. REV LNG of Mendon, N.Y., is a minority member of BRE.
Lack of Details
BRE requested a non-jurisdictional determination from the state’s Department of Environmental Conservation (DEC) confirming that the project will have no impacts on regulated wetlands and, therefore, that no further DEC permitting is required.
“All of these approvals for the proposed pipeline and RNG facilities are expected to be received promptly so as to permit construction to be commenced and completed as soon as feasible to allow the benefits of the project to be expeditiously realized,” BRE said.
The two dairies now mitigate some of the climate impacts of all their methane by using their digesters to produce biogas and generate electricity that’s used on site, said Gale Pisha of Nanuet.
“However, when Bluebird claims in its petition that its biogas product will displace an equivalent amount of fossil fuel, it neglects to calculate the greenhouse gas emissions resulting from all the additional energy spent to collect, scrub, process, compress and transport the RNG to its injection point,” Pisha said.
Bluebird Renewable Energy projects it would transport one RNG tube trailer per day, like the one shown, for its project in Tompkins County. | Eaton Engineering
BRE said it foresees sending one carbon fiber tube trailer per day to a point where it will be injected into an interstate pipeline, likely the Corning natural gas system near Caton.
The idea of trucking tubes of methane gas bothered Valdi Weiderpass of Endicott.
“This is just unbelievable that we’re still allowing this on New York state roads when the permitting that was used by the federal government to allow this practice in the first place stipulated that these trailers must not leak if the truck has an accident,” Weiderpass said.
He cited several accidents where trucks have rolled over, entered ditches and “then leaked so badly that you could hear it from thousands of feet away, and the first responders that show up are afraid to go near it, rightfully so, because there’s a risk of a fire and or explosion.”
The Bluebird petition appears to be fairly incomplete, energy consultant Bob Wyman said.
“I’ve been involved in many cases in PSC proceedings, but I don’t think I’ve ever before seen one so poorly documented with such an incomplete record,” Wyman said.
The state’s Climate Leadership and Community Protection Act requires that, in making its ruling, the PSC must determine that a project is consistent with the state’s GHG emission-reduction goals. But BRE’s petition does not appear to provide sufficient information to enable the PSC to make such a determination, Wyman said.
“Simply capturing and utilizing some methane does not necessarily result in a decrease in net emissions if one is capturing methane produced from something like an anaerobic digester that dramatically increases the quantity of methane which is produced,” Wyman said.
He also said that injecting RNG into the pipeline system will result in a significant increase in emissions over those that would be produced if the gas were immediately converted to electricity on site. Even if the on-site emissions of the current system are ignored, there would definitely be increased emissions from the transmission, distribution and on-site utilization of the gas, Wyman said.
Aurora Ridge’s and Sunnyside’s digesters are just two of dozens in operation on dairy farms across the state, said Irene Weiser, coordinator of Fossil Free Tompkins, a former council member from the town of Caroline and a retired veterinarian.
“The state must evaluate the implications of its analysis and ruling in light of potentially similar actions from the broader sector in which anaerobic digesters are used. … In light of the paucity of information on the record at this point, I urge the commission to consider a second public statement hearing when the record is complete so that the public is better able to provide meaningful comments,” Weiser said.
President Biden on Friday extended Trump-era tariffs on imported solar cells and panels but softened the blow by continuing an exemption for bifacial panels and doubling the amount of imports that can enter the country duty free each year, from 2.5 GW to 5 GW.
In his proclamation on the tariffs, Biden said keeping the tariffs in place was “necessary to prevent or remedy serious injury to the domestic [solar] industry” from cheaper imports, mostly from China, while also noting that “the domestic industry is making a positive adjustment to import competition.”
The president also said the tariffs will step down each year, but according to an addendum to the proclamation, these reductions will be minor. When originally established by former President Donald Trump in 2018, the solar tariffs stood at 30%, with a 5% decrease every year to their current level of 15%. Biden’s extension shaves the tariff amount by 0.25% annually, beginning at 14.75% in 2022 and bottoming out at 14% in 2026.
The solar industry’s reaction was mixed. The Solar Energy Industries Association (SEIA) has long opposed the tariffs, arguing that they have cost the industry close to 62,000 jobs and have not produced a significant increase in domestic manufacturing. SEIA CEO Abigail Ross Hopper expressed disappointment with the extension but said that the administration had reached a “balanced solution” with the bifacial exemption and quota increase.
“Today’s decision recognizes the importance of [bifacial] technology in helping to improve power output and lower costs in the utility-scale segment,” Hopper said. “It is a massive step forward in producing clean energy in America and in tackling climate change.”
Gregory Wetstone, president and CEO of the American Council on Renewable Energy, called the bifacial exemption and doubling of the duty-free quota “reasonable steps that will help our clean energy sector to continue growing at the rate we need to reach our climate goals.”
But he also called for stronger federal action to build out a “robust domestic supply chain … including enactment of the clean energy manufacturing incentives found in the Build Back Better Act.”
Mark Widmar, CEO of Arizona-based First Solar, which manufactures thin-film solar panels, slammed the bifacial exemption for “[unleveling] the playing field. … With bifacial being the dominant Chinese solar product today, this decision effectively allows China to outflank American efforts to grow self-reliant solar supply chains.”
Bifacial technology allows panels to produce power on both sides versus the one-sided panels that have been the industry standard. They can therefore produce more power per panel and are increasingly being used in utility-scale projects across the country, but the U.S. has yet to develop a home-grown supply chain.
Sen. Rob Portman, a Republican from Ohio, where First Solar is building a 1.8 million-square-foot plant, also criticized the bifacial exemption. “It will do nothing to incentivize the investments necessary to expand domestic manufacturing of solar panels, and only continues our reliance on China and their forced labor practices for this technology,” he said.
Widely referred to as the Section 201 tariffs — for the provisions in the 1974 Trade Act which authorizes them — the tariffs were first put in place by Trump in 2018, following a complaint from two U.S. solar manufacturers, Suniva and SolarWorld, to the U.S. International Trade Commission. SolarWold was acquired by SunPower, a leading U.S. solar manufacturer.
The decision on whether to renew the tariffs has been a loaded one for Biden as he tries to stimulate domestic supply chains for renewable energy while accelerating the deployment of solar to meet his targets of a decarbonized grid by 2035 and a net-zero economy by 2050. The energy provisions of the stalled Build Back Better bill included production tax credits and other incentives to spur domestic supply chains.
The catch is that supply chain expansion generally follows demand. According to widely cited figures from the Chinese Photovoltaic Industry Association, China produces about 80% of solar panels used in the U.S. and worldwide. Dependence on Chinese imports has long been a sore point for the U.S. solar industry and a target for critics of Biden’s clean energy policies, who argue that accelerating decarbonization of the grid will only increase that dependence.
Reports of forced labor at some Chinese solar plants have also raised concerns on both sides of the aisle, and in June, Biden banned the import of silicon materials from a Chinese manufacturer found to be using forced labor.
As a result of the tariffs, both Chinese and Korean solar cell and panel producers have begun manufacturing in the U.S. JinkoSolar, a Chinese firm, has a factory in Jacksonville, Fla., while Korean firms LG Electronics and Hanwha Q Cells opened plants, respectively, in Huntsville, Ala., and Dalton, Ga.
The owners of a commercial high-rise in Lower Manhattan are targeting lost heat as part of a decarbonization pilot for the Empire Building Challenge in New York.
“345 Hudson [St.] is the quintessential New York City building at 17 stories, with almost a million square feet, and built in the 1930s,” Michael Izzo, vice president of carbon strategy for the real estate firm Hines, said Thursday.
The building has 54% energy waste, which represents a significant portion of the $3 million the owners spend on energy each year, Izzo said during an Empire Building Challenge event hosted by Building Energy Exchange and the New York State Energy Research and Development Authority (NYSERDA). Hines is the operating partner for Hudson Square Properties, a portfolio of 12 buildings that includes 345 Hudson.
As one of four high-rise retrofits selected in January for the building challenge, the pilot at 345 Hudson is all about decarbonizing heat through recycling, according to Izzo.
“When we talk about heating, our steam system was designed in the early 1900s, and our fossil-fuel systems and boilers in the 1950s,” he said. “That infrastructure has not changed.”
For the pilot, the owners will turn to air-to-air energy recovery and heat-pump technology to recycle energy. Some wasted energy from the building will transition to an adjacent building or go to thermal storage before any excess is vented outside.
New York City has more than 1 million buildings that are responsible for 70% of the city’s carbon emissions, according to Richard Yancey, executive director of Building Energy Exchange. Most of the city’s buildings, he said, were built before the advent of current codes and standards and “fall far short of their performance potential.”
The 2019 Climate Mobilization Act set emission standards for the city’s buildings that go into effect in 2024 and increase every five years. Those standards, together with a recent ban on fossil-fuel-burning equipment in new construction and renovations in the city, have “ignited a retrofit revolution at an unprecedented scale,” Yancey said.
By 2050, he added, 90% of the city’s buildings will need to complete energy efficiency upgrades.
“The retrofit market will be colossal,” reaching between $17 billion and $24 billion within 10 years, he said.
Launched in September 2020, the Empire Building Challenge now has 10 real-estate portfolio owners, representing 700 buildings, working on high-rise, low-carbon demonstrations.
Gov. Kathy Hochul awarded Hines, Empire State Realty Trust, L+M Development Partners and Omni New York $5 million each through a competitive solicitation for their replicable high-rise retrofit projects that address barriers to decarbonization.
“We’ve been working closely with these partners for well over a year,” said Janet Joseph, senior vice president of strategy and market development at NYSERDA. “We’re very excited to move to this next phase of implementation and, hopefully very soon, construction.”
Other Projects
The Empire State Realty Trust plans to make the Empire State Building carbon neutral by 2030, according to Dana Schneider, senior vice president and director of energy and sustainability.
Initial carbon reduction measures, such as moving from steam to electric chillers, have reduced emissions 54% in the iconic building, and the goal is 80%, she said.
Through the building challenge, the trust is upgrading the Empire State Building’s control systems to improve system performance.
“We’re doing a lot of work to control our steam,” which Schneider said will be critical while the trust tries to make a business case for replacing steam systems with electricity. “Sometimes that’s difficult to do, and it’s certainly difficult to do all at once.”
At The Heritage in Harlem, L&M will update the 600-unit apartment complex with an insulated façade and a thermal heat-pump system in one of the buildings.
The three-building complex was constructed in the 1970s as a prototype for affordable housing that integrated a federal Head Start program and a center for child development, according to Joseph Weishaar, vice president of L&M fund management.
Working with the building challenge will allow L&M to electrify domestic hot water on the property.
“There are new domestic hot water plants that can compete with natural gas on an operating cost basis, but their upfront cost is very high,” Weishaar said.
L&M will connect heat pumps to a centralized control system so that the building can respond to grid conditions.
Whitney Young Manor, a 12-story, 1970s apartment complex in Yonkers, will receive an insulated exterior façade upgrade as part of Omni’s pilot.
The building is on a path to carbon neutrality by 2035, said Anna Weiss, vice president of Omni.
One of the major retrofit challenges for the project, she said, is installing and maintaining technology that is not “fully vetted” for cold weather.
In addition to upgrading the building envelope, Omni will install an air-source heat pump heating and cooling system with a central loop. Domestic hot water will transition to a water heat pump system that feeds off the air-source central loop. Backup gas boilers will be available on the building’s roof in the event of extreme cold weather.
“If we have an emergent situation in a blackout, we can be assured that our tenants will still have heat and they will be comfortable in our apartments,” she said.
Washington state lawmakers have introduced a bill that would create a council to help phase in the adoption of electric vehicles and manage the state’s spending of federal funds targeted at building EV-related infrastructure.
“Presently, there are four agencies in charge of these vehicles’ electrification. We need a coordinated strategy,” SB 5908 sponsor Sen. Marko Liias (D), chair of the Senate Transportation Committee, said during a hearing on the bill Thursday.
Led by the state’s Commerce and Transportation departments, the Interagency Electric Vehicle Coordinating Council’s duties would include developing a strategy to ensure that the state is prepared for EVs to account for all new car sales in 2035. The new body would also gather and disseminate information about EV programs, policies and funding.
If approved, the council’s most pressing task would likely be to identify and coordinate EV-related grant programs stemming from the federal Infrastructure Investment and Jobs Act passed last year. Washington is expected to receive $71 million from the act to expand EV charging networks, in addition to $4.7 billion in highway aid, some of which could be eligible for allocation to EV-related projects.
The council’s other responsibilities would include:
developing a statewide electrification roadmap that is coordinated with an EV mapping and forecasting tool required in state law (See Inslee Vetoes Part of Wash. EV Mapping Bill.);
create an industry EV advisory committee to provide input on ways to more effectively and efficiently decarbonize the transportation sector through electrification policies;
identifying policy challenges and existing barriers in electrification policies; and
ensuring the state’s EV strategy benefits disadvantaged communities.
Thursday’s committee hearing picked up only two people testifying on the bill, both in support.
Debbie Driver, Gov. Jay Inslee’s senior transportation adviser, testified in favor of creating an interagency council to focus on EV policy. The original version of the bill had called for establishing an altogether new agency to address the issue.
“It brings together the best and the brightest in our state agencies,” Driver said.
Annabel Drayton of the NW Energy Coalition also supported the council’s creation, but she said the bill should add protections for consumers to its duties.
While 246 people signed up to oppose the bill, none testified, so no reasons for the opposition publicly surfaced. Eleven others who signed up in support of the bill also failed to testify.
Full adoption of the bill will be contingent on the state’s transportation budget providing funding for the council by June 30.
The California Air Resources Board could adopt by year-end several regulations intended to speed the transition to zero-emission vehicles, including the Advanced Clean Cars II rules.
Cars, trucks, commercial harbor craft and locomotives are covered by the proposed regulations, according to a presentation to the CARB board during a Jan. 27 meeting.
“The single element that binds these efforts and drives them all is the transition away from combustion,” CARB Executive Officer Richard Corey said.
Corey described Advanced Clean Cars II (ACC II), which would move the state to 100% zero-emission car sales by 2035, as “one of the most significant climate and clean air efforts for 2022.” The board is expected to consider the regulation on June 9, followed by a second hearing and vote in August.
ACC II would be a follow up to California’s current Advanced Clean Cars regulation, with the new regulation covering cars starting with model year 2026.
The regulations include a low-emission vehicle program, which sets emission standards for light- and medium-duty vehicles. The second piece of ACC is a ZEV program, which requires car manufacturers to supply a certain number of battery-electric, fuel-cell electric or plug-in hybrid vehicles each year.
As of October, 15 states and the District of Columbia had adopted California’s Advanced Clean Cars regulation.
A new feature of the proposed ACC II regulation is a system of environmental justice credits within the ZEV program. For example, automakers could receive credits for selling EVs at a discount to community programs offering services such as ZEV car-sharing. (See CARB Plan Would Allow Interstate Transfer of ZEV Credits.)
The proposal also includes warranty and durability requirements for ZEVs, which would “assure consumers that ZEVs can serve as true replacements to conventional vehicles,” Corey said.
“This will support providing dependable, high-quality zero-emission vehicles on the secondary market as well,” he added.
Cost Impact Study
As part of the regulatory process, the state Department of Finance released a Standardized Regulatory Impact Assessment (SRIA) for ACC II on Feb. 1.
ZEVs have higher upfront capital costs but lower operating costs, and the regulation should result in net savings for car buyers, the SRIA said.
The analysis estimated that the total cost of the proposed regulations from 2026 to 2040 would be $289 billion and total savings would be $338 billion, for a net savings of $49 billion.
The net savings includes about $16 billion in reduced tax and fee revenue, which would have negative implications for state and local government, according to the assessment.
The next step in the ACC II rulemaking will be an Initial Statement of Reasons (ISOR) that explains the justification for each provision in the regulation. CARB expects to release the ISOR in mid-April for 45 days of public comment.
Advanced Clean Fleets
CARB will also continue to work this year on the proposed Advanced Clean Fleets regulation, which aims to achieve zero-emission truck and bus fleets in the state by 2045, where feasible. The proposal would require a zero-emission transition for some vehicles sooner. All drayage trucks, for example, would be required to be zero-emission by 2035.
CARB expects Advanced Clean Fleets to go to the board for a first hearing by the end of this year.
Boats, Trains
Last year, CARB proposed amendments to its Commercial Harbor Craft regulation, whose goal is to reduce emissions of diesel particulate matter, nitrogen oxides and reactive organic gases from diesel engines used on boats.
The proposed amendments would include a requirement for new and in-use short-run ferries to upgrade to zero-emission vessels by the end of 2025. Many tugboats would be required to use Tier 4 engines equipped with diesel particulate filters.
The harbor craft regulation is expected to go to the board for final approval in the next few months.
CARB is also working on an in-use locomotive regulation that it expects to present to the board in the fall. The proposal would apply to all line-haul, switch and passenger locomotives that operate within the state.
As proposed in a discussion draft of the regulation, locomotive operators would be required to place funds each year into a “spending account” based on the emissions of their locomotives. Zero-emission locomotives in a fleet would receive a credit, which could be deducted from the amount that must be paid into the spending account.
Operators would use money in the spending account to buy or lease locomotives that meet increasingly stringent emission standards, with a zero-emission requirement starting in 2035.
“Cleaning up railyards is crucial to cleaning up the air in our hardest-hit communities,” Corey said.
ISO-NE CEO Gordon van Welie resumed his push for winter reliability solutions Thursday, pointing to near misses last month as motivation to make policy changes, while also reiterating that the RTO has limited agency in fixing the region’s problems.
Van Welie’s memo to the NEPOOL Participants Committee followed up on recent exchanges he has had with state officials after ISO-NE issued vocal warnings about the reliability of the grid in New England ahead of this winter. (See New England’s Reliability Debate Bleeds into FERC Compressor Decision.)
A lack of extended extreme weather has spared the region from the worst effects so far this season, but van Welie warned in his latest memo that policymakers still need to find solutions.
The message was a familiar refrain. A changing generation mix is leading to new problems and could be “insufficient in the face of the wrong combination of severe weather, non-gas generation contingencies and fuel supply chain issues,” van Welie wrote.
It also came with a new twist: an “evolving situation” in New York, including the shutdown of the Indian Point nuclear plant and increasing gas consumption, that could lead to reductions in how much energy it exports to New England.
On one of the biggest issues —
how to store energy for longer durations —
van Welie laid out a few possible solutions, including more hydro imports from Quebec, increased LNG imports and more dual-fuel capability.
But his biggest ask in the new memo was for better coordination, and he placed the onus on FERC to get everyone into the same room.
“We plan to continue talking with the states about this issue, and we’ve asked FERC to continue to focus on these issues with us until we find a solution. We are hoping that they will utilize their convening power to get all the right parties together later this year,” he wrote.
January Scares
Several incidents on cold days in January that led ISO-NE to briefly take emergency actions paint a picture of the vulnerabilities that van Welie is describing.
The first was on Jan. 11. NYISO told ISO-NE in the morning that it would likely have to reduce imports because of constraints on its own system. Around noon, a pole on the Phase 2 line from Hydro-Quebec tripped. Throughout the day, 1,100 MW of generation went down, and in total, an expected surplus of 1,278 MW turned into a deficit of about 1,200 MW.
The RTO had to commit additional units and declared a Master/Local Control Center Procedure No. 2, preparing for abnormal conditions on the grid.
The problems ultimately self-resolved, with imports resuming from New York and the Phase 2 trip fixed.
But the next day brought more challenges. Canaport LNG lost its electric feed, and ISO-NE had to notify New England pipelines that they should expect additional demand. The line was restored a few hours later.
The Millstone nuclear plant in Connecticut also went down for nearly a week during January for repairs.
“These are many of the major contingencies we worry about, and they all occurred within the span of two weeks,” van Welie wrote. “Thankfully, the region did not experience extended severe weather during this time frame, and we have been able to manage through them.”
The D.C. Circuit Court of Appeals issued a stay Friday on FERC’s order to terminate Killingly’s capacity supply obligation, allowing the proposed Connecticut natural gas plant to participate in ISO-NE’s capacity auction Monday.
“Absent other legal developments, the ISO will comply with this order in the conduct of the auction and will therefore unwind the actions it had taken to terminate Killingly,” ISO-NE said in a notice to stakeholders Friday evening. “After FCA 16 is conducted, should FERC confirm the termination of Killingly, the ISO would adjust the auction results to reflect the removal of Killingly.”
ISO-NE had requested the termination of Killingly’s CSO in November, saying that the project would not be able to meet key milestones for fulfilling its capacity obligations.
FERC approved the termination Jan. 3, writing that it was “persuaded by the evidence” presented by ISO-NE (ER22-355). That meant Killingly would have to forfeit its CSO for 2022/23 and would not be able to take part in FCA 16. (See FERC Accepts ISO-NE Request to Terminate Killingly CSO.)
The D.C. Circuit ruled that the order cannot be enforced until FERC “resolves” developer NTE Energy’s Jan. 11 petition for rehearing.
The rehearing request would be automatically denied “by operation of law” if the commission does not act on it within 30 days.
The court’s full opinion was not yet available as of Saturday. Judge Robert Wilkins noted in the order that he would have denied the stay, but Judges Neomi Rao and Ketanji Brown Jackson sided with NTE.
The developer did not immediately respond to a request for comment.
In a second notice Sunday, the RTO said it had declined suggestions that it delay the auction. Instead, ISO-NE said it will calculate prices and quantities cleared with and without Killingly. “The ISO intends to keep these results confidential until there is greater certainty about Killingly’s status. This will protect the commercially sensitive information that might otherwise be revealed as part of the auction finalization process,” said Allison DiGrande, director of Participant Relations & Services. “This approach will allow the ISO to conduct the auction in a timely fashion, consistent with the requirements of its tariff, while addressing the uncertainty created by the recent D.C. Circuit Court of Appeals order.”
DiGrande said the RTO also will not reveal the results of any clearing in the substitution auction until Killingly’s status is resolved. “The ISO believes that this is the most prudent path to both minimize disruptions to the administration of FCA 16 and the required timing of [Forward Capacity Market] activities related to subsequent auctions. After due consideration, the ISO is confident that this approach will ensure the integrity of the auction while also complying with the D.C. Circuit Court of Appeals order.”
In a subsequent notice on Feb. 11, the RTO announced that NTE had been suspended from the markets and told stakeholders that “a
market participant would not be allowed to participate in an Forward Capacity Auction (FCA) unless it was in compliance with the Financial Assurance Policy.”
Five business days after being suspended, a company’s CSO would be terminated and financial assurance forfeited.
Oregon’s investor-owned utilities are asking state regulators to alter key provisions in a newly proposed set of rules designed to bolster utility wildfire mitigation plans.
Portland General Electric (PGE), PacifiCorp and Idaho Power on Wednesday jointly filed a draft of the proposed rules that eliminates a requirement that the IOUs collaborate with other users of shared utility poles, such as telecommunications and cable providers, on 10-year inspections to ensure compliance with wildfire safety standards.
Under current regulations, electric utilities are solely responsible for regular inspection of poles supporting their lines, the costs for which are recovered from ratepayers. In crafting the new rules requiring joint inspections, Oregon Public Utility Commission (OPUC) staff were looking to spread the cost of those inspections to other beneficiaries.
The joint inspection provision emerged as a major sticking point at a Jan. 18 OPUC meeting, when the commission voted to proceed with a formal rulemaking process for the broader ruleset that includes the provision despite utility objections. The commissioners urged commission staff and the IOUs to negotiate a revision for the commission to consider before the rulemaking begins. (See Ore. PUC Advances Wildfire Rulemaking Despite Utility Concerns.)
The IOUs voiced concern about the complexity — and risk — of relying on joint inspections, especially for utility poles in high fire-risk areas that might have multiple users and owners.
“We have significant concerns that the proposed joint inspection mandate will cause delays to find and remediate issues found in high fire-risk zones and inevitably increase wildfire risk,” Larry Bekkedahl, PGE senior vice president of advanced energy delivery, said at the Jan. 18 meeting.
Bekkedahl said PGE preferred to continue the existing policy of solo inspections, a position backed by representatives from PacifiCorp and Idaho Power. Commissioner Mark Thompson sympathized with the IOUs, even suggesting he was disinclined to vote in favor of the rulemaking over doubts that the commission could resolve the joint inspection issue during the formal process.
The IOUs offered a blunt solution to the problem in their redline draft, striking the definition of “joint inspection” and any additional references out of the proposed rules — an approach likely to get pushback from commission staff.
More Redlines
The redline draft also addresses the IOUs’ concerns regarding another section of the proposed rules that could put utilities in conflict with municipal codes when trimming trees away from lines in high fire-risk zones within urban areas. The IOUs’ revisions would clarify that utilities are exempt from local ordinances around tree trimming and removal in such zones, giving primacy to OPUC standards.
Last month, the utilities suggested that the commission modify those provisions to focus utility trimming operations on only the highest risk areas, typically located outside urban areas, thereby avoiding conflicts. They appeared to change tack in response to Commissioner Letha Tawney’s questions about whether municipal codes sufficiently accounted for wildfire risk, raising concerns that ignitions in populated areas could create “real havoc.”
The IOUs suggested additional revisions, giving them more latitude in responding to safety violations discovered on non-utility-owned — or “foreign-owned” — poles, including the right to issues a pole owner a notice that specifies a timeline for repair.
“If the pole owner or equipment owner does not replace the reject pole or repair the equipment within the timeframe set forth in the notice, then the operator of electric facilities may repair the equipment or replace the pole and seek reimbursement of all costs and expenses related to correction or replacement of the reject pole or equipment including, but not limited to, administrative and labor costs related to the inspection, permitting and replacement of the reject pole,” the IOUs wrote.
A utility would also be authorized to charge the pole owner a replacement fee amounting to 25% of the cost of the work.
OPUC will meet again on Feb. 8 to discuss the wildfire mitigation plan rules.
