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November 5, 2024

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Audit Faults NY on Climate Act Progress

A new audit by the state fiscal watchdog faults New York’s slow progress toward its climate protection goals and warns that the full cost of the effort still has not been quantified, five years after the goals were signed into law.

State Comptroller Thomas DiNapoli said July 17 the audit by his staff found New York was moving in the right direction but better planning, monitoring and risk assessment are needed.

The audit finds fault with the state Public Service Commission (PSC), which with its staff in the Department of Public Service (DPS) draws up regulations for pursuing the climate goals. To a lesser extent, it finds fault with the New York State Energy Research and Development Authority (NYSERDA), which awards the development contracts that will help achieve the climate goals.

In their rebuttals, the PSC and NYSERDA stand by their efforts. The PSC said the audit discounts much of the work done and overlooks some of the factors that have limited progress. NYSERDA thanked the Office of State Comptroller (OSC) for its detailed analysis and said it has taken steps to address some of the feedback, but it pushed back on other criticisms.

The audit began in early 2022 and encompasses a period when the state’s pipeline of contracted clean energy projects swelled impressively amid strong policy support then collapsed amid strong industrywide headwinds.

The Department of Public Service and NYSERDA predicted in a draft review issued July 1 that the state will fall short, perhaps far short of its first major target: 70% renewable energy by 2030. (See NY Expects to Miss 2030 Renewable Energy Target.)

In announcing the audit, DiNapoli said: “New York has been a leader in its efforts to reduce greenhouse gas emissions and the threats caused by climate change, and identifying existing and emerging challenges will improve the likelihood that we succeed.”

CLCPA Turns 5

Then-Gov. Andrew Cuomo (D) signed the state’s landmark Climate Leadership and Community Protection Act (CLCPA) into law on July 18, 2019, surrounded by supporters of the measure.

Many blue states tout their climate protection and decarbonization efforts, and some even claim to be nation leading. New York’s effort legitimately could be called one of the strongest in the nation at the time — former Vice President Al Gore, who shared the 2007 Nobel Peace Prize for his efforts to protect the planet, joined Cuomo for the signing ceremony.

But New York also would sit near the top of any list of states where renewable energy projects are slow and expensive to complete.

It took more than three years just to produce a scoping plan for the CLCPA. Meanwhile, the clock was ticking on the CLCPA’s legal mandates of 70% renewable energy by 2030, 100% emissions-free power by 2040 and greenhouse gas emissions at least 85% lower than 1990 levels by 2050.

While New York was planning, drafting and reviewing, the world moved ahead. A global pandemic and a European war drove up costs, rendering untenable dozens of contracts for 11 GW of renewable energy projects.

For the past nine months, New York has been scrambling to regain its lost momentum. It has had partial successes, at a cost in time and money.

Findings, Recommendations

The audit highlights several findings:

    • PSC is using outdated data and at times incorrect calculations for planning purposes.
    • PSC has not started to address all existing and emerging issues that could increase demand for electricity and lower supply.
    • PSC has taken steps to address some risks and issues but has not begun to formally review progress toward CLCPA goals, raising the risk that the CLCPA’s goals will be missed.

New York has not quantified the cost of transitioning to renewable energy, nor provided a reasonable estimate, nor specified a source of funding. This leaves the cost to utility ratepayers who already have faced sharp rate increases over the past two decades and in many cases already are having trouble paying their bills.

The audit highlights several recommendations:

    • Begin the required comprehensive review of the CLCPA, including assessment of progress toward the goals, distribution of systems by load and size and annual funding commitments and expenditures.
    • Continuously analyze risks to minimize impact on ability to meet CLCPA goals.
    • Analyze the expected cost of the clean energy transition and of meeting CLCPA goals, then update that analysis periodically and report the results to the public.
    • Determine how much of this cost ratepayers reasonably can be expected to cover and look for alternative sources of funding.

PSC Response

As is customary, the OSC audit included the response of the audited agencies. The comments by PSC Chair Rory Christian and the counter comments by the auditors added 25 pages to the 29-page audit.

PSC also sent a prepared statement to NetZero Insider:

“DPS is pleased to note that OSC found that the PSC and NYSERDA have taken considerable steps to transition to renewable energy in compliance with the Climate Leadership and Community Protection Act (CLCPA) and Clean Energy Standard (CES), but is disappointed that OSC overlooks several significant steps taken and factors that have impacted progress to date.

“Indeed, in the five years since the CLCPA was enacted, the PSC modified the existing CES to comply with the law, directed NYSERDA to continue undertaking solicitations for new renewable projects in the face of unprecedented and evolving market conditions outside of New York’s control, approved $5 billion in transmission investments to support renewable projects, worked with federal, State and local governments on renewable energy initiatives that have reduced the ratepayer costs of complying with CLCPA (potentially saving ratepayers billions of dollars), partnered with the Legislature to streamline the siting laws for renewables and transmission projects, advanced critical planning proceedings to ensure the energy transition is done in a safe and reliable manner, and expanded utility affordability initiatives.

“Much of this work appears to have been discounted in the OSC report, and the Department’s response highlights several instances where it disagrees with OSC’s findings.”

NYSERDA Response

The audit’s criticism of NYSERDA was narrower, focusing on some of the methodology it used for evaluating bids and awarding contracts. NYSERDA President Doreen Harris’ response to the audit was proportionately narrow, at just four pages.

In an interview, she said:

“The comptroller found us to be in full compliance with the Public Service Commission orders. And ultimately, the recommendations within the audit are almost exclusively already being incorporated within our record keeping and the implementation of our solicitations.”

Harris said goals such as 70% renewables by 2030 are more than aspirational or inspirational; they establish a market size to attract the considerable private sector investment and consumer support that is needed for CLCPA to succeed.

The idea is that a maturation of technologies and markets needs to happen for CLCPA’s goals to be achieved, and the existence of those goals helps these markets and technologies mature.

Harris sees this happening already in registrations for battery electric vehicles, heat pump sales and the installed capacity of community solar in New York.

“Change happens in ways that reach inflection points, inflection points where the market reaches a level of maturity and uptake that it essentially takes off,” she said. “When I look at the data, not even in the super long term but literally over the last couple of years, [it shows] we have reached those inflection points [with] many technologies that are necessary to not only make progress toward these goals, but also be well on our way toward achieving them.”

Despite all the cost escalations and contract cancellations seen in the past year, progress is being made in New York, even if there is less than had been anticipated.

Harris spoke to NetZero Insider on July 17 after helping lead a ceremonial groundbreaking for Sunrise Wind, an offshore wind project that will be among the largest capacity additions to the state’s grid in decades — 924 MW — if it is completed as planned. Its initial contract was among the dozens canceled statewide in 2023 and 2024, but it was brought back into the portfolio in June. (See Empire, Sunrise Wind Back Under Contract in NY.)

More Money

But what of the cost concerns the audit raises?

In July 2023, the PSC commissioners heard the first annual report from DPS staff on efforts to implement the CLCPA. A conservative estimate was offered of money already spent or authorized to meet CLCPA goals: $43.76 billion.

But there was no estimate of how much more would be needed, which took some commissioners aback. (See Energy Transition Costs Give NY Utility Commissioners Pause.)

A year later, Harris did not offer any cost estimate. She pointed instead to the Scoping Plan, an extensively detailed publication stretching 445 pages where cost estimates are buried within calculations — the benefits to society of decarbonizing will be $400 billion to $415 billion greater than the cost, for example.

These figures were derived before the massive cost increases of 2023. And they include assumptions such as $1.9 billion in savings over a 30-year period from decreased frequency of trip-and-fall accidents in low- and moderate-income households.

The auditors are not the first observers frustrated in their quest for a clearly stated price tag.

The unknown costs of implementing the CLCPA became a frequent talking point for John Howard in his recently concluded five-year tenure on the PSC, which neatly overlapped the first five years of the CLCPA’s existence.

“My own personal back-of-the-envelope thinking is about a half a trillion,” he told NetZero Insider, but that is only an estimate, one he had to produce because no one had a hard number for him.

The audit was correct in flagging the risks of not stating the full cost, Howard said.

“Oh, yeah — I mean, they are self-evident. On the issue of cost transparency, look, you’re a reporter. We have several good reporters trying to get these numbers. They just don’t want to be released. They can be known. They can be estimates. But the sticker shock will scare people away, so it doesn’t happen.”

He continued: “The hard numbers are an illusion because you can’t find them. If the Office of State Comptroller can’t find the numbers, well, then who’s gonna find the numbers?”

Howard said the integration analysis used to calculate the negative net cost of implementing the CLCPA is the wrong pitch for New Yorkers.

The costs are being revealed piecemeal, but they are broad and immediate: Utility bills going up 2% for a particular wind farm or 3% for a particular transmission project, for example. The benefits, meanwhile, will be realized unevenly over decades through hard-to-quantify metrics such as reduced asthma symptoms or fewer cases of carbon monoxide poisoning.

“It’s easy to say ‘yeah, we can afford it’ when you don’t tell anybody what it’s gonna cost ya,” said Howard, adding that he does believe climate change is real and needs to be addressed.

“Do it as transparently as possible, because if you’re asking New Yorkers to pay this giant new vig, you need to get them to say yes. By not telling them, it’s the worst thing you could do.”

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California Reaches Funding Agreement to Launch Hydrogen Hub

California became the first state in the U.S. to launch a hydrogen hub with the announcement of a funding agreement with the Department of Energy on July 17. 

DOE’s Office of Clean Energy Demonstrations awarded $30 million to the California hydrogen hub, in what OCED described as a first installment in what could be as much as $1.2 billion in federal funding. 

The federal money will be matched with $11.4 billion in public and private funds, for a total of up to $12.6 billion, under an agreement between DOE and the Alliance for Renewable Clean Hydrogen Energy Systems. ARCHES is a public-private partnership that’s leading the California hydrogen hub. 

The California hub is one of seven regional hydrogen hubs across the nation that DOE designated in October 2023 for potential funding. ARCHES is the first of the seven to sign an official agreement with DOE. 

“California is leading the nation with the first hydrogen hub to sign a cooperative agreement, and we will continue to lead by decarbonizing goods movement, the energy sector and heavy industry,” U.S. Sen. Alex Padilla (D-Calif.) said in a statement.

The federal funding is from the Bipartisan Infrastructure Law, which is providing up to $7 billion for regional hydrogen hubs throughout the U.S. 

Ports and Transportation

The California hydrogen hub will focus on decarbonizing seaport operations, heavy-duty trucking and public transportation. 

The goal is to cut carbon emissions by about 2 million metric tons per year, roughly equivalent to the emissions of 445,000 gasoline-powered cars. 

“We’re going to use clean, renewable hydrogen to power our ports and public transportation — getting people and goods where they need to go, just without the local air pollution,” Gov. Gavin Newsom (D) said in a statement. 

The plan includes decarbonizing cargo-handling equipment at the ports of Oakland, Los Angeles and Long Beach.  

It aims for more than 5,000 fuel-cell electric trucks and 1,000 fuel-cell electric buses, to be supported by more than 60 hydrogen fueling stations. ARCHES said this may lead to an expanded clean freight network on the West Coast that is linked to the Pacific Northwest Hydrogen Hub. 

As part of the hydrogen hub, the Los Angeles Department of Water and Power and Northern California Power Agency will convert certain power plants to 100% renewable hydrogen. 

The plan even includes a marine vessel. A hydrogen-hybrid research vessel is being designed for the Scripps Institution of Oceanography at the University of California-San Diego. 

Clean, renewable hydrogen produced at more than 10 sites will fuel the projects and prompt the growth of a greater hydrogen ecosystem, according to ARCHES. 

The project also aims to make clean hydrogen in California cheaper than diesel and other traditional fuels by 2030. 

ARCHES said it will announce more projects soon. 

The first tranche of funding will allow ARCHES to begin Phase 1 of the project, which involves planning, analysis and work with communities and stakeholders. Phase 1 is estimated to take 18 months. 

Seven Hubs Selected

DOE’s hydrogen hub selection process started with an initial group of 79 preliminary applications filed by a November 2022 deadline. From that group, DOE encouraged 33 to advance to the next stage by submitting full applications. 

DOE announced in October 2023 its designation of seven hydrogen hubs to potentially receive funding. (See DOE Designates Seven Regional Hydrogen Hubs.) 

The seven hubs are: 

    • California Hydrogen Hub (California) 
    • Appalachian Hydrogen Hub (West Virginia, Ohio, Pennsylvania) 
    • Gulf Coast Hydrogen Hub (Texas) 
    • Heartland Hydrogen Hub (Minnesota, North Dakota, South Dakota) 
    • Mid-Atlantic Hydrogen Hub (Pennsylvania, Delaware, New Jersey) 
    • Midwest Hydrogen Hub (Illinois, Indiana, Michigan) 
    • Pacific Northwest Hydrogen Hub (Washington, Oregon, Montana) 

DOE noted at the time that its selection of the hubs was not a promise to provide funding, which is subject to a negotiation process. 

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WEIM Governing Body Officially Changes Name

The CAISO Board of Governors and Western Energy Imbalance Market (WEIM) Governing Body voted July 17 to officially change the name of the latter organization to the Western Energy Markets Governing Body to better reflect its full scope of responsibility since it began overseeing the ISO’s Extended Day-Ahead Market (EDAM) in March. 

“The name simplification represents a huge step in expansion of Western electricity markets,” body member John Prescott said during the joint meeting with the board. 

Other members echoed the support.  

“We’ve looked at the growth [of the WEIM] over 10 years, and it’s nothing short of phenomenal,” body member Robert Kondziolka said. “It’s now clearly made participants much more comfortable and be able to move forward into a day-ahead market and to be able to broaden this out, and so I think the name change is very positive.” 

The motion was directly approved by both entities. A vote by the board to amend CAISO’s corporate bylaws, which also was required to change the name, passed unanimously. 

The name will be reflected “as soon as practicable” in governing documents, according to a memo outlining the decision. 

“Someone should be able to look at our name and say, ‘We understand what you’re responsible for and who you are,’ and I think this name change actually exemplifies what we’re responsible for and what we’re doing,” body member Anita Decker said. “I really support this change and appreciate the work that staff did to bring some iterations to us and land here.” 

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Report: Companies Say Fusion will be Online by 2035

About 45 companies worldwide are in the race to develop commercially viable nuclear fusion technology, and according to a new report from the Fusion Industry Association (FIA), almost half of them say they expect to deliver power to the grid somewhere between 2031 and 2035.

While existing reactors produce energy by breaking atoms apart, fusion promises even larger amounts of energy by superheating and fusing hydrogen or other light elements. But the technology is still years away from any kind of commercial scale.

However, the FIA report, released July 17, presents a confident image of a “maturing industry” that attracted $900 million in new private investment in the past year and grew public investment from $271 million to $426 million. An extensive list of investors includes both Microsoft founder Bill Gates and his Breakthrough Energy Ventures, Chevron Technology Ventures, Mitsubishi UFJ Capital and the German Federal Agency for Disruptive Innovation.

“In the face of continued challenges in raising capital for deep technology ventures, the additional funding underscores confidence in fusion technology’s potential to revolutionize the global energy landscape on a timescale that is relevant to investors,” FIA CEO Andrew Holland said in the report’s introduction.

He also pointed to public-private partnerships as a key driver for fusion development. In the U.S., the Department of Energy’s Milestone-based Fusion Development Program last year awarded a total of $46 million to eight companies to continue research and development of fusion technologies, while the governments of Germany, Japan and the U.K. also have launched public-private partnerships to develop fusion, the report says.

Jobs are another plus. Holland noted that the industry’s workforce now totals more than 4,100 people ― almost four times its 2021 headcount. Close to 75% of current employees are either engineers or scientists, but only 26% are women.

Holland explained those lopsided demographics in terms of “the intensive research and development efforts required to advance fusion technology,” which is also reflected in the report’s fragmented findings on the current state of research and development in the field.

About half the companies the FIA surveyed are pursuing some form of “magnetic confinement” ― in which magnets are used to manipulate the atoms, which are in the form of plasma ― but using different approaches. Stellarators (eight companies) and tokamaks (three companies) are both types of reactors that use magnetic confinement to produce fusion.

The other major branch of fusion research centers around “inertial confinement,” in which atoms are heated and compressed to trigger fusion. Two companies are pursuing a hybrid technology called magnetized target fusion, which combines both magnetized and inertial confinement.

Others are researching a range of technical variants: shock-driven inertial confinement, pulsed magneto-plasma pressurized confinement and short pulse laser-driven inertial confinement. In total, the report lists 24 different technological approaches.

Commercialization will likely require the development of standards and some consolidation around a few core technologies.

Getting to Break-even

Interest in fusion and small modular reactors is on the rise in the U.S. and worldwide as both carbon-intensive industries ― cement, steel and chemicals ― and power-hungry data centers look for new sources of clean, dispatchable power to help them reduce their greenhouse gas emissions.

The U.S. appears to be leading the world in fusion development, with 25 fusion companies now spread across the country, according to the FIA report. In June, DOE released its 2024 Fusion Energy Strategy, which focuses on closing technology gaps needed to build a pilot fusion plant and then laying out a path to commercial deployment, leveraging public-private partnerships.

Cited by 25 companies in the FIA report, the top gap that needs closing is fusion efficiency ― called “energy gain” ― which is the ratio of the power produced by a fusion reaction to the power needed to maintain the reaction in a steady state so it continues to produce energy. For commercial viability, the power produced by fusion has to significantly exceed the power needed to maintain the reaction.

In December 2022, the Lawrence Livermore National Laboratory was the first U.S. facility to pass that break-even point of a fusion reaction producing more power than was needed to maintain it.

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NY Kicks off 5th Offshore Wind Solicitation

New York Gov. Kathy Hochul on July 17 announced the opening of the state’s fifth offshore wind solicitation, a competitive effort to be overseen by the New York State Energy Research and Development Authority (NYSERDA).  

Proposals will be required to abide by state-mandated labor, “buy American” and environmental mitigation measures.  

“Today’s fifth offshore wind solicitation announcement is crucial to achieving New York’s clean energy goals,” Mario Cilento, president of the New York AFL-CIO, said in a press release. “We commend Governor Hochul for her commitment to ensuring that union members play a pivotal role in manufacturing, constructing, operating and maintaining New York’s clean energy future.”  

NYSERDA is seeking to procure Offshore Wind Renewable Energy Certificates as authorized under a series of orders from the state’s Public Service Commission (DPS) to support the goals of the Climate Leadership and Community Protection Act (CLCPA).  

The CLCPA requires the state to achieve 70% renewable energy by 2030 and install 9 GW of offshore wind by 2035. A report from NYSERDA and DPS anticipates that the state will miss the 2030 goal but suggests that catching up is possible by 2033. 

To be eligible for evaluation NYSERDA requires projects to be deliverable to New York City or Long Island and deliver a minimum offer capacity of 800 MW. NYSERDA will select no more than two projects delivering electricity via HVDC to New York City. The agency did not cap the number of projects that may deliver power to Long Island. 

The news came at the same time Gov. Hochul announced the start of construction for the 924-MW Sunrise Wind Project, approximately 30 miles east off the coast of Montauk, N.Y., on Long Island. Project developer Ørsted expects Sunrise will be completed in 2026 and that the project will support 800 jobs during construction.  

“We’re growing New York’s green economy, building clean energy and expanding economic opportunities for all New Yorkers,” Hochul wrote in a press release. “By breaking ground on Sunrise Wind and advancing the next wave of offshore wind projects, New York is passing a tremendous milestone to combat climate change. These projects will create good-paying union jobs and demonstrate that New York is leading the nation to build the offshore wind industry.” 

Applications are due by 3 p.m. ET Sept. 9. A webinar for interested parties will be held at 10 a.m. July 22. Registration is available here.  

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NYISO Proposes Changes to Special-case Resource Program

NYISO is proposing to increase the required duration of special-case resources’ load curtailment from four hours to six following a survey showing stakeholder support as part of the ISO’s Engaging the Demand Side initiative.

SCRs are demand-side resources connected to a load that is capable of being interrupted at NYISO’s direction, including on-site solar. These resources may also have a local generator that is behind the meter and rated at 100 kW or higher that can be used to reduce load. They are activated when operating reserves are forecasted to be short; when there are actual operating reserve deficiencies; or in case of another emergency to balance load and generation. SCRs from aggregate resources must be within the same zone.

Currently NYISO requires SCRs to curtail load for at least four consecutive hours. Increasing the requirement to six hours would “provide the opportunity for SCRs to earn additional revenue for load reduction and enhance NYISO grid operators’ ability to balance supply and demand,” Michael Ferrari, ISO market design specialist, told the ICAP Working Group on July 15.

“Multiple Intervenors supports this particular change, and that support is really driven by the vast chasm of compensation between four- and six-hour resources with respect to NYISO’s capacity accreditation initiative,” said Mike Mager, an attorney for Multiple Intervenors, a large energy customer organization. “I will note, however, that that’s not unanimous.”

Some stakeholders asked whether NYISO would consider creating SCR categories with different durations.

“It is certainly easiest to have a single class for SCR, where it is one duration, and resources can just be dispatched by zone,” Ferrari said. “It is certainly more burdensome for two different classes of SCRs. But given the feedback on the desire for more flexibility, it’s something I think we can consider.”

“I appreciate that a one-size-fits-all approach is easiest for you,” said Kevin Lang, of law firm Couch White. “I would just note that for your suppliers, you don’t have one-size-fits-all approaches.”

“It’s not so much that it’s burdensome,” explained Zach Smith, vice president of system and resource planning for NYISO. “It’s remembering that this is a manually activated program, which is very different from every other supplier.”

Ferrari told the working group that NYISO is also considering shortening the activation notice period for the SCR down from 21 hours. The final, shorter duration would still be roughly a day-ahead notice, but the final time has not been decided.

“On a preliminary basis, the feedback we’ve gotten from our members” is they prefer “a fixed-time approach sometime comfortably prior to the close of business the day before,” Mager said. “By 1 p.m. or 2 p.m., they would know whether the call was happening or not.”

One stakeholder reminded NYISO that certain engineers and professionals that manage building and industrial infrastructure would not be available after 3 p.m. because their days start much earlier than the traditional “start of business.”

NYISO is also proposing changing the method for determining SCRs’ baseline load values from average coincident load (ACL) to customer baseline load (CBL). Ferrari said that CBL would allow the ISO and market participants to more accurately look at the energy available to reduce load. Some stakeholders noted that this would be more difficult to calculate and potentially be confusing for operators.

“I would note that all of the changes being proposed have the effect of seemingly making performance more difficult or challenging for participants,” Mager said.

Others noted that the CBL was already being used in the installed reserve margin study to estimate the amount of relief from using an SCR.

NYISO plans to deploy these revisions to the SCR program in the 2026/27 capability year with possible phased implementation. Several stakeholders expressed disappointment that the six-hour duration could not be deployed sooner.

“We certainly understand the request and the desire and the disappointment that this cannot be made sooner,” Smith said. He explained that to implement the change for 2025/26, a software update would be needed by February. “We did not ask to have software development as part of the work for this year, and the two months that we have to deploy this is insufficient for even just” a change of two hours.

Smith said that NYISO would continue to evaluate whether that could be accelerated.

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NEPOOL Reliability Committee Briefs: July 16, 2024

New Data Collection Standards

The NEPOOL Reliability Committee (RC) voted July 16 to support new data collection standards for distributed energy resources (DERs), intended to aid the RTO in both real-time operations and longer-term planning studies.

While ISO-NE currently collects data using voluntary submissions, the new standards would require data submissions from distribution providers and transmission owners related to DER size, location and operating characteristics, said Dan Schwarting of ISO-NE.

“Uniformity in data submission will lead to better accuracy of load forecasting and studies at ISO-NE,” Schwarting said. The proposal now heads to the NEPOOL Participants Committee.

Affected System Operator Study Coordination

Brad Marszalkowski of ISO-NE outlined proposed tariff changes to coordinate affected system operator (ASO) studies with the new cluster study interconnection process, which was mandated by FERC Order 2023. (See Clean Energy Groups Respond to ISO-NE Order 2023 Filing.)

ASO studies are under the jurisdiction of the states and assess the impact of distributed generation projects on the transmission system and broader power grid. They are performed by the relevant transmission owner.

“ASO studies will have to coordinate with and respect ISO Cluster Studies,” Marszalkowski said. “This will naturally establish windows for the start and completion of ASO studies.”

Marszalkowski said the new ASO process would create a “state project submission window” that coincides with the ISO-NE cluster request window. ASO studies corresponding to each window would occur simultaneously with ISO-NE cluster studies. The studies would be required to account for ISO-NE interconnection requests and updated ISO-NE study information.

“ISO-NE will no longer consider one-at-a-time project additions,” Marszalkowski noted. “Determinations will be made solely based on the total aggregate of all projects submitted during the submission windows that are electrically close based on the screening criteria.”

Order 881 Changes

ISO-NE also discussed planning procedure changes associated with FERC Order 881, which requires transmission providers to adopt ambient adjusted line ratings for near-term transmission service requests and seasonal ratings for longer-term requests.

The commission accepted ISO-NE’s compliance proposal in 2023, subject to an additional filing by November 2024 to specify “timelines for calculating or submitting AARs.” The compliance will take effect in July 2025. (ER22-2357, see Order 881 Timelines Need Explaining, FERC Says.)

Michael Drzewianowski of ISO-NE said Order 881 compliance requires changes to the RTO’s Planning Procedure 7 (PP7), which “provides the general assumptions to be used in the calculation of facility ratings.”

For seasonal ratings, ISO-NE plans to use 12 seasons corresponding to each month, said Drzewianowski, outlining the ambient temperatures the RTO will use for each month under normal and emergency conditions.

To account for changing seasonal load shapes, ISO-NE plans to shift to a long-time emergency (LTE) rating period of four hours across the entire year, instead of the current LTE ratings of four hours in the winter and 12 hours in the summer.

Drzewianowski said ISO-NE will review stakeholder comments and changes to the PP7 appendices at the August RC meeting, targeting a vote in September.

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ISO-NE Planning Advisory Committee Briefs: July 17, 2024

Following its increase of the transfer limits on three interfaces in Maine, ISO-NE has increased the capacity import capability of the New Brunswick-New England (NB-NE) interface from 700 MW to 980 MW, Alex Rost of ISO-NE told its Planning Advisory Committee. 

ISO-NE announced the Maine transfer limit increases to the PAC in June. (See ISO-NE PAC Briefs: June 20, 2024.) The increases were the result of changes to how the RTO calculates the limits, which now are “based solely on ‘design contingencies’ — loss of transmission lines, transformers, etc.,” ISO-NE said. 

Capacity historically has been constrained in parts of Maine because of the interface transfer limits and existing capacity resources above the Maine interfaces, Rost said, adding that “the amount of capacity than can be transferred over the NB-NE interface has been limited to 700 MW out of a possible 1,000 MW for many years.” 

He noted that “proposed new capacity resources north of the Orrington-South interface have been unable to qualify for FCAs [forward capacity auctions] for many years,” and new resources have faced similar problems above the Surowiec-South interface since 2016. 

Responding to stakeholder questions, Rost said the import capability increase from New Brunswick likely means no new headroom will be made available for new capacity resources above these interfaces. 

“I’m not going to give official overlapping impact analysis answers today, … but if you walk through the analyses and steps that we went through and you crunch the numbers, that would indicate that there is no headroom,” Rost said.  

Abigail Krich of Boreas Renewables expressed concern that increasing the import capability from New Brunswick but not increasing the limits on domestic capacity could lead to the increased transfer capabilities being “reserved and underused.” 

When transfer limits are increased, “we reserve those for imports, instead of for domestic generation qualified to participate in the capacity market,” Krich said. “We reserve them for imports regardless of whether they actually get used for imports. We often see that the New Brunswick interface, historically, even at 700 MW, has not been fully subscribed. 

“This is something we should all be thinking about: How we can better utilize this transfer capability to ensure we’re getting the most out of it?” 

Rost also noted that ISO-NE likely will reassess the internal transfer limits once the New England Clean Energy Connect transmission line is in service to account for system upgrades associated with the line. 

Eversource Asset Condition Project Cost Increase

Also at the PAC, Chris Soderman of Eversource presented a cost and scope increase of an asset condition project in Connecticut. The project now includes the replacement of 22 structures and is projected to cost $32.2 million, compared to the initial estimate of $11.6 million. The project has an estimated in-service date of the fourth quarter of 2025. 

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Utilities Seek Rehearing in FERC Interconnection Funding Proceedings

A group of utilities have filed for rehearing of a show cause order FERC issued last month that could change the practice of who pays for interconnection lines at four ISO/RTOs. (See FERC Issues Show-cause Order on TO Self-Funding in 4 RTOs.) 

The commission asked ISO-NE, MISO, PJM and SPP to explain why their tariffs that give utilities the first shot at paying for the transmission upgrades required by interconnecting generators are just and reasonable, or to submit changes. 

Ameren Services, American Transmission Co., Duke Energy, Exelon, Northern Indiana Public Service Co. and Xcel Energy Services filed for rehearing of the show cause order this week. Ameren won a lawsuit involving MISO that started the practice back in 2018, but the District of Columbia Circuit Court of Appeals directed the commission to better explain its reasoning in 2022 after it had spread to the three other markets. (See FERC Must Clarify MISO Transmission Funding Decision, DC Circuit Finds.) 

The 2018 decision from the same circuit court found that revoking transmission owners’ right to self-fund network upgrades for interconnection and earn a right of return raised serious “statutory and constitutional concerns” due to compelling generator-funded upgrades on utility business models. 

“The commission has now decided to take on those serious constitutional and statutory questions — and potentially take the historic step of compelling the construction, ownership and operation of interstate transmission facilities by private entities with no opportunity to earn a return — all on the unproven premise that doing so will actually save consumers money,” the rehearing request said. “The show cause order is short-sighted and unwarranted. Investor-owned utilities investing private capital in exchange for a reasonable return is one of the most basic tenets of the century-old regulatory compact between government and the utility industry.” 

The constitutional issues come from the Fifth Amendment, which bars the government from taking private property for public use without compensation. Under the Federal Power Act, that has been interpreted to mean FERC cannot impose “confiscatory rates,” which means utilities need to be able to earn a reasonable return on the value of property at the time it is being used to render service. 

“It cannot be lawful to compel the construction, ownership and operation of utility-owned assets with no opportunity to earn any return,” the rehearing request said. “On this basis, the proposal in the show cause order is per se unconstitutional.” 

FERC suggested the interconnection upgrades can be treated as “nonprofit appendages without jeopardizing total return,” but the utilities argued it lacks the authority to eliminate equity returns from an entire class of rates represented by a major driver of new transmission investment. The utilities argued the decision could discourage much-needed investment in transmission expansion. 

The commission has run multiple proceedings that led to the rules at issue, while the D.C. Circuit’s 2022 ruling only required a better explanation as to why “generators’ concerns about potential discrimination did not outweigh the transmission owners’ enterprise-risk concerns.” 

The show cause order goes further and reopens the potential for discrimination in what appears to be an effort to “backfill the record that never materialized” in the proceedings leading to the currently effective rules across the four markets, the request said. 

The dispute started in MISO with FERC proceedings stretching back to 2011 with multiple proceedings that wound up before the D.C. Circuit with the court vacating decisions empowering generators to override a transmission owner’s self-funding choice. 

The court concluded the commission had “distorted and dismissed” the transmission owners’ fundamental argument that FERC’s orders would require transmission owners “to act, at least in part, as a nonprofit business,” and constituted an “attack on their very business model,” creating a risk of deterring “new capital investment,” the rehearing request said. 

That 2018 decision found it was “at least uncertain” FERC would reach the same conclusion on remand after addressing the deficiencies identified by the court. FERC sided with the transmission owners on the remand order. American Clean Power Association then filed a lawsuit that led to the 2022 decision, which FERC did not deal with until the show cause orders issued in June. 

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DOE, AAI Reports: VGI Critical to Managing New EV Power Demand

Vehicle-to-grid integration (VGI) is about more than connecting electric vehicles to the grid, say reports from the U.S. Department of Energy and the Alliance for Automotive Innovation, both released July 16.  

Rather, it represents a convergence of the automotive and electric industries in ways that could provide benefits for the grid, utilities, EV drivers, all utility customers and, in the big picture, society in general.  

At its most basic, VGI is the use of electric vehicle batteries, connected to EV chargers, as grid resources, either through managing when and at what pace they charge or tapping EV batteries for grid support or backup at times of peak demand or in emergencies.  

The two reports are complementary, with DOE’s “The Future of Vehicle Grid Integration” laying out a vision for VGI development by 2030, while the AAI report provides lists of recommendations focused on rate design and the kinds of technology that will be needed for consumer, utility and regulatory buy-in. 

DOE sees huge potential for VGI, with “millions of electric vehicles, charging at home and work, at charging depots and along the [highways] … integrated with the electricity system in a way that supports affordable and reliable charging for drivers and enables a reliable, resilient, affordable and decarbonized electric grid for all utility customers.” 

VGI can “seamlessly [align] the grid’s physical infrastructure and operational structure, regulatory frameworks and market design with customer charging behaviors to create a symbiotic relationship that benefits everyone regardless of EV ownership,” the report says. 

AAI’s definitions of success are more specific and targeted at building a solid business case for VGI. For EV drivers, VGI should deliver no-compromise mobility; convenient, reliable and affordable charging; and compensation for grid services, while utility customers will get a more efficient and modern grid that enhances system reliability and resilience and delivers economic and environmental benefits. 

Recommendations for utilities include adoption of time-of-use rates for EV charging and allowing EVs to participate in demand response programs. 

The overlap between the two reports is their recognition of the complexity of the work ahead to achieve their goals and the need for broad-based collaboration between utilities, automakers, regulators, EV charging firms and software developers, and local officials and community groups. 

Both also call for the development of standards and codes, with AAI more focused on data accuracy and technical interoperability, and DOE calling for “cyber-informed engineering” for EVs, charging equipment and the grid to minimize physical and cyber threats. 

What is also implicit in both reports is a shared sense that as more EVs hit the road across the U.S., VGI will be critical to managing their increased electricity demand, and best practices and information sharing will be needed to move beyond a recurring pattern of utility pilot programs to fuller system integration. 

DOE’s Big Picture

The DOE report was developed by the department’s EVGrid Assist initiative, which is itself a cross-industry group. The report notes it is intended to set goals for an ideal VGI environment and that a second report with specific strategies will be forthcoming.  

At the same time, it provides a framework for why VGI is important and specific pillars that could form a core for successful and equitable deployment of VGI.  

The report argues that VGI increases the use of grid infrastructure, cutting system costs, while helping to hold the line on electricity rates and put more clean energy online. EV owners can take advantage of more cost-effective charging, which lowers their total cost of ownership.  

VGI programs could also serve as a model for tapping other distributed energy resources for grid support and flexibility, the report says. 

Pillars for successful VGI deployment will include recognizing the “universal value” VGI provides to all utility customers and promoting a “right-sized” grid in which managed charging programs could cut peak loads and provide system flexibility. “Better use of grid assets reduces the risk of overbuilding,” the report says. 

For example, the report calls on utilities to provide “clear information about upgrade costs, capacity availability and load service request processes [to] help developers and site owners identify cost-effective charging locations where capacity is available.” 

The report’s other pillars focus on developing standards and codes, ensuring system security and providing customers with “a wide range of products and services to accomplish their charging needs,” as well as compensation for the services they provide. 

Both DOE and AAI recommend that VGI programs offer “value stacking,” allowing EV owners to get paid for different services their EVs might provide. 

Telematics and Bidirectional Charging

Incentivizing VGI through various rate designs is a priority in the AAI report. Utilities and regulators could support the deployment of DC fast chargers by adopting commercial and industrial rates that “ensure the … viability of fleet electrification and DCFC stations in the early stages of operations and in lightly trafficked areas.”  

Chargers in remote areas may not, at first, get enough use to cover utility demand charges and make the chargers financially viable, the report says. Possible solutions could include “temporary demand charge holidays … offsetting the demand charge with declining short-term subsidies and replacing the demand charge with a kW-based subscription fee.” 

For fleet electrification, another option is automated load management, a system that manages demand across more than one EV charger and can cut costs for the installation and operation of charging equipment, the report says. 

On the residential side, AAI pushes for a “prompt transition” from pilot programs offering time-of-use rates or managed charging to mass market initiatives, which will be “crucial to achieving cost-effective VGI as EV adoption accelerates.” The report also urges utilities and automakers to work together on wider consumer education programs to ensure EV owners are aware of and can easily sign up for such programs. 

AAI also points to telematics ― the integration of telecommunications and computer data ― as a key tool for advancing the benefits of managed charging. 

“Telematics-based managed charging programs integrate vehicle and utility data to optimize the timing of charging, thereby enhancing the value of an EV as a grid resource,” the report says. 

“By factoring the state of charge into the optimization algorithm, telematics-based managed charging systems can determine how long it will take to replenish the battery and therefore how much latitude there is to modulate charging to shift load and provide grid services,” it says. 

Deploying bidirectional charging at commercial scale is another way EVs can be integrated with the grid. By allowing EVs to charge from or discharge to the grid, bidirectional charging essentially turns EVs into mobile batteries that can provide “frequency regulation, spinning reserves and load shifting,” the report says. “Their ability to charge and discharge multiple times while plugged in significantly augments their value relative to standard EVs.” 

However, not all EVs currently on the market have bidirectional charging, which the AAI report says is costly to build into the vehicles, and incentives may be needed to compensate fleet operators for the added expense.  

The bottom line is that utilities, RTOs and regulators should enact policies and programs to compensate EV owners who send power to the grid, the report says. A Pacific Gas and Electric pilot program for EV commercial fleets provides incentives to offset equipment costs and uses day-ahead hourly pricing to encourage fleet operators to put power from their EV batteries back on the grid during times of peak demand.