Saying “divorce is not an option,” California Gov. Gavin Newsom met with Chinese President Xi Jinping in Beijing on Wednesday to bolster climate cooperation between his state and the People’s Republic of China.
The talks with Xi and other Chinese officials focused mainly on climate and economic issues, but also touched on human rights and the fentanyl crisis, according to the governor’s office.
While noting “major differences,” Newsom said working together on climate change “can be the bridge we’ve been missing.”
“I made it clear to Chinese leaders that California will remain a stable, strong and reliable partner, particularly on low-carbon, green growth,” Newsom said in a statement.
Also Wednesday, Newsom signed an agreement with Chairman Zheng Shanjie from the National Development and Reform Commission to combat climate change and advance clean energy development.
China is the world’s largest emitter of greenhouse gases and is responsible for almost a third of global GHG emissions. The U.S. is the second-largest GHG emitter, with roughly half the annual emissions of China in 2020.
About half of China’s GHG emissions come from its power sector, and the nation continues to add new coal plants.
California aims to reach carbon neutrality by 2045; China has set a 2060 goal.
Citing the impacts of the climate crisis on California, including floods and wildfires, Newsom called for efforts to meet carbon neutrality goals earlier. He emphasized the urgent need to transition away from fossil fuels.
As part of the discussion, Newsom touted battery storage technology. California has increased battery storage resources from 770 MW in 2019 to 6,600 MW as of this month, a number expected to grow to 8,500 MW by the end of the year, the state announced this week.
The California-China cooperation aims to reduce carbon emissions while fostering economic growth. The governments will work to accelerate the clean energy transition, including zero-emission vehicles, offshore wind and advanced energy storage technologies.
Newsom’s meeting with Xi on Wednesday was part of the governor’s weeklong trip to China.
On Tuesday, he visited China’s Greater Bay Area, a region consisting of Hong Kong, Macao and nine major cities. There, he visited the world’s first zero-emission city bus fleet, and the state entered a climate partnership with Guangdong Province.
The trip comes at a time of tense U.S.-China relations, and some say the visit could be politically risky for Newsom.
Given the complexities of the U.S.-China relationship, some see “subnational” efforts as key to climate action.
“The states really are where anything substantive is going to happen,” David Victor, co-director of the Deep Decarbonization Initiative at the University of California, San Diego, told NBC News.
Newsom coordinated his travel with the White House, Politico reported, and he was accompanied by Nicholas Burns, the U.S. ambassador to China.
“This was a very positive and consequential day for the United States,” Burns said in a statement following Wednesday’s meetings.
FERC on Oct. 24 fined independent power producer AES $6 million for failing to fulfill resource adequacy obligations related to eight of the company’s 12 generating units operating in Southern California (IN23-15).
At issue in the order was the performance capability of eight AES units at the Alamitos and Redondo Beach power plants, which were contracted through CAISO resource adequacy purchase agreements from June 2018 to May 2020. All 12 of AES’s units received payments for providing capacity to the ISO’s market during that time frame.
CAISO had contracted with the resources to bid energy into the ISO market and deliver their maximum output — or Pmax — should it become necessary during Southern California’s hot summer months. Before entering the contract, AES was required to submit a master file containing the operating and technical characteristics of each unit, including their Pmax ratings. ISO guidelines stipulate that a Pmax value be based on the highest MW output a unit can sustain over a 30-minute interval.
However, in August 2019 CAISO’s Department of Market Monitoring (DMM) notified FERC’s Office of Enforcement (OE) that AES had submitted inaccurate master file parameters to the ISO that overstated some of the resources’ Pmax values before entering the contract.
DMM reported to OE that summer readiness tests CAISO performed in spring 2019 and exceptional dispatches occurring in July 2019 showed that AES’s Alamitos units 3, 4, 5 and 6 and Redondo Unit 7 were unable to meet the Pmax values submitted to the ISO in the original master file, resulting in a total deficiency of 91.80 MW.
According to the DMM’s referral, the eight AES units were either unable to reach or maintain full capacity for a 30-minute interval after they were dispatched by CAISO. Regardless, AES had sold and, in some cases, financially benefited from RA contracts stating that their resources were operating at full capacity, FERC said.
As a result, OE found AES to be in violation of multiple sections of the CAISO tariff. The company did not admit or deny the violations but agreed to pay $2.97 million in disgorgement to CAISO and $3.03 million in civil penalties to the U.S. Treasury.
AES owns and operates a portfolio of generation of approximately 32,300 MW of energy worldwide. As of 2022, AES was one of the largest independent producers in California, with a capacity of 3,799 MW in the state.
New Jersey has revised its strategy for building the infrastructure to link offshore wind (OSW) projects to the grid onshore, abandoning a plan to have the developers in the state’s third solicitation submit connection proposals along with their wind farm plans.
Instead, the New Jersey Board of Public Utilities (BPU) on Oct. 25 agreed to split off the connection infrastructure part of the project from wind farm development and hold a separate solicitation for the infrastructure work. The wind farm solicitation, which is expected to be concluded with project selection in early 2024, will continue as planned.
Jim Ferris, deputy director of the agency’s division of clean energy, said that after reviewing the infrastructure component of the four bids submitted in the OSW solicitation, his staff concluded the original plan “imposes an unreasonable burden” on ratepayers. Splitting the two would increase competition by allowing infrastructure proposals from developers who had not submitted an OSW generation project, he said.
The BPU’s 4-0 vote — one seat is vacant — was one of two decisions at the meeting triggered by implementation challenges involved in creating infrastructure that can handle the massive escalation in electricity generated that’s expected as the state’s clean energy policies unfold.
Separate from the OSW decision, the BPU agreed to extend the development deadline of five community solar projects after the developers filed petitions stating the utility to which they would connect their projects, Atlantic City Electricity, would take between 20 and 32 months to connect them to the grid. That delay effectively would prevent them from meeting program-imposed deadlines, the developers said.
BPU Commissioner Zenon Christodoulou acknowledged the OSW decision would not please some stakeholders but was necessary.
“I understand the frustration that this must cause on behalf of some of the developers that solicited [projects] in good faith,” he said. “But we appreciate their partnership and look forward to working with them in the future to provide and promote a better product that will serve them the projects and the ratepayers.
Commissioner Mary-Anna Holden echoed the sentiment but said she was “very comfortable” with the decision.
“It is frustrating, but we’re moving ahead,” she said, adding that she backed the “approach that you’re going to take with the pre-build, and soliciting people that really have an expertise in this transmission building.”
New Solicitation
The state’s third OSW solicitation, which could add capacity of between 1.2 GW and 4 GW and perhaps more, follows a 2019 solicitation in which the BPU backed the state’s first OSW project, Danish developer Ørsted’s 1,100-MW Ocean Wind 1. In the second solicitation, the state backed Ørsted’s 1,148-MW Ocean Wind 2 project and the 1,510-MW Atlantic Shores project.
Gov. Phil Murphy (D) has set a state wind capacity target of 11 GW, of which the BPU so far has awarded 3,758 MW. Four bidders have submitted plans in the third solicitation (See NJ’s 3rd OSW Solicitation Attracts 4 Bidders.)
The BPU on Oct. 27, 2022, approved onshore transmission upgrades totaling $1.07 billion that were submitted under a groundbreaking use of FERC Order 1000’s State Agreement Approach. The approved projects would create a new substation to accept OSW electricity, known as Larrabee Collector Station. (See NJ BPU OKs $1.07B OSW Transmission Expansion.)
The BPU acknowledged at the time that the projects’ selection under the SAA would not prevent future OSW generators from proposing different landing points or different routes to connect their offshore projects with the grid. In response, the board said it would require a successful bidder in its third OSW solicitation to “prebuild” offshore ducts and cabling to connect projects to the grid, known as PBI — creating a single corridor from the shore crossing to the Larrabee collector.
Ferris told board members Wednesday that the BPU planned for the offshore connection to link four OSW projects and land at the New Jersey National Guard Training Center in Sea Girt, from where it would connect to the Larrabee station. That “would minimize environmental and community impacts by resulting in a single short crossing and a single or limited onshore corridor to the point of interconnection,” he said. The BPU planned to recover the cost of the infrastructure through the state’s Offshore Wind Renewable Energy Certificate (OREC) system, which also would fund the OSW projects, he said.
However, Ferris said, the agency now believes the use of the “OREC funding mechanism” and the “requirement that the PBI could only be awarded to a developer who also receives an award as a qualified offshore wind project imposes an unreasonable burden on New Jersey’s ratepayers.”
“Staff has determined that a separate solicitation for the PBI open to transmission developers, transmission owners, offshore wind generation developers and other qualified firms.”
A separate solicitation would “would increase competition and lead to ratepayers’ savings,” he added. He said the BPU staff believed the move would “not affect the generation project component of the third offshore wind solicitation applications.”
Deadline Extension
In a separate case, the board approval of five deadline extensions in the state community solar program highlighted the difficulties faced by solar projects in some parts of the state in connecting projects to the grid.
Solar developers have for a while expressed concern about the challenges, and delays involved in getting projects connected, and cited the area served by Atlantic City Electric (ACE) in South Jersey as the worst. (See Solar Developers: NJ’s Aging Grid Can’t Accept New Projects.)
In outlining the case for an extension, Sawyer Morgan, clean energy representative for the BPU, noted that only 3 MW out of 33 MW of community solar project capacity that was approved by the BPU in the ACE area was expected to open within the program deadline.
The board’s unanimous vote comes as the state prepares to transition to a permanent program — the Community Solar Energy Program (CSEP) — after two heavily oversubscribed community solar pilot programs that resulted in the approval of 150 projects totaling 235 MW. (See NJ Opens Community Solar and Nuclear Support Programs.)
The BPU approved the five projects seeking extensions in the second pilot program. They include two rooftop solar projects developed by Solar Landscape in Millville; two by Trina Solar Development on a Pennsville landfill; and a landfill project created by Greenpower Developers in Stafford Township. The projects had an initial 18-month deadline requiring them to become operational by May 4, 2023, which the BPU subsequently extended to Nov. 4, 2023, Morgan said.
“The petitioners each separately engaged in discussion of alternative interconnection options, but ACE’s construction timelines still extended beyond the deadlines,” the BPU representative said. “All three indicated that they would have been able to fully complete project construction by the deadline were it not for the upgrades required for interconnection.”
The BPU representative said the difficulty of getting community solar projects online in areas served by ACE “may raise equity concerns for potential subscribers, as substantially more projects in other parts of the state have been able to become operational.”
A deadline extension is warranted, he said, because the problems they face “were systemic, unforeseen and unforeseeable by petitioners, and wholly outside of their control.”
Asked about the comments, Francis Tedesco, ACE spokesman, said in an email to RTO Insider that the company is “committed to continuing to work with local and state partners to accelerate the clean energy transition, including community solar, for the communities we serve.”
“We continue engaging with state electric utility companies, solar developers, the NJ Board of Public Utilities and other stakeholders and are actively working toward performing necessary energy grid upgrades to help accommodate community solar projects in our service area,” he said.
Speaking before the ERCOT Board of Directors on Oct. 17, the grid operator’s Independent Market Monitor, Potomac Economics’ Carrie Bivens, defended her organization’s recent report that the grid operator’s newest ancillary service “likely” raised the real-time market’s energy value by at least $8 billion.
Several directors latched on to the $8 billion figure during their meeting before Bivens stood at the podium, saying the figure was “erroneously reported” and “a billion-dollar headline that was inaccurate.”
In the report, the IMM said ERCOT’s recent implementation of ERCOT contingency reserve service (ECRS), its first ancillary service in 20 years, has nearly doubled the amount of required online reserves and resulted in “enormous” increases in market costs and shortage pricing when the market is long.
Procuring and deploying the service has reduced supply and liquidity in the day-ahead market, “significantly” raised demand for ancillary products and resulted in inefficient day-ahead ancillary service (AS) price spikes, Bivens said during a September working group presentation. (See ERCOT IMM Raises Concerns over Newest Ancillary Service.)
“We know that this service has not increased efficiency because of the analysis that we perform,” Bivens said, noting the ECRS business case focused on improving market efficiency. She said the report’s purpose was to show an “order of magnitude” so the board could understand the costs involved.
Bivens said the IMM intends to provide comments to staff’s annual AS methodology report to “tweak” how ECRS and non-spinning reserve is purchased “to bring that into alignment with what we think are more reasonable reliability goals.”
“I hope that we can engage you guys in December to talk more about the ancillary services methodology,” she said.
Former Rep. Bill Flores (R), the board’s vice chair and a proponent of dispatchable thermal generation, debated Bivens over AS products and their value in avoiding load shed, saying their additional costs are worth the alternative.
Board Vice Chair Bill Flores | ERCOT
“When you look at the cost of ancillary services that’s paid for to try to encourage reliability to try to create a reliable grid, the offset to that is that there was a cost of avoided load shed. What is the value of that?” he asked. “Basically, ancillary services are paying for the avoidance of load shed. I think you’d bet that reliability is important and that ought to be the goal of any grid operator.”
“Of course, absolutely,” Bivens responded. She said ancillary services are “very specific capacity products,” not general capacity products to meet a reliability standard.
“They’re very specific to follow the load and to ensure that the frequency is followed or, if a unit trips, to be able to replace those megawatts, but you still have reliability,” she said. “What I’m trying to point out is that they have very specific uses and, as specific uses, can be studied and analyzed to determine how many do you need to meet them.”
“The cost they’re offsetting is avoided load shed,” Flores said. “We need to look at the value of that. Somewhere, that’s got to be baked into this analysis … because load shed has a cost to consumers, the economy, to people, to physical health and so forth.”
“We should absolutely procure enough to have a reliable grid,” Bivens said. “We should have the right services to meet the specific attributes that the grid needs. But we should not buy more than that. More megawatts is just more cost. It’s not actually buying you any additional reliability. I think we would have been just as reliable this summer without these excess ECRS megawatts.”
The Public Utility Commission has a request for proposals out for the next four-year contract for a market monitor. Responses are due Oct. 30, with the new contract beginning Jan. 1. (See ERCOT Monitor’s Name Change Raises Legislative Concerns.)
1-Hour SOC for ESRs
The board approved a nodal protocol revision request (NPRR1186) that sets the minimum state of charge (SOC) for energy storage resources participating in two of ERCOT’s ancillary services (ECRS and non-spinning reserve), a move one energy storage developer said will have a “chilling effect” on attracting longer-duration batteries.
As modified by ERCOT and endorsed by the Technical Advisory Committee last month, the protocol change will reduce the requirement for storage resources to maintain a two-hour SOC down to one hour. The NPRR was remanded back to TAC by the board during its August meeting for further discussion and to address a “stranded energy” issue during scarcity conditions. (See ERCOT Technical Advisory Committee Briefs: Sept. 26, 2023.)
Storage developer Eolian, speaking for its segment, has opposed the measure throughout the stakeholder process. It says ESRs’ fast-ramping capability can be crucial during scarcity events and give other resources additional time to come online.
Ironically, ESRs produced a record 2.17 GW on Sept. 6, when ERCOT, faced with constrained renewable energy in South Texas, declared a Level 2 energy emergency alert after voltage dropped. (See ERCOT Voltage Drop Leads to EEA Level 2.)
ERCOT began the summer with more than 3 GW of energy storage and expects that total to hit 9.5 GW next year.
During a discussion before the board’s Reliability and Markets (R&M) Committee on Oct. 16, the ISO said it needs to know that a resource with an ancillary service obligation is available during the times it has bid into being available. The R&M unanimously approved NPRR1186.
“We came up with a better product,” committee chair Bob Flexon told the board. “We really did air it all out yesterday. I feel that all parties had ample time to express their thoughts and considerations.”
The board will direct staff to file priority NPRRs to handle compliance issues and financial penalties for nonperformance. The changes may be sent directly to TAC.
The board also approved two other revision changes:
NPRR1184, which clarifies ERCOT’s management of the interest it receives and is owed to counterparties for posted cash collateral and requires staff to credit counterparty collateral accounts for interest every month. The NPRR also requires ERCOT to report the interest calculation.
A system change request (SCR824) that increases the attachment file size and quantities allowed within the resource integration and ongoing operations system.
F&A Proposes Revised Budget
Flores, who chairs the board’s Finance and Audit Committee, said a review of ERCOT’s financial performance indicates the organization’s improved financials need to be considered when the PUC takes up the grid operator’s 2024-25 budget next month.
ERCOT has proposed a budget, approved by the board in June, that increases its system administration fee 27.9%, from $0.555/MWh to $0.710/MWh. The budget drew several questions from the PUC during an Oct. 13 public hearing. The commission will take up the budget a final time during its Nov. 2 open meeting. (See ERCOT Defends Admin Fee Increase Before PUC.)
Flores said interest income is expected to be about $27 million higher than initial forecasts and that this summer’s administration fee revenues were up about $6 million because of the additional load. Expenses that are down $4 million have given ERCOT about $36 million more available for 2025 than originally projected, he said.
“Those additional resources should be made available to reduce the impact of the cost of the system admin fee on the consumers of the state,” Flores said. “If you were to prepare the budget today and present that to the PUC, you could possibly come up with a system admin fee somewhere less than the 71 cents that we originally proposed.”
The F&A Committee, following Flores’ lead, has asked ERCOT staff to submit a revised rate calculation to the commission.
PUC Holds Weatherization Workshop
ERCOT staff and stakeholders updated the PUC on Friday during a public hearing reviewing winter weather preparedness, grid reliability and resiliency, and industry compliance with weatherization standards ahead of the 2023-24 winter season.
The grid operator said weatherization inspections are ahead of schedule in meeting PUC rules. Power plants are required to winterize their equipment against extreme cold and identify critical components susceptible to cold weather.
ERCOT also briefed the commission on its new firm fuel supply service, which ensures generators have backup fuel available on site, and demand response programs in the ERCOT region.
“Today’s work session was a great opportunity for us and the public to review the many steps Texas has taken to prepare for extreme cold weather,” Commissioner Will McAdams said.
The grid operator does not expect emergency conditions this winter but has issued an RFP for 3 GW of additional capacity to increase its operating reserves. Resources have until Nov. 6 to respond to the RFP; awards for three-month contracts (December-February) will be announced Nov. 23. (See ERCOT Searching for 3 GW of Winter Capacity.)
FERC agreed today to extend the compliance deadline for its interconnection queue rulemaking by four months to April 3, 2024, in response to requests from RTOs and utilities (RM22-14).
FERC Order 2023, issued in July, revised the pro forma generator interconnection queue rules to shift from a first-come, first-served serial process to a first-ready, first-served cluster study process, an effort to unclog backlogged queues filled mostly with renewable projects and storage.
The order also increased financial requirements for developers and set penalties for transmission providers that fail to meet deadlines for completing interconnection studies. Interconnection studies also must consider grid-enhancing technologies (GETs). (See FERC Updates Interconnection Queue Process with Order 2023.)
American Electric Power, Dominion Energy, PacifiCorp, the Edison Electric Institute and PJM filed requests for rehearing or clarification of the order, which the commission effectively denied when it failed to respond within 30 days.
The commission responded only to the extension requests, saying it would address the other issues raised on rehearing in a future order.
FERC initially set the compliance date for 90 calendar days after the rule’s Sept. 6 publication in the Federal Register, or Dec. 5. The new order extends the 90-day clock to 210 days for all transmission providers except for those with wholesale distribution access tariffs, which will have 90 days beginning when their RTO or ISO submits its compliance filing.
The commission said its extension “does not change or modify any other determination or other deadlines established by Order No. 2023, including the deadline for eligibility for interconnection customers to opt to proceed with a transitional serial study (for those interconnection customers tendered a facilities study agreement) or transitional cluster study (for those interconnection customers assigned a queue position) or to withdraw their interconnection requests without penalty (i.e., 30 calendar days after the transmission provider submits its initial compliance filing).”
Washington’s Department of Agriculture is mulling a petition by the electric vehicle charging industry to eliminate a state requirement that EV chargers contain a credit card chip reader for payments.
The Electric Vehicle Charging Association (EVCA), Tesla and six charging station suppliers in July petitioned the agency to overturn the requirement laid out in 16-662 WAC, a set of EV supply equipment (EVSE) rules approved in December 2022 and scheduled to go into effect in January 2024.
The petitioners argued the rules were designed to align with California’s EVSE regulations, which at the time required charging stations be equipped to accept payment via a toll-free telephone number, a mobile payment system and a chip reader.
But, in July, California revised its rules to match the National Electric Vehicle Infrastructure program, a massive federal initiative to subsidize installation of charging stations along key U.S. travel corridors, which does not require inclusion of chip readers on chargers.
That would leave Washington as the only state with rules requiring chip readers.
“To put it simply, manufacturers will have to design an EV charging product just for operating in Washington.” the petition said. “This will add further complexity and costs to multistate EV [supply equipment] projects, such as those running across California, Oregon and Washington. For EV drivers in Washington, it will also result in different payment experiences, offerings, reliability and potentially costs to charge from that of surrounding states.”
In September, the Agriculture Department told the petitioners it would not require chip readers to be installed in new charging stations until the state reviews the issue.
Opposing the petition is environmental and consumer advocacy organization Northwest Energy Coalition (NWEC), which argues a policy change will discourage low-income residents from buying EVs. The vehicles already are beyond the reach of many lower-income families, the group noted, with manufacturers trying to reduce prices for certain models to be more affordable.
“We need to meet households where they are if we are to transition quickly and equitably” to EVs, NWEC spokesperson Matt Joyce told NetZero Insider in an email. “Removing this requirement will mean unbanked, underbanked and people without smartphones will have a more challenging charging experience. … If Washington is going to move to electric vehicles, everyone needs to be able to access electricity and how you pay should not be a barrier.”
Joyce said 30% of drivers with incomes below $50,000 do not have access to smartphones with contactless payment ability. He also noted that electricity ratepayers and taxpayers are subsidizing the construction of charging networks.
In an interview, Joyce said the charging industry wants to avoid adding chip readers to chargers because it is cheaper to build stations without the devices.
In an email to NetZero Insider, the EVCA noted that contactless credit and debit cards are widely used and are expanding rapidly in use. It also said charging stations usually have an automated toll-free phone number or a short message/messaging system that provides a customer with the option to initiate a vehicle charge session and to submit payments.
Utilities and their regulators shared their thoughts for a new report on the challenges and opportunities facing the industry as the clean energy transition places a growing reliance on distributed energy resources.
Itron published its 2023 Resourcefulness Insight Report on Oct. 25. The utility management technology company drew on the input of 250 U.S. utility executives and 10 state-level utility commissioners for the report.
“Powering the Energy Transition: Insights from Utilities and Commissioners on Creating the Future U.S. Grid” reports that 88% of the executives call the transition extremely or very important, and that seven of the commissioners say their state’s policies support the transition.
But only 45% of the utilities are actively addressing the transition. Nearly half — 49% — are still in the planning stages, and most of those are only in the early stages. The remaining handful have not yet begun to plan.
Itron CEO Tom Deitrich noted in his introduction the rapidly growing power demand of electric vehicles and electrified buildings and said grid capacity must expand just as dramatically and quickly while providing uninterrupted service from an increasingly intermittent generation portfolio.
“And while many likely see in the energy transition a burdensome challenge,” he wrote, “still others see what we see: an opportunity to build a more responsive and intelligent grid that serves communities better and more efficiently than ever before.”
The report looks from multiple angles at the many-dimensional challenge that is utility and grid planning in the 2020s: balancing supply, demand, finances, reliability, regulation, customer expectations and technology limitations to keep the lights on and save the planet in a sustainable and affordable manner.
The Itron report finds a wide range of technology being used to varying degrees by U.S. utilities. | Itron
The report also found that:
59% of cooperative-owned utilities rank the transition as extremely important, compared with 34% of those municipal-owned and 33% of investor-owned.
Utility executives split almost evenly when asked to identify the key driver behind the transition: 37% said public demand, 36% cost savings and 34% environmental concerns.
61% of utilities say their state’s policies support transition initiatives, and 20% say they hinder progress; policies are rated most supportive in the Midwest (70%) and least in the South (54%).
Utilities in the West are leading their counterparts elsewhere — 12% say they have fully implemented their transition plans, and 47% are currently doing so. The Northeast is second on both counts.
43% of utilities say their customers are a critical part of the solution — driving demand for renewable energy, DERs and energy-efficiency measures — and can significantly impact the success of the transition.
Top considerations in utilities’ decision-making process are reliability (76%), safety (70%) and sustainability; resilience (43%) and equitable access (42%) are at the bottom of the list.
Technical investments are interwoven and often difficult to pursue individually, but infrastructure upgrades/grid modernization tops the list of priorities at 48%, with developing renewable energy resources close behind at 47%; residential and commercial EV integration lag at 23% and 21%, respectively.
Utilities reported a tight range of technologies already adopted, including battery storage and advanced metering (37% each); solar arrays and residential EV charging (36% each); and various types of load monitoring or management (32 to 35%). Lagging were distributed/edge intelligence (20%) and bidirectional or net metering (16%).
Utility priorities for the next five years are load monitoring/voltage management (22%), solar arrays (22%), consumer pricing initiatives (21%), distribution automation (21%) and grid/battery storage (20%); bidirectional or net metering again bring up the rear, at just 6%.
Grid modernization is the top priority for U.S. utilities, the Itron report indicates. | Itron
All of this, the report concludes, makes the case for utilities drawing up a full to-do list — particularly the 32% of utilities that are only in the early stages of planning. It suggests that utilities take stock of the current state of affairs; lay the foundation for a customized transition; consider how the business will change; present a compelling case for making those changes; and seek out partners with expertise.
“This year’s report underscores the pivotal moment we’re at in shaping the future of the U.S. grid,” Itron Vice President Marina Donovan said in the official announcement of the report. “Utilities have a critical role to play in accelerating the energy transition, and stakeholder education is an important part of that effort. By educating consumers, policymakers and regulators about clean energy, conservation and energy management programs, utilities can help overcome these challenges.”
The long-awaited results from a key study on the financial impact of an organized day-ahead electricity market in the West indicate that many entities outside California would see more benefits from a two-market outcome while the Golden State has the most to lose from such a split.
And while some industry stakeholders in the Northwest had speculated that the Bonneville Power Administration would be among the losers in a single-market solution, the findings — adjusted by BPA itself — paint a more complicated picture in which the federal agency could be either winner or loser in either scenario.
BPA discussed the findings during an Oct. 23 workshop, one of a series of stakeholder meetings related to its decision whether to join a day-ahead market.
The study was conducted by Energy+Environmental Economics (E3) on behalf of the Western Markets Exploratory Group (WMEG), a loose coalition of 26 transmission-owning entities covering most the Western Interconnection. The WMEG was established in 2021 to evaluate the region’s electricity market options, and its membership quickly expanded alongside broader discussions about the issue.
The WMEG asked E3 to limit the scope of the study’s cost-benefit analysis to variable production costs and energy market prices, while not considering potential investment savings that could be realized from lower capacity needs due to resource and load diversity, the ability to procure resources over a wider geographic area and coordinated regional transmission planning.
“Other market studies have shown those other benefit categories can create 2-10x the impact of production cost savings alone,” E3 noted in a presentation at the workshop.
“We think of our results as being quite conservative and intentionally so,” E3 senior partner Arne Olson said.
The study was structured to show a comprehensive picture of potential benefits for the West as a whole, while also breaking down results for individual utilities. While results were provided to WMEG study participants early this summer, they were not released publicly due to concerns about confidential information related to individual utilities. The BPA workshop offered a wider set of stakeholders and the public their first look into the analysis.
The study’s results are important because they likely will influence the choices of Western utilities weighing whether to join CAISO’s Extended Day-Ahead Market (EDAM) or SPP’s Markets+, decisions that likely will set the course for whether the West ends up with a single RTO in the future or two — or more — organized markets divided by seams.
“Today’s conversations represent just one element of the business case that Bonneville will use in helping arrive at a leaning [toward a market] in 2024,” Andy Meyers, BPA public utility specialist, said during the workshop. “And just to reemphasize something that we’ve shared before but want to make clear: We have not made any proposals about a leaning for 2024 at this point.”
EDAM Bookend vs. Main Split Footprint
In presenting the findings, E3 noted that the study was designed to provide WMEG members with “credible information” about the benefits of joining either EDAM or Markets+.
The results focused on three core scenarios for 2026:
A business-as-usual (BAU) case assuming continuation of the West’s current bilateral market for day-ahead energy combined with the existing footprint of CAISO’s Western Energy Imbalance Market (WEIM) for real-time trading. The BAU assumes no entities join either day-ahead market, E3’s Jack Moore said during the workshop.
An “EDAM Bookend” case that assumes a single combined day-ahead and real-time market that covers the entire Western Interconnection, excluding the Canadian provinces of British Columbia and Alberta. This scenario assumed no charges for wheeling power within the system, Moore said.
A “Main Split Footprint” that assumes participation in the EDAM by CAISO, PacifiCorp, Los Angeles Department of Water and Power, Balancing Authority of Northern California, Turlock Irrigation District and Imperial Irrigation District, while the rest of the West (excluding Alberta) participates in Markets+. This scenario assumed charges at the seams between the two markets, Moore said, noting that it was difficult to know what would be required to coordinate between the two, given that they wouldn’t be full RTOs.
Compared with the BAU case, the study found, the EDAM Bookend scenario results in $60 million in annual savings for the West as whole. But in breaking the results down by balancing authority area, the study indicates that California entities would realize $80 million in savings in that scenario, while WMEG members outside California would see a $20 million loss compared with the status quo. And results even vary among those WMEG members, Moore noted, with some realizing net benefits while others suffer losses at varying levels. Exact results for individual utilities must remain confidential, he added.
The cost-benefit outcomes get flipped in the Main Split Footprint case. In the scenario with two markets, West-wide costs increase by $221 million compared with BAU, with California entities taking a $247 million hit. Most of those increased costs stem from California’s need to fire up relatively expensive internal natural-gas-fired generation to substitute for cheaper imports, Moore said.
However, the Main Split market scenario showed $26 million in savings for WMEG members in general, although some members would face losses compared with the BAU case.
“The trade-off has different effects for different entities,” Moore said.
E3 said the results indicate the importance of “critical” transmission lines between the Northwest and Southwest in the Main Split case, where transactions would depend heavily on paths in Idaho, Nevada and Montana to avoid wheeling through the EDAM.
“Northwest to Southwest becomes a pretty significant pinch point” in the Split scenario, Moore said. Olson added that the transmission constraints in that scenario also could depress energy prices in the Northwest and reduce the value of the region’s flexible resources.
BPA Findings
Presenters at the workshop saved the most anticipated findings — BPA’s results — for last.
The study’s initial findings showed BPA seeing financial losses relative to BAU in both the EDAM Bookend and Main Split scenarios, largely because of a sharp decline in transmission wheeling charge revenues within its territory under either market. E3 assumed that a more robust market would undercut the need for customers to secure wheeling contracts from BPA, reducing those revenues from $251 million in the 2026 BAU case to $5.5 million in EDAM and $31.8 million in Main Split.
But BPA Director of Market Initiatives Russ Mantifel said the agency drew a different conclusion about the impact of day-ahead market participation on those charges. Most wheeling revenues are derived from long-term contracts, the agency found, and counterparties are likely to maintain those agreements for the foreseeable future.
By restoring wheeling revenues to expected 2026 levels, BPA and E3 estimated the agency’s annual net benefits would rise to $134.7 million in the EDAM Bookend scenario and $28.8 million in the Main Split scenario.
“I think the wheeling revenue numbers in the study do a good job of articulating something that we as a region and that Bonneville has intuitively known, which is, for Bonneville, there’s probably some amount of transmission that for us, is probably long-term, firm point-to-point transmission that’s purchased and rolled over and over and over again,” Mantifel said.
But it was clear the recalibrated study results showing how BPA could benefit from both day-ahead market scenarios were not a clincher for either market.
“There’s no study that tells you exactly what you’re supposed to do,” Mantifel said. “These are big decisions with a lot of different complicated factors, and so Bonneville is going to try to utilize all this information, but we’re going to be based in the sort of decision framework” the agency has previously laid out for choosing which market to join.
Twenty-five renewable energy projects totaling 6.4 GW have been selected for development in New York, including three new offshore wind farms with a combined 4 GW of capacity.
The projects chosen for the conditional contract awards Tuesday now enter the negotiation process. If they all are successful, they are expected to create 8,300 jobs and spur $20 billion in economic development.
Gov. Kathy Hochul called it the largest-ever renewable energy investment by a state.
N.Y. Gov. Kathy Hochul | New York Governor’s Office
“Today, we are taking action to keep New York’s climate goals within reach, demonstrating to the nation how to recalibrate in the wake of global economic challenges while driving us toward a greener and more prosperous future for generations to come,” she said.
The onshore projects are a mix of technologies totaling 2,410 MW of capacity: 14 new solar farms, one with co-located storage; six repowered wind farms; one new wind farm; and one return-to-service hydro project. The largest is a 401.6-MW solar farm in central Pennsylvania that will feed into the New York grid.
The offshore component is:
Attentive Energy One — 1,404 MW developed by TotalEnergies, Rise Light & Power and Corio Generation;
Community Offshore Wind — 1,314 MW developed by RWE Offshore Renewables and National Grid Ventures; and
Excelsior Wind — 1,314 MW developed by Vineyard Offshore (Copenhagen Infrastructure Partners).
Just 12 days earlier, the state Public Service Commission rejected inflation-related cost adjustments for developers of 90 contracted projects that had said they might not be able to begin construction without more money.
These total more than 12 GW and constitute a large percentage of New York’s vaunted renewable energy pipeline — including almost the entire offshore wind pipeline, which is particularly hard hit by cost increases and supply constraints.
One of New York’s five planned offshore wind farms, the 132-MW South Fork, is under construction and may become the nation’s first utility-scale offshore wind project to generate power.
Developers of the other four planned facilities, totaling 4,230 MW, may need to cancel their contracts and attempt to rebid in future solicitations.
The New York State Energy Research and Development Authority said the strike price for the three offshore wind projects announced Tuesday could vary depending on price indices, federal incentives and other factors. But it is expected to be $96.72/MWh in 2023 dollars as a weighted average and $145.07 as a nominal weighted average over the 25-year contract terms.
This would yield an average charge of $2.93/month for New York electric ratepayers over that period, NYSERDA said. And it is less than the increase developers of the four contracted offshore wind projects had been seeking. In its comments to the PSC on the requests, NYSERDA said they would have resulted in a weighted average of $167.25/MWh for the four contracted projects.
A couple of hours after the PSC rejected the requests Oct. 12, Hochul announced a new 10-point plan to “Expand a Thriving Large-Scale Renewable Industry.” Given recent events, “thriving” might be a stretch, and most of the 10 points were policies and initiatives already in place.
However, the first of the 10 points promised an announcement on contract awards, and she followed through 12 days later — acknowledging the setbacks in passing but focusing on the promise of the next chapter.
Economic Goals
Hochul announced the tentative contracts in an IBEW Local 3 training facility where some of the young people who will build the state’s clean energy infrastructure are learning their trades.
New York’s statutory goals include an energy portfolio that is 70% renewable by 2030 and 100% zero emissions by 2040. It is struggling to stay on schedule and simultaneously using the energy transition as a vehicle for social justice and economic development — particularly in offshore wind, a new industry in which it hopes to become a leader.
The domestic supply chain stands to gain two significant new components in New York with the three offshore wind projects chosen for contracts: a nacelle factory and a blade factory operated by General Electric and subsidiary LM Wind Power USA, respectively. Plans for both were announced this year but were conditioned on the companies securing enough orders to warrant construction.
Hochul announced $300 million in state funding to build the facilities, which she said would attract $668 million in private financing.
National Climate Adviser Ali Zaidi joined Hochul for the event, which he called an investment in the neglected middle class as much as in the environment.
White House Climate Adviser Ali Zaidi | New York Governor’s Office
And that is not just in New York, he said: Already, more than 4,000 contracts have been signed in 47 states to supply the nascent U.S. offshore wind industry.
It is, Zaidi said, “an economy that is being built not just to put steel in the ground — or, in the offshore industry, steel in the water — but really steel in the spine of the American middle class.”
All of the projects chosen in New York’s latest round of awards will be eligible for tax credits of up to 50%, he added — if they use domestic components, train apprentices, create jobs in disadvantaged communities and pay prevailing wages.
The Alliance for Clean Energy New York, a trade group that represents the developers chosen for contracts, said the projects would have the economic and environmental benefits the state is trying to achieve.
Fred Zalcman, director of the New York Offshore Wind Alliance, called the contract awards a good change of direction from recent news. “Today’s announcement, awarding three contracts for more than 4,000 MW of offshore wind generation, shows that New York is prepared to double down on this clean, renewable and job-creating resource, and will go a long way towards instilling confidence in a market that has recently faced tremendous headwinds,” he said. “We look forward to working with the governor and other stakeholders in getting these early-stage projects to the finish line.”
Truck manufacturers have been racking up zero-emission vehicle credits in advance of California’s Advanced Clean Trucks (ACT) rule taking effect with model year 2024, a new report shows.
About 7,900 zero-emission trucks from model years 2021 and 2022 have been sold in California, according to a report from the California Air Resources Board (CARB). Another 1,000 ZEV trucks are expected to be sold from those model years based on participation in the Hybrid and Zero-Emission Truck and Bus Voucher Incentive Project.
The combined total is about 60% more than the 5,500 zero-emission trucks that CARB expects manufacturers to need to meet the model year 2024 quota. And that doesn’t include zero-emission truck sales from model year 2023.
“Helping the businesses that rely on trucks to transport goods across the state switch to zero emissions is key to achieving a clean air future, and the data show that progress is well underway,” CARB Executive Officer Steven Cliff said in a statement.
Cliff said the figures indicate trucking businesses are interested in zero-emission vehicles, and manufacturers are stepping up to meet the demand.
Rivian led the way in model year 2022, with 5,286 zero-emission trucks sold in California. Ford followed with 1,686 ZEV trucks sold — out of a total of 28,606 medium- and heavy-duty vehicles delivered for sale in the state.
GM delivered 24,500 trucks for sale in model year 2022, but none of them were zero-emission, according to CARB.
In the Class 7-8 tractor category, Volvo sold 64 zero-emission vehicles from model year 2022. Paccar sold 16, followed by Daimler and Nikola Motor, with 13 each.
For model year 2022, 104,558 medium- and heavy-duty trucks were delivered for sale in California, including 7,639 zero-emission trucks, or 7.3%.
Advanced Clean Trucks, which CARB adopted in 2020, requires truck manufacturers to sell an increasing percentage of zero-emission vehicles in California starting in 2024.
The sales requirement varies based on the weight class of the truck. For model year 2024, ZEVs must account for 5% of Class 2b-3 trucks; 9% of Class 4-8 trucks; and 5% of Class 7-8 tractors. CARB said that on average, about 6% of trucks sold will need to be ZEVs in model year 2024.
Truck manufacturers may earn early credits for ZEV sales in model years 2021 through 2023, to be banked for use in later years or sold to other truck makers. The early credits are good through the 2030 model year.
Truck manufacturers that sell 500 or fewer vehicles a year in California are exempt from ACT but may opt to generate ZEV sales credits that can be banked or transferred.
Zero-emission truck sales generate credits that increase with the weight class of the vehicle. For model years 2022, truck manufacturers earned 6,414.7 credits, bringing the total for 2021 and 2022 to 7072.6 credits.
The manufacturers agreed to meet California’s vehicle standards even if they’re challenged in court.
Under the Clean Truck Partnership agreement, truck manufacturers committed to selling as many zero-emission trucks as reasonably possible in California and other states that have adopted ACT.
The agreement came after a coalition of 19 states petitioned a federal appellate court in June to review EPA’s approval of Advanced Clean Trucks. Last month, a briefing schedule was filed in the case, with final briefs due in April.
