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October 30, 2024

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Market Footprint Critical for EDAM Decision, NV Energy Says

The growing footprint of CAISO’s Extended Day-Ahead Market (EDAM) was a critical factor in NV Energy’s recently announced decision to join it rather than the competing Markets+ offering from SPP, the utility said in a regulatory filing.

PacifiCorp, the Balancing Authority of Northern California, Los Angeles Department of Water and Power, and Portland General Electric, as well as CAISO, all are expected to participate in EDAM. In addition, Idaho Power has said it is leaning toward EDAM as its day-ahead market choice.

The expected EDAM lineup “provides a significant degree of interconnectivity and supports a diversity of resources,” said Ryan Atkins, NV Energy’s vice president of resource optimization and resource planning.

Atkins’ comments are from written testimony included in the company’s 2025/27 integrated resource plan, filed with the Public Utilities Commission of Nevada on May 31. The commission made the filings public June 5.

CAISO’s recent approval of the Southwest Intertie Project-North (SWIP-North) was another key factor in NV Energy’s decision, Atkins said. A joint project by NV Energy and LS Power, SWIP-North will be a 285-mile, 500-kV line to send Idaho wind energy to markets to the south. It will connect to the One Nevada (ON) Line at Robinson Summit, a site that eventually will be one corner of a transmission triangle across Nevada when NV Energy’s Greenlink North and Greenlink West lines are completed. (See CAISO Board Approves Nevada Transmission Line to Access Idaho Wind.)

SWIP-North “will only enhance the transfer capability of the existing ON Line transmission line in Nevada, bringing even greater benefits to all EDAM participants,” Atkins said.

Atkins also noted the “significant economic, reliability and environmental benefits” that NV Energy has gained through participation in CAISO’s Western Energy Imbalance Market (WEIM). Since joining the WEIM in December 2015, the utility has reaped $488 million in benefits.

Although NV Energy stated in its IRP that it plans to join EDAM, the utility will file a separate, formal proposal later this year seeking PUC approval to join the day-ahead market.

In a June 6 release, CAISO called NV Energy’s intent to join EDAM “a substantial milestone in advancing the efficient coordination of the electric needs for growing loads and a changing resource mix across the West.”

‘Least-cost, Least-regrets’ Decision

NV Energy’s announcement of its EDAM choice may be a central piece in the day-ahead market puzzle in the West.

As competition for day-ahead market participants has been heating up between CAISO and SPP, many potential participants have indicated they are waiting to see who will join each market before making their own decision.

Entities that have shown the most interest in joining Markets+ include the Bonneville Power Administration and Puget Sound Energy in the Northwest, and Arizona Public Service, Salt River Project and Tucson Electric Power in the Desert Southwest. NV Energy’s balancing authority area sits between those two areas.

The comments in the IRP are the latest confirmation of NV Energy’s intent to join EDAM.

David Rubin, NV Energy’s federal energy policy director, confirmed the utility’s decision May 31 during a meeting of the Launch Committee for the West-Wide Governance Pathways Initiative. (See NV Energy Confirms Intent to Join CAISO’s EDAM.)

Before that, NV Energy had disclosed its decision to join EDAM during private meetings, multiple sources previously told RTO Insider.

In his testimony, Atkins also addressed the question of how NV Energy plans to meet a Nevada requirement to join an RTO by 2030.

“Events in the West are still too fluid, and the requirement dates still far enough out, to make any judgments about [NV Energy’s] ability to meet the Jan. 1, 2030, requirement,” he said.

Atkins described the decision to join EDAM as an incremental step to capture “substantial customer benefits on a least-cost, least-regrets basis.”

Last year, the PUC opened a docket to explore ways to evaluate a utility’s request to join a regional market or RTO. (See Nevada RTO Proceeding Examines EDAM, Markets+ Design.)

In a May 20 procedural order, Commissioner Tammy Cordova laid out 18 topics that NV Energy should address in an application to join a day-ahead market.

Those include governance, cost of participation, greenhouse gas tracking, impacts on non-jurisdictional transmission customers and pathways to joining an RTO.

Another topic for consideration is any investment in generation and transmission that would be needed to participate in the market or maximize its benefits.

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BOEM Clears Way for Central Atlantic Wind Lease Auction

The Bureau of Ocean Energy Management has determined its planned lease of Central Atlantic wind energy areas would have no significant impact on the ocean, the creatures that live there or the people who use it for other purposes. 

The final environmental assessment, announced June 6 sets the stage for the BOEM to auction lease areas along the Delaware, Maryland and Virginia coasts this year. The target date is Aug. 14. 

The analysis does not examine the impacts of construction and operation of wind turbines and the associated infrastructure. It analyzes only the research that would determine the area’s suitability for future wind farms and underwater transmission. 

This research includes site assessment and site characterization efforts such as placement of meteorological buoys and oceanographic devices, as well as geophysical, geotechnical, archaeological and biological surveys. 

The three wind energy areas — designated A-2, B-1 and C-1 — total 356,545 acres and stand as little as 19 nautical miles from shore. BOEM expects the four lease areas would average 80,000 acres each. 

B-1 will not be offered in this year’s auction because of the potential conflicts there between offshore wind turbines and nearby military and space flight activities. BOEM concluded the scope of constraints and cost of mitigation measures needed for construction were too great.  

However, B-1 was included in the environmental assessment because it may be included in a later lease sale after NASA and the Department of Defense complete an in-depth review of what activities could co-exist there, and under what conditions. 

Site assessment and site characterization were projected to have a negligible or negligible-to-minor impact on each of the resources evaluated, which ranged from air quality to fishing to military operations to sea turtles. 

BOEM’s Central Atlantic region stretches from Delaware Bay to Cape Hatteras.  

The world’s largest naval base, multiple fighter wings, a bombing and gunnery range and a space launch facility all are sited close to water’s edge, and the Department of Defense has raised concerns about incompatibility with wind turbines. (See Potential Military/NASA Conflict with OSW Seen in Wind Energy Area.) 

Some interagency friction was reported as BOEM attempted to prepare the region for offshore wind development, but by the time Central Atlantic wind energy auction plans were announced in late 2023, the Department of Defense and NASA offered supportive statements. (See BOEM to Auction Wind Energy Areas in Central Atlantic.) 

The concerns about building wind turbines in area B-1 apparently do not extend to doing research work there, or in A-2 or C-1.  

The environmental assessment predicts 201 to 377 round trips from port by an array of research vessels, and states that is not a large number when spread across the anticipated five- to seven-year research window or when compared with the heavy marine traffic already seen in the area. 

Potential conflicts with the military would be averted through effective coordination with military commanders and the U.S. Coast Guard, the report concludes, although site-specific stipulations may be needed. 

In a June 6 news release, BOEM Director Elizabeth Klein said development would move forward collaboratively: “We will continue to work closely with Tribes, our other government partners, ocean users, and the public to ensure that any development in the region is done in a way that avoids, reduces or mitigates potential impacts to ocean users and the marine environment.” 

BOEM also plans offshore wind energy auctions in 2024 in the Gulf of Maine, the Gulf of Mexico and Oregon. 

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Chicago Law Prof Takes ISO-NE to Task at Consumer Liaison Group

HOLYOKE, Mass. — Governance structures and market rules at ISO-NE that favor incumbent interests have contributed to pushing the region into costly and carbon-intensive reliability solutions, University of Chicago Law School professor Joshua Macey told the RTO’s Consumer Liaison Group (CLG) on June 4. 

Speaking to NEPOOL members, ISO-NE officials and members of the public at Holyoke Community College, Macey said the voting power of incumbents within NEPOOL has led to a bias toward capital-intensive solutions to reliability concerns. 

“Reliability regulations are increasingly coming into tensions with clean energy policies,” Macey said, pointing to the reliability-must-run agreement for the Mystic Generating station and ISO-NE’s inventoried energy program, which compensates resources for keeping stored fuel on hand in the winter. The program is set to expire at the end of February. 

“This is the type of intervention that essentially renders any type of clean energy policy irrelevant,” he said, arguing that out-of-market fuel security interventions constitute an admission that the capacity market is not adequately serving its reliability function. 

He argued that ISO-NE’s capacity market has had small penalties for generators that can’t run when called upon. In 2014, “a resource could have met none of its obligations and still made a profit in the capacity market,” he said.  

Although penalties have increased in recent years, that must be coupled with “some way to guarantee that the generator can pay,” Macey said. 

ISO-NE is in the middle of a multiyear process of revising its capacity market rules to better align procurements with tangible reliability benefits. The RTO also has an ongoing project “to reduce collateral shortfalls for Pay-for-Performance penalties that generators are assessed if they fail to operate or underperform during long-duration capacity-scarcity conditions.” 

Regarding transmission, Macey argued that a lack of oversight over line upgrades has led to high-cost projects that do not address the looming needs associated with the clean energy transition. 

Asset-condition project costs have increased dramatically over the past 10 years, prompting states to push for changes. In response, transmission owners have rolled out some changes to the asset-condition review process, including a new database, process guide and opportunities for stakeholders to provide comment on projects in the planning stages. (See “Asset Condition Project Updates,” ISO-NE PAC Briefs: Dec. 20, 2023.) 

However, asset-condition costs have continued to accumulate. In mid-May, National Grid proposed an approximately $500 million project to replace degrading wooden structures with steel poles on a line that was previously refurbished in 2008. (See ISO-NE Planning Advisory Committee Briefs: May 15, 2024.) 

Since the financial risk of these transmission investments falls on ratepayers, TOs face minimal consequences for ineffective or poorly planned upgrades, Macey said. 

One NEPOOL officer took exception to Macey’s characterizations of market and governance bias. 

“When you look at NEPOOL, all the voting is transparent,” said Dave Cavanaugh, vice chair of the organization’s Participants Committee, whose meetings are closed to the press and public. NEPOOL’s primary role as a purely advisory body limits the power of individual companies or sectors, he argued. 

Regarding Macey’s criticism of the capacity market, Cavanaugh said ISO-NE is working to address some of the issues the professor talked about, including increasing penalties. “There’s a message in the marketplace that you need to perform.” 

Demand Response

Henry Yoshimura, director of demand resource strategy at ISO-NE, outlined the role of demand response in the clean energy transition. 

As intermittent renewable resources increase, the grid will face “big periods of under-generation and big periods of over-generation,” Yoshimura said. These swings will lead to energy prices that increasingly “bounce around.” 

This variability of supply, combined with rapidly increasing peak loads, will make DR a key resource in the coming years, Yoshimura said. 

“I do think that retail rate reform is needed in order to encourage demand flexibility,” Yoshimura said, adding that time-of-use rates could incentivize end users to better align their consumption with wholesale prices. 

Yoshimura noted that the proposed shift to a prompt and seasonal capacity auction could boost DR resources, which can be relatively quick to develop and could be used to fill capacity deficiencies on a shorter notice than many traditional transmission or generation solutions. 

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WECC Flags Hydro in BC, SW Heat as Potential Summer Concerns

Extreme heat in the Desert Southwest and low hydro conditions the Northwest could pose reliability problems for the Western Interconnection this summer, although the region isn’t at an alarming risk for grid emergencies, WECC officials said during a June 5 call. 

Those officials delved into the regional entity’s findings that became part of NERC’s 2024 Summer Reliability Assessment, which showed British Columbia, the Southwest and Baja California at an “elevated” — but not “high” — risk this summer, which indicates a “potential for insufficient operating reserves in extreme conditions.” (See NERC Summer Assessment Sees Some Risk in Extreme Heat Waves.)

Despite that assessment, Kris Raper, WECC vice president of strategic engagement and external affairs, cautioned call listeners about how quickly conditions could deteriorate, noting industry participants know the West has “had some really tight summers recently.”  

“Until we can get more resources and more transmission online to be able to get the energy from where it’s generated to load and have a broader perspective and purview of where that energy can come from, then we have to know what it is that we’re looking at and what the risks may be,” Raper said. “And right now, the risks are greater than they’ve ever been.”  

A trend of rising temperatures and an increased rate of load growth has fueled steady increases in summer peak demand in the West in recent years, and this year is expected to be no different, WECC officials said.  

Data from the National Center for Environmental Information indicates a 61% chance that 2024 will be the hottest year on record and a 100% chance it will be in the top five, said Matt Zapotocky, senior reliability assessments engineer at WECC.  

Investing in additional capacity is crucial to accommodating the increasing frequency of heat waves, Zapotocky said. Inverter-based resources (IBRs), which include renewables and battery storage, make up the bulk of capacity additions in the Western Interconnection, with the latter increasing “exponentially” between 2019 and 2023, from 230 MW to almost 10 GW. Solar resources nearly doubled from 19 GW to 35 GW over that time, and wind resources increased from 25 GW to 37 GW.  

An additional 32 GW of proposed capacity is projected in 2024, with about 80% of that being IBRs. WECC also expects 1.6 GW of mostly thermal resources to be retired.  

While no Western regions are projected to experience a loss-of-load event this summer, according to WECC’s assessment, some regions, such as British Columbia, are at a greater risk than others.   

While hydroelectric resources and reservoir levels — particularly in California — are in a better position than they’ve been in the recent past, conditions have not returned to historical norms, said Bryon Domgaard, a senior analyst at WECC. Drought remains in British Columbia, where hydro resources make up 90% of the resource portfolio. Additionally, the province is undergoing rapid electrification in the industrial, commercial and residential sectors, but there are no planned capacity additions for the summer ahead, he noted.  

“That reduction in hydro availability is really what is concerning for British Columbia. In addition, the transfer capacity has been diminishing over the past couple years as we see more load growth in the Pacific Northwest taking out some of the transfers that used to make it to British Columbia,” Zapotocky said. “These concerns, coupled with the increase in demand in British Columbia from electrification, placed it in that elevated risk category.”  

The Desert Southwest also sees elevated risk because of heat-related extreme weather. The potential for high temperatures to cause derates for natural gas-fired generators coupled with escalating demand could lead to loss of load, Zapotocky said.  

In California and Mexico, supply chain issues for obtaining grid equipment are of greater concern.  

“Not being able to complete their projects on time could result in escalating the small amount of loss-of-load hours that we’re seeing in that region,” Zapotocky said. “Which reliability risk is most pertinent depends on which region we’re discussing.” 

While increased coordination continues to be crucial for mitigating risk, interconnectivity in the system also adds new complexities.  

Solar proliferation in California and Mexico has boosted south-to-north transfers into the Northwest, causing concerns about hitting system operating limits on paths between the two regions, Zapotocky said. And despite seeing more transfers from California to the Northwest, fewer of the transfers are making it to Canada. As British Columbia is forced to serve more of its own load, the system in other regions, such as Alberta, can experience reduced transfer capability.  

“When it’s near islanding conditions — when IBR outputs are high and demand is low — there’s actually difficulty maintaining frequency response in that region, and this can potentially result in additional under-frequency load shedding. So really, everything is kind of interrelated here,” Zapotocky said.  

With the influx of IBRs, areas in the Desert Southwest also are experiencing increased frequency issues. 

Working Together

Demand response programs have been “instrumental” in reducing peak demand during stressed grid conditions, Domgaard said. But they face limits because of decreased customer participation in the face of increased DR events, and they should be reserved for emergencies.   

Working together remains the priority in ensuring reliability across the Western Interconnection, said Katie Rogers, WECC manager of reliability systems.  

“If there are wildfires going on in California, if there’s a drought that’s affecting hydro availability up in the north, how can the subregions and [balancing authorities] in the whole of the Western Interconnection work together so that someone isn’t stranded?”  

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FERC Nominees Set for a Quick Floor Vote as Schumer Files Cloture

President Joe Biden’s three nominees to FERC are set for a floor vote as soon as next week with Senate Majority Leader Chuck Schumer (D-N.Y.) filing cloture on them June 5. 

Energy expert Judy Chang, FERC staffer David Rosner and West Virginia Solicitor General Lindsay See all comfortably cleared the Energy and Natural Resources Committee on June 4, with leaders urging swift confirmation to maintain a quorum on the commission. (See related story, Senate Energy Committee Advances Biden’s FERC Nominees.) 

Two of the nominees would fill two open seats, and Chang would replace outgoing Commissioner Allison Clements, who congratulated them on their swift movement through the confirmation process in a post on X. 

“As my term is ending, I intend for the June open meeting to be my last,” Clements posted, along with a screenshot of the Senate Cloakroom’s X feed showing Schumer’s cloture motions. “More to say then, but for now — it has been my highest privilege and honor to serve.” 

Clements’ term ends June 30. A quick confirmation would maintain FERC’s quorum after Clements leaves, meaning it will be able to continue its normal business and vote out orders. 

In addition to the leadership of the ENR Committee, several groups had also called on the Senate to move quickly to confirm the three nominees. 

“It is vital that FERC [have] a full suite of commissioners as it goes through the rehearing process on Order 1920 and moves towards implementation,” Electricity Transmission Competition Coalition Chair Paul Cicio said in a statement. 

The Interstate Natural Gas Association of America, which represents the pipelines regulated by FERC, also called for swift approval of the nominees. 

“With a pending vacancy in a couple of weeks, the agency could lose quorum, which would eliminate the commission’s ability to approve construction of critical energy infrastructure projects, including natural gas pipelines and storage facilities,” INGAA CEO Amy Andryszak said in a statement. “INGAA urges the Senate to act swiftly to avoid this loss of quorum by scheduling votes to confirm the nominations of Rosner, See and Chang with bipartisan support.”

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USEA Event Looks into Addressing Growing Data Center Demand

Data center expansion is a major part of the power industry’s return to demand growth around the country, and the United States Energy Association hosted a webinar June 5 with industry leaders on how the sector’s growth will play out. 

NERC for years forecast flat growth nationally, but that changed last year in part because of data center expansion to meet new computing needs from artificial intelligence. CEO Jim Robb said he expects growth will be even higher in the next long-term assessment. (See NERC: Growing Demand, Shifting Supply Mix Add to Reliability Risks.) 

Growing demand makes ensuring resource adequacy more of an issue, but the scope of specific data centers can lead to challenges for the grid. 

“We’ve seen and heard reports of interconnection requests on the order of 1 to 1.5 GW,” Robb said. “And to put that in perspective, a gigawatt is about the entire load of the city of San Francisco. So, these are very, very large loads that are seeking to interconnect, and they’re not diverse, right? So as load is either on or off, that has potential to create stability issues for the grid.” 

AI uses much more energy than a normal Google search, but over time, the difference should shrink because Nvidia, which manufactures much of the hardware for AI, is expecting its next generation of chips to use less power, Robb said. 

“Algorithms will also get better over time,” Robb said. “We saw this with the internet when the internet was first coming into broad scale adoption in the ’90s and early 2000s. We had similar concerns around electricity demand that largely didn’t actually occur because the chips got better. The algorithms got better. We will see something similar happen with the AI chips as well.” 

Data centers are very important to modern civilization, and while they do consumer a lot of power, they provide major benefits, said Christopher Wellise of Equinix, which builds data centers around the world. 

“They do operate … 24/7/365, supporting a whole wide range of essential services, from the life-saving work in hospitals, to first responders, to powering global financial markets, managing food and pharmaceutical production, and so on,” Wellise said. “Not to mention, of course, entertainment, communication and all the other things … that folks rely upon.” 

Some in the data center industry are putting multiple facilities at one site, and those can get up to 4 or 5 GW of demand, said Daniel Brooks, vice president of integrated grid and energy systems at the Electric Power Research Institute. (See EPRI: Clean Energy, Efficiency Can Meet AI, Data Center Power Demand.) 

“That’s a significant requirement in terms of additional supply and delivery capacity that has to be planned and permitted and constructed,” Brooks said. “And the timelines for the development of the data centers themselves are on the order of … one to two, maybe three years.” 

It takes longer than that to actually get new supply and new power lines sited, permitted and built: three to five years for a new gas turbine. Transmission can take even longer, he added. 

Natural gas is going to be part of the grid for the near term; whether that is defined as five to 10 years or 15 to 20 is anyone’s guess, said Dan Brouillette, president of the Edison Electric Institute. 

“I don’t suggest to you that that’s what utilities want,” Brouillette said. “That’s just what is required by the physics of the problems that we’re facing today. There’s no way to stabilize the grid today without the use of some firm baseload power, and that includes natural gas. So, I think that you know, as I see it here, fully decarbonizing the grid, fully decarbonizing electricity production in the United States, it’s probably not going to happen by 2030.” 

Even getting it done by 2035 is ambitious, but Brouillette said utilities would continue to “make every effort.” 

While demand from data centers is a growing issue, the industry has dealt with huge spikes from specific facilities in the past, especially at the start of the Cold War, when nuclear weapons production was ramping up, Brouillette added. Those manufacturing facilities consumed 10% of the electricity in the country. 

The issue “boils down to a question of political will” and whether the facilities can be permitted, he added. 

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NERC Targets IBR Modeling Concerns in Level 2 Alert

In light of recent grid disturbances involving inverter-based resources (IBRs), NERC sent a Level 2 Alert to industry June 4 seeking information on their presence on the grid and the models in use by their owners and operators while also providing recommendations to strengthen current modeling practices. 

Under NERC’s alert system, recipients of a Level 2 Alert must respond to the ERO by a set time; in this case, applicable stakeholders must acknowledge their receipt of the alert by midnight ET on June 11 and respond to its questions by Sept. 2. Unlike a Level 3 Alert, action by stakeholders is recommended but not required. 

Concerns about IBRs, and particularly modeling practices related to them, have risen in recent years because of a series of grid disturbances directly involving IBRs such as wind and solar generation facilities. NERC’s alert mentions 10 large-scale disturbances since 2016 totaling nearly 15 GW of “unexpected IBR output reduction.” About 10 GW worth of disturbances have occurred in the past four years. 

The ERO did not mention specific disturbances in its alert, but it has documented several noteworthy events in which operators lost substantial amounts of generation from IBRs, including two separate events near Odessa, Texas, in which the Texas Interconnection lost nearly 4 GW of solar PV and synchronous generation. (See NERC Repeats IBR Warnings After Second Odessa Event.) After the second event, NERC issued a report identifying modeling as a significant challenge to maintaining grid reliability with IBRs. 

“The significantly higher complexity and software-based nature of IBR modeling … necessitates an improvement in the fundamental principles of dynamic modeling to accurately capture the performance of IBR plants,” NERC said in this week’s alert. 

The alert is directed at generator owners (GOs), transmission planners (TPs) and planning coordinators (PCs). GOs that own grid-connected IBRs, including solar and wind generators, battery energy storage systems and “any hybrid facilities with an IBR component” are required to complete a workbook providing a range of information about their IBRs, including: 

    • manufacturers of inverters on their systems; 
    • model numbers for their inverters and their quantity; 
    • nameplate ratings for each model of inverter; 
    • inverter- and plant-level voltage and frequency protection settings; 
    • inverter- and plant-level reactive power capabilities and control information; 
    • model types used to represent facility model data to TPs and PCs; and 
    • dynamic and load-flow model files for each facility. 

In addition to this information, IBR owners — along with TPs and PCs — must answer a series of questions. These include whether their organizations have publicly available model submission and quality requirements, what type of generator models are permitted during the interconnection process, and how the organizations verify accuracy of their models. 

NERC also provided a set of recommendations for all stakeholders to mitigate known modeling deficiencies, such as validating models at the individual inverter and plant level and updating models throughout the life cycle of the plant. In addition, the ERO suggested implementing standard library positive sequence phasor domain models in interconnection-wide base case creation, while using equipment-specific models for generation interconnection and local reliability studies. 

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Lithium-ion Batteries to Replace NYC Peaker Plant

An energy storage developer has committed to replacing one of New York City’s aging fossil-fired peaker plants with a lithium-ion battery system. 

Elevate Renewables said it expects its Arthur Kill project to be the largest battery energy storage system (BESS) in the city when completed in mid-2025.  

This distinction speaks more to the historic challenges of siting storage in the city than to this project’s capacity — at 15 MW and 60 MWh, it is a fraction of the size of systems being built elsewhere in the state and nation. 

However, New York City has moved to sharply ease construction of energy storage, which will play a critical role in decarbonization of its grid, and Elevate Head of Development Eric Cherniss said he expects his team’s project will not hold the title for long. 

But he’s OK with that and says down the road Elevate may make plans of its own that also would dwarf this initial project. 

“New York has a very aggressive target. And I think we can play a very material role in that,” Cherniss said. 

The corporate umbrella that includes Elevate owns the Arthur Kill Power Station, which along with the peaker consists of two gas-fired steam turbines rated at 376 and 535 MW and dating to 1959 and 1969. 

One can think of potential scenarios involving an aging waterfront fossil plant with interconnection rights in a state trying to develop 9 GW of offshore wind on its way to a zero-emissions grid.  

Nothing is ready for public announcement at Arthur Kill, Cherniss said, “but we definitely see that there’s opportunities to reutilize existing infrastructure.” 

The City of No

Development of BESS has been slow in New York state, due in part to market and regulatory structures not optimized for storage. Development has been particularly challenging in New York City, which had earned the nickname “City of No” for its approach to renewable energy development. 

With its dense population, expensive real estate and public safety concerns, the city has practical limits on renewables beyond policy limits. 

But in December, the New York City Council approved a package of zoning changes titled “City of Yes for Carbon Neutrality” that seeks to ease siting of energy storage and renewable energy generation, along with other environmentally friendly steps. 

The Arthur Kill BESS proposal had been in the works for a few years and did not face some of the obstacles that stymied other projects.  

It is in Staten Island, the city’s least populated borough, and will sit on a legacy brownfield site already used for power generation in an industrial area apart from homes. 

This is Elevate’s niche: The 4 GW of projects it is developing in six states are all co-located with existing power infrastructure on brownfields, whether they are replacement, co-location or hybridization of new and existing assets, Cherniss said. 

This cuts down on environmental impact, can reduce local opposition and may come with a skilled workforce on site. 

“It’s just the right place to put these facilities and be able to provide the services that are wanted in places in which they’re needed,” he said. 

“So, we had a lot of things going for us when we initiated this development that helped speed things along and reduced the risk of execution.” 

The 20-MW gas-fired peaker the BESS will replace was destined for retirement anyway — it will not meet tougher state air emissions standards imposed on peakers effective May 1, 2025. 

The upcoming wave of peaker retirements was sufficiently worrisome to NYISO that in November, it directed four of the generators to remain available for up to two more years to meet reliability needs. 

The Arthur Kill BESS will be one more backstop, able to power more than 10,000 households during peak periods — not a large number in a city of 8.3 million people, but it makes a statement.  

“It demonstrates the capability of renewables and specifically energy storage to really just step into the void associated with retiring assets,” Cherniss said. 

All major regulatory hurdles are cleared: Elevate has signed its construction contracts, and the energy storage services agreement with Con Edison was submitted to the state Department of Public Service on May 24. 

Commercial operation is targeted for the summer of 2025. 

The City of Yes

In the wake of the City of Yes revisions, Staten Island has attracted attention of BESS developers, so much so that Borough President Vito Fossella has raised safety concerns about the number of proposals and their proximity to residential areas. 

Popular opposition has reared up as well, thanks in part to media coverage of BESS fires. But in the industrial zone along the Arthur Kill, the new BESS will be away from residences. 

Cherniss said Elevate has heard no local opposition to its 15-MW BESS. 

Similarly, a 650-MW BESS proposed by Hecate Grid a half-mile from the Arthur Kill Power Station has generated no written comments to the DPS even though it is closer to residential areas, nor did anyone comment during a DPS public statement hearing May 15. 

Other large-scale proposals have been floated in New York City, and Cherniss predicts the Arthur Kill BESS will not be the largest in the city for long. 

“It really depends on when people show up with their projects based on their stated time frames,” he said.  

“I believe it’s sometime in either ’26 or ’27. For New York City, I hope that it’s sooner or it stays on that time frame, because I’d love for there to be some more competition to continue to grow energy storage due to the importance that I see, placed in the overall transition.” 

(These records already are falling with some frequency: Less than a year ago, Con Edison claimed the title of biggest BESS in the city with a 7.5-MW/30-MWh facility in a different part of Staten Island.) 

Elevate “absolutely” intends to go larger than 15 MW on future New York City BESS development, Cherniss said, and he sees progress at the DPS and NYISO on building regulatory and market structures that can better support energy storage development. 

Storage is more than a way of meeting peak demand, he said; it adds stability and resilience to a grid increasingly relying on intermittent renewables. These added values are not presently compensated, he added, but he sees improvements in the works in New York state.  

“It’s going to take the market some time to figure out how to give those signals to the development community,” he said, “and that’s why you see a significant number of the states either putting procurement requirements or direct subsidies, because they know the value of energy storage, but they know that the market isn’t necessarily giving that clear of a signal.”

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NJ Master Plan Speakers Seek Sweeping Electrification Plan

Clean energy supporters argued in a hearing for the next New Jersey energy master plan that an aggressive and broad embrace of electrification would generate enough money to help fund clean energy projects and protect ratepayers. 

Speakers at the fourth, and final, online public forum, held June 3 by the New Jersey Board of Public Utilities (BPU) to solicit input for the successor to the state’s 2019 Energy Master Plan, pushed state officials to include extensive investment in storage and in-state electricity generating projects in the plan. 

They also sought a cost evaluation that would include the direct expenses of electrification strategies and show the costs avoided if the effects of climate change and pollution are mitigated, such as fewer health services needed. Some speakers argued that electrification strategies would pay for themselves. 

Andy Wall, a board member of the Mid-Atlantic Solar and Storage Industries Association, said that instead of spending $600 million to buy clean energy from out of state, as the organization forecasts for this year, the state should invest within its own borders. 

“We need to take those resources and focus them on clean energy generation projects closer to home that actually matter to our own in-state generation mix,” he said. 

He said while the state goal for 2023 was for clean energy to account for 22% of all energy, only about one-third of that was generated in state. The rest “came from renewable energy projects in the Midwest, mostly Illinois, but also Indiana, Ohio, even North Dakota and some other places on average 800 miles away. “  

Michael Winka, a former BPU clean energy policy adviser, said the state’s electric system generates about $11 billion in revenue, which would increase to $22 billion if electricity use doubled as forecast. That would provide plenty of money to support the energy transition, he said. 

“The cost to upgrade the distribution system at max is probably $4 billion to $5 billion range,” he said. 

Winka called the 2019 master plan a “good first step” but said the next version has to better evaluate all energy systems and provide a “detailed cost, avoided cost and benefits, of not using oil, gasoline and diesel.” The plan also should “detail the revenue increases that go along with an increase in electricity usage.” 

Deeper Study

BPU officials said they’re looking to produce a “deeper more robust study,” than the 2019 version, which was compiled at the request of Gov. Phil Murphy (D). While it has underpinned much of the state’s clean energy strategy during Murphy’s tenure, business groups have criticized the plan for failing to include an assessment of the cost of dramatically cutting fossil fuel use. 

The next plan, state officials said, will include policy analysis and a review of best practices nationally, modeling of the impact of the plan on gas and electricity rates and a consideration of using gas as a backup heat source in the coldest months of the year. (See NJ Wrestles with Clean Energy Priorities.)   

With the public hearings completed, the BPU will conduct “workshop-style gatherings of stakeholders.” The agency plans to release a report draft in the third quarter of 2024 and the final report in the fourth quarter. According to the BPU, the report will be led by the Governor’s Office of Climate Action and the Green Economy, with input from multiple state agencies. A Final Comprehensive Climate Action Plan will be released in the third quarter of 2025. 

More than 50 people spoke over three hours at the first session, on May 20, and about two dozen voiced their opinions at the final hearing. Among the speakers June 3, Andrew Gold, staff attorney for the New Jersey Rate Counsel, offered a note of caution, urging the master plan drafters to “view modeling results with a healthy degree of skepticism.” 

“Projecting the future during fundamental changes over long periods is challenging,” Gold said. “Modeling results are frequently overly optimistic and make many assumptions that are impractical to implement.” 

He said the BPU should compare the 2019 master plan modeling assumptions to what happened and ensure the 2024 energy master plan incorporates the past. Gold urged the BPU to make its “modeling platform” public, calling it “unreasonable to ask ratepayers to pay billions of dollars based on a model that the public cannot access.” 

At the BPU’s May 22 master plan hearing, the Division of Rate Counsel said state energy efficiency programs, many of which are focused on helping low- to moderate-income ratepayers, should be more cost effective and the state should hold “utilities and contractors accountable for their performance.” Some programs should be run by utilities and others by the BPU, said Lisa Littman, assistant deputy rate counsel, who urged the board to “refrain from establishing utility-run monopolies.” 

Solar-powered Green Hydrogen

Utilities emphasized the need for planning, and support for their own initiatives, some of which are underway. 

“Comprehensive integrated distribution planning is vital and will help identify utilities’ resource and customer needs,” said Noreen Giblin, associate counsel state regulatory at PSE&G. 

“Improvements to regional load forecasting are essential for effective transmission planning, and in determining how much generation needs to be built and where, while providing visibility into the amount of clean generation needed to reach stated objective,” she said.  

Giblin urged the state to strengthen programs to boost medium- and heavy-duty vehicle infrastructure. And she said PSE&G has proposed “the adoption of time use rates in its current base rate case to …. encourage residential customers to shift electricity usage away from peak demand times, saving money.” 

Melissa Orsen, senior vice president at South Jersey Industries and president of SJI Utilities, which owns two gas utilities in new Jersey, said the company aims to reach 100% carbon-neutral operation by 2040. The effort includes spending 25% of the utility’s annual capital expenditures on sustainability projects such as repairing leaks, replacing the legacy pipeline distribution system with “modern resilient facilities” and investing in renewable natural gas (RNG) and green hydrogen. 

“We envision a future where New Jersey residents transition to clean energy but continue to use their gas appliances with RNG and green hydrogen being critical components of the gas stream,” she said, adding that “our ability to achieve these goals in many ways depends on the state support as expressed in the next EMP.” 

The utility’s effort also will depend on how the BPU responds to utility on-site solar projects, she said, adding that this year, it will begin “producing green hydrogen powered by solar energy” in South Jersey that will be blended into the gas system. 

Solar Parity with Wind?

Clean energy developers said the state needs to do more to ensure their sectors become the major energy providers needed to meet state clean energy goals. 

Lyle Rawlings, president of the Mid-Atlantic Solar and Storage Industries Association, said he would like to see the state reform the “stark disparity in the state’s investment of effort and money to help the offshore wind industry with infrastructure investment, flexibility, workforce development, helping hand in tough times and much more.” 

“We recognize the absolute necessity of offshore,” he said. “But we want to see an equally comprehensive and proactive approach for solar.” 

In a subsequent interview with NetZero Insider, Rawlings said the issue is a “long-standing gripe that we’ve never spoken about.” He said his concerns include the amount of money the state has committed to offshore wind infrastructure while it has “never spent a dime on infrastructure to encourage solar.”  

Another concern, he added, is that in the post-pandemic period — when developers experienced cost increases and supply chain issues — the BPU refused to extend project deadlines, resulting in “hundreds of projects that had to be canceled before they were done.” 

Evan Vaughan, executive director of the Mid-Atlantic Renewable Energy Coalition, which represents 50 utility scale wind, solar and storage developers, said the state needs to address the fact it is “woefully behind” in its energy storage goals, specifically the goal of having 600 MW of storage in place by 2021 and 2000 MW of storage in place by 2030. 

“The PJM market does not incentivize energy storage currently, and so a state incentive program is critical for any meaningful level of deployment,” he said. He encouraged New Jersey to conduct long-term planning for its transmission system, including with other states. 

“We ask New Jersey to look closely at near-term opportunities to coordinate with neighboring states like Maryland and Delaware to facilitate no-regrets cost-saving transmission planning for offshore wind integration and for the integration of other energy sources like solar and storage,” he said. 

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MISO: New Interconnection Queue Cycle to Wait on MW Cap Filing

MISO said new queue entries must wait while it takes another swing at imposing an annual megawatt cap on its interconnection queue.  

MISO Manager of Generation Interconnection Ryan Westphal said the RTO will file by the end of the year for a cap to create a leaner and less backlogged waiting room for new generation. He said it won’t accept applications for new generation projects until it hears from FERC on the filing. That likely will leave MISO a year behind on its queue processing.  

“Our plan right now would be to get this through before we open another queue,” Westphal told stakeholders during an Interconnection Process Working Group teleconference June 4.  

Months ago, MISO staff hoped the RTO could begin processing both the 2023 and 2024 cycles of queue applications before the end of the year. That no longer appears to be the case. When asked by stakeholders, Westphal wouldn’t venture an estimate as to how long before MISO would begin study work on the 2024 cycle of interconnection requests.  

MISO’s 2023 class of queue applications was delayed into early 2024 while it tried for new rules to discourage speculative projects from entering the queue. Those rules included its unsuccessful first attempt at a megawatt cap. (See MISO Reports 123-GW Roster for 2023 Interconnection Queue Cycle.) In April, MISO reported a 2023 queue intake of 123 GW spread across about 600 interconnection requests, substantially lower than 2022’s 171 GW of proposed generation projects across 956 interconnect requests. 

FERC late last year denied MISO’s proposal to cap generation projects entering its interconnection queue on concerns over too many cap exemptions, the formula to establish the cap and potential resource adequacy deficits from limiting new generation onto the grid. However, FERC said a “cap in some form could be beneficial.” (See FERC Rejects MW Cap, Approves MISO’s Other Stricter Interconnection Queue Rules.) 

MISO maintains that some limit on projects remains necessary. It said too many applications result in an overwhelming study process and make it nearly impossible to resolve models for a hypothetical system loaded with new generation.  

“We did get a 30% reduction in the 2023 cycle versus 2022, but we still think we need to cap annual cycles. … We think this is necessary for the future to maintain an orderly queue going forward,” Westphal said. “Ultimately, we want to have a queue that’s fast and efficient where [we’re] giving you good information so you can make better decisions. That’s the hope, and we think that’s achievable with less volume.” 

Westphal said that, had MISO this year encountered the volumes it experienced in 2022, the queue could be as high as 350 GW by now. He emphasized that MISO’s peak load expectation is 127 GW.  

Westphal said MISO is leaning toward simplifying the calculation, which could be as “simple as a percentage of load.” He said MISO staff are at the same time contemplating ways to “limit the use of exemptions” to the cap to better the chances of it passing FERC’s judgment.  

Finally, Westphal reassured stakeholders that MISO is thinking about its future resource adequacy needs alongside its second attempt at a cap design. He said MISO envisions that a cap would put it in position to administer less onerous studies more quickly and deliver more interconnection approvals sooner. 

Curb ‘Queue Crashing,’ Savion Advises

However, Derek Sunderman, of Shell subsidiary Savion, said that instead of a hard megawatt cap, MISO should pursue a “gating mechanism” to deter disproportionate applications from a handful of interconnection customers.  

He said some interconnection customers will “queue crash,” or submit large volumes of interconnection requests into a study application window to secure grid hookups.  

Sunderman said MISO should consider administering a volumetric price escalation in the queue, where interconnection customers’ fees and penalties rise as they submit more projects for study. He said higher milestone fees for 4 GW worth of applications versus 1 GW of submittals would allow smaller interconnection customers to meaningfully participate in the queue while still allowing larger interconnection customers to submit as many projects as they believe feasible. He also said escalating prices would cause large corporations to rethink their projects’ viability.  

Sunderman said if MISO pursues a hard cap at a hypothetical 80 GW, it might encourage a mad dash among developers to snap up queue positions. Volumetric price escalation, on the other hand, would allow all kinds of developers access, he said.  

“It’s not a fight of the fittest of who can consume the most megawatts first,” Sunderman explained. “We’re concerned that the higher-equipped companies could control a percentage of the queue” under a hard cap.  

Westphal said MISO would consider Savion’s proposal and hold more discussion on a cap design at the Interconnection Process Working Group’s meeting July 23.