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January 31, 2025

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Shell Quits Atlantic Shores Offshore Wind Project in NJ

One of the partners behind New Jersey’s Atlantic Shores Offshore Wind has bailed out of the long-running project, taking a billion-dollar impairment in the process. 

Shell announced the news Jan. 30 with its fourth-quarter 2024 earnings results. 

The offshore wind project was not specifically mentioned in material prepared for investors, or in prepared remarks by the CEO and CFO. Instead, the company referred to the $996 million in impairment charges “mainly relating to renewable generation assets in North America.” 

Similarly, in its first-quarter 2024 reporting, Shell offered few details about its divestment from SouthCoast Wind, off the Massachusetts coast. 

Shell New Energies US had partnered with Ocean Winds North America on SouthCoast and with EDF-RE Offshore Development on Atlantic Shores. Ocean Winds has continued with SouthCoast since Shell’s departure.  

In a Jan. 30 statement, Atlantic Shores said it too will continue working to deliver the project. 

“Business plans, projects, portfolio projections and scopes evolve over time — and as expected for large, capital-intensive infrastructure projects like ours, our shareholders have always prepared long-term strategies that contemplate multiple scenarios that enable Atlantic Shores to reach its full potential,” the company said. 

Both projects have secured their key federal permits, which will provide at least short-term protection from the Trump administration’s attempts to halt offshore wind development in U.S. waters, which include a freeze on leasing. (See Critics Slam Trump’s Freeze on New OSW Leases.) 

But under Trump’s Day 1 executive order, Atlantic Shores and SouthCoast are subject to a review that could result in their leases being amended or terminated. 

Furthermore, Atlantic Shores and SouthCoast both have critical gaps in their balance sheets. 

Atlantic Shores won a 1,510-MW contract from New Jersey in June 2021. But in July 2024, it submitted a bid in New Jersey’s fourth solicitation for two projects — one new, but one a rebid of the original project, presumably with higher costs attached. (See 3 OSW Proposals Submitted to NJ.) 

New Jersey still has not finalized contracts from that solicitation. 

Massachusetts and Rhode Island selected SouthCoast in early September in a three-state solicitation but have not been able to complete negotiations on power purchase agreements. They are now targeting a March 31 execution date — a full year after developers submitted bids. 

New Jersey has some of the largest offshore wind goals in the U.S., and its shore region has been the scene of some of the loudest opposition to development of offshore wind farms. Opponents cheered in late 2023 as Ørsted abruptly canceled the Ocean Wind 1 and 2 projects it had contracted with the state. (See Ørsted Cancels Ocean Wind, Suspends Skipjack.) 

And opponents cheered again as word spread of Shell’s pullout. 

“Another major blow to the offshore wind scam! Shell is pulling out of the Atlantic Shores project, writing off nearly $1 billion as the industry collapses under its own weight,” U.S. Rep. Jeff Van Drew (R), who represents much of the shore region, posted Jan. 30 on X. 

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‘Green’ Steel Mill Gets Financial Boost from CEC Grant

San Diego-based Pacific Steel Group (PSG) is planning a zero-carbon-emission steel mill near Mojave, Calif., in a first-of-a-kind project that will set an example for industrial decarbonization.

While there have been other electric steel mills, the Mojave Micro Mill project would be the world’s first fully electric, zero-carbon-emission steel production facility, according to Lin Planchard, a utilities engineer with the California Energy Commission. Electricity for the steel plant will come from on-site solar and the grid, and the plant will be equipped with a carbon-capture system.

The $630 million project will recycle steel to produce rebar for use in California’s construction industry. Currently, scrap metal from California is sent to facilities in Washington, Oregon, Utah, Arizona or even Asia for recycling and rebar production. The rebar must then be transported back to California.

“By building a new rebar mill, California can fill this gap in the market by localizing our scrap recycling and rebar production and thereby reducing emissions from transporting steel by approximately 118,000 tons per year,” Planchard said.

The CEC on Jan. 21 approved a $14 million grant to PSG for long-duration energy storage (LDES) to support about 50 MW of solar power at the steel plant. The storage will be connected to the solar photovoltaic system and a microgrid.

“It will optimize the use of on-site solar energy, support critical operations during outages and contribute to the overall energy management strategy of the facility,” according to the grant request form.

The 32 MWh LDES system will be non-lithium-ion; PSG is exploring multiple chemistries including zinc that are capable of discharging for at least eight hours, company spokeswoman Michelle D’Alonzo told NetZero Insider.

D’Alonzo said the Mojave Micro Mill will electrify processes that traditionally use natural gas. Steel will be recycled at the facility by melting it in an electric arc furnace.

Nearly 90% of the mill’s carbon emissions, which are already low, will be captured, according to a project fact sheet. Captured carbon dioxide will be purified, liquified and used in applications that require CO2.

Kern County certified an environmental impact report and a statement of overriding consideration for the project in March 2024. PSG expects to break ground on the steel mill in March and start operations in early 2027.

When completed, the Mojave Micro Mill would be the only operational steel mill in the state, which hasn’t seen a new steel mill in more than 50 years.

“I love this project,” CEC Chair David Hochschild said during the Jan. 21 meeting. “This marries many of the things that we’re trying to do together: industrial decarbonization, new manufacturing, assembly and recycling facilities, and cutting-edge clean energy technologies and grid reliability.”

In addition to the CEC grant award, the Mojave Micro Mill got a boost Jan. 16 when Generate Capital announced a $200 million secured loan to PSG for the project. Generate Capital is a San Francisco-based sustainable infrastructure investment firm.

“PSG’s innovative approach demonstrates how we can significantly reduce emissions in the industrial sector while meeting the rising demand for greener building materials economically,” Generate Capital President Bill Sonneborn said in a statement.

As the most widely used metal in the world, steel is one of the largest single sources of carbon emissions, accounting for 7% of global and almost 30% of industrial emissions, Generate said in a release.

“Decarbonizing the steel market, therefore, is vital to achieving the transition to net-zero emissions,” the investment firm said.

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Texas RE Calls ITCS Recommendations ‘Very High Level’

Fulfilling the recommendations from NERC’s Interregional Transfer Capability Study will not be a simple task, a speaker said at a webinar Jan. 29 hosted by the Texas Reliability Entity. 

“I don’t expect that we’re going to have a mandate from Congress to build anything at a certain level, particularly with the administration we have now, but I don’t know for sure. Nobody does,” Mark Henry, Texas RE’s chief engineer and director of reliability outreach, said at the regional entity’s “Talk with Texas RE.” 

Henry took part in writing the ITCS as part of the ERO Executive Leadership Group; he told attendees that industry stakeholders from Texas also contributed through the ITCS Advisory Group. 

NERC filed the ITCS with FERC in November 2024 as ordered by Congress in the Fiscal Responsibility Act of 2023. (See NERC Files ITCS to FERC, Meeting Congress’ Deadline.) The commission posted the report for a 12-month public comment period Nov. 26 and will submit a report on its conclusions to Congress after the comment period concludes, along with recommendations for statutory changes, if any (AD25-4). 

The three parts of the ITCS submitted last year include a transfer capability analysis summing up the current transfer capabilities between transmission planning regions in North America, recommendations for prudent additions to transfer capability that could strengthen grid reliability, and recommendations to meet and maintain total transfer capability. A fourth document is planned in the second quarter of 2025 covering transfer capabilities and prudent additions from the U.S. to Canada and between Canadian provinces. 

NERC recommended 35 GW of additional transfer capability across the North American grid, while noting that it was still not possible to resolve all the potential energy deficiencies identified over the 10-year course of the study. 

Henry observed that these additions included a significant amount of added capacity — 14,100 MW — in ERCOT across the existing SPP-South connection (4,100 MW) and two new connections to Front Range (5,700 MW) and MISO-South (4,300 MW). These still hypothetical new connections do not represent any specific projects or locations, he said, because identifying such opportunities would be outside the ITCS’ scope. 

Henry emphasized that the ITCS should be seen as a jumping-off point for further studies and planning work, rather than a blueprint for solving the grid’s transmission problems. He pointed out that the study only posited transfer additions between neighboring regions and added that even if such additions are constructed, there is no guarantee that the regions will be able to use the full capacity, because severe weather or other conditions that lead to energy shortfalls in one region could easily affect a nearby one. 

In addition, Henry reminded listeners of the constraints imposed on the team. The FRA set NERC a deadline of just 18 months to complete the first-of-its-kind study, and the ERO had to choose its focus carefully to ensure it could finish on time. 

“With the time and resources allowed for this, we kept this at a very, very high level,” Henry said. “The first part of meeting and maintaining is just to recognize that you’re going to have to do a lot of additional work. You’re going to have to study the system in more detail and identify where you might actually accomplish some of these transfers.” 

Henry promised that NERC will continue to study the topics raised in the ITCS and refine its findings. He also urged listeners to “offer some insight” and reactions to the report through FERC’s comment process. 

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BPA Employees Confront Trump’s ‘Fork in the Road’

Employees of the Bonneville Power Administration received the same buyout offer from the Trump administration as millions of other federal workers, staff have confirmed to RTO Insider.

The move came despite the federal power marketing administration’s status as a self-funding entity and its key role in Northwestern electricity generation and transmission, flood control and regional fish conservation efforts.

BPA also operates a balancing authority area covering about 300,000 square miles, which encompasses large parts of Oregon, Washington, Idaho and Montana, and smaller sections in California, Nevada, Wyoming and Nevada.

The agency is headed by Administrator John Hairston, who has served in that role since January 2021.

The Trump administration emailed the buyout offers to about 2.3 million federal employees through the Office of Personnel Management (OPM) in a Jan. 28 message titled, “Fork in the Road.”

The message instructed recipients to type the word “Resign” into the subject line and reply if they want to accept the offer of the “deferred resignation” arrangement, with the promise they’d be provided a severance package consisting of eight months’ pay and benefits through Sept. 30, the end of the federal fiscal year. Employees were directed to respond by Feb. 6.

The email explained that the move is part of an effort to “reform” the federal workforce around “four pillars,” consisting of a policy to require most remote workers to return to their physical offices five days a week; a “performance culture” that will “insist on excellence at every level”; a “more streamlined and flexible workforce” resulting from downsizing; and “enhanced standards of conduct” intended to retain “employees who are reliable, loyal trustworthy and who strive for excellence in their daily work.”

The administration has said it expects 5 to 10% of the federal workforce to accept the offer, which observers have said looks to be modeled closely on the approach that Elon Musk used with employees at Twitter (now X) after he assumed ownership of the social media platform in 2022. Trump picked Musk to lead efforts at the unofficial “Department of Government Efficiency,” charged with reducing the size of federal operations.

‘Ridiculous Deal’

A BPA employee who spoke on background to RTO Insider said fellow staff members had expressed concern about the unexpected development but were generally “keeping their heads down” and continuing to perform their duties amid the uncertainty.

Portland-based BPA employs more than 3,000 people and manages the output from 31 hydroelectric dams in the Federal Columbia River Power System with a combined capacity of about 22,440 MW. The agency additionally operates more than 15,000 miles of transmission lines — about 75% of the Northwest grid.

Asked to comment about the potential impact of the order, a BPA spokesperson referred RTO Insider to the agency’s parent agency, the U.S. Department of Energy, for a response.

DOE did not respond to a series of questions seeking clarity on several points, including:

    • what steps DOE is taking to evaluate the operational impact on BPA and the other three PMAs of potentially high staff turnover in such a short period of time;
    • if DOE is aware of how and when OPM will inform the department and the PMAs about specific resignations at the agencies;
    • whether DOE has been provided guidance by the administration about how BPA and the other PMAs should implement the “four pillars” outlined in the buyout memo or been given a time frame for doing so; and
    • whether DOE expects BPA, the other PMAs and the Tennessee Valley Authority to be in any way insulated from the measures laid out in the email based on their self-funding models.

In an email to RTO Insider, U.S. Sen. Jeff Merkley (D-Ore.) said Trump “has no authority to offer this ridiculous deal, nor does he have authority to guarantee it. If folks take this so-called deal, they could be left high and dry by the president.

“Nonpartisan BPA professionals work hard to provide reliable, affordable electricity across the Pacific Northwest, and citizens and local businesses depend on the agency for its critical services.”

The offices of Sens. Ron Wyden (D-Ore.) and Maria Cantwell (D-Wash.) did not respond to requests for comment as of press time.

Scott Simms, executive director of the Portland-based Public Power Council — whose membership consists of BPA’s “preference” customer base of publicly owned utilities that purchase low-cost power from the agency — said the group is “gravely concerned” by the development.

“BPA is funded by Northwest ratepayers and not taxpayers, and its mission supports the Northwest economy; ensures the flow of reliable, domestically produced electricity; and provides employment in rural areas,” Simms said in an email. “I think if certain decision-makers knew that, they would do everything possible to retain this valuable workforce. This will be important for us to emphasize in the weeks and months ahead so we don’t suffer unintended consequences to our power system and our region’s communities that depend on it.”

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765-kV Lines in West Texas Inch Closer to Reality

The drive to build 765-kV lines in Texas continues to inch forward, with ERCOT and stakeholders working to provide enough information for regulators to reach a decision on which framework to go with by May 1. 

During an extra high voltage (EHV) workshop Jan. 27, ERCOT staff shared with stakeholders their “traditional” 345-kV portfolio of projects as part of its annual Regional Transmission Plan (RTP). They also included for the first time a 765-kV study, a result of their 2024 Permian Basin Reliability Plan identifying transmission facilities and import paths needed to serve existing and future demand in petroleum-rich West Texas. 

The Texas Public Utility Commission in September approved the Permian Basin plan, which included both 345-kV and 765-kV infrastructure, and $13 billion to $15 billion in initial investment. However, it deferred a decision on the import paths’ voltage levels to no later than May 1, 2025. (See Texas PUC Approves Permian Reliability Plan.) 

The commission plans to open a comment period following a Jan. 31 discussion of the two plans. The PUC will host its own EHV workshop March 7 (55718). 

“My understanding from working with commission staff is that’s just the beginning of the process,” Prabhu Gnanam, ERCOT’s director of grid planning, told the workshop’s attendees. “All of this to help set up the commissioners to be able to make a decision before May 1.” 

Either plan will require thousands of miles of transmission lines to be built through 2030. Both will cost more than $30 billion, according to initial projections, far surpassing the last project of its kind in Texas, the Competitive Renewable Energy Zone (CREZ) initiative completed in 2014. That project resulted in 3,600 miles of transmission lines, built at a cost of $6.9 billion. CREZ has freed up more than 23 GW of wind capacity in West Texas that since has been added to the grid. 

texas lines

New 345-kV lines and upgrades as part of the 345-kV plan. | ERCOT

The Texas 765-kV Strategic Transmission Expansion Plan (STEP) has an estimated construction cost of $32.99 billion and includes: 

    • 2,468 miles of 765-kV lines. 
    • 649 miles of new 345-kV lines and 1,098 miles of existing 345-kV upgrades. 
    • 324 miles of new 138-kV lines and 1,287 miles of existing 138-kV upgrades. 
    • 446 miles of existing 69-to-138-kV conversions. 

The 2024 RTP 345-kV plan has a projected construction cost of $30.75 billion and includes: 

    • 2,673 miles of new 345-kV lines and 1,913 miles of existing 345-kV upgrades. 
    • 334 miles of new 138-kV lines and 1,714 miles of existing 138-kV upgrades. 
    • 647 miles of existing 69-kV to 138-kV conversions. 

Both plans will require an estimated $5 billion annually over the six-year planning horizon, as compared to an average of $3 billion per year over 2022/24, the grid operator said. 

ERCOT says its analysis indicates the 765-kV STEP would provide “significant economic and reliability benefits” to the system because 765-kV lines are more efficient in moving power from resource-rich regional to load centers over long distances. 

The grid operator said last year it expects over 150 GW of demand, more than its current capacity, to be added to the system by 2030. Almost 50 GW of that expected demand is from the oil and gas natural load, AI and data centers, cryptocurrency mining, electrification, and hydrogen processing and related infrastructure. 

“If those large loads move from one county to the next, you’re still making that power flow across the state,” Kristi Hobbs, ERCOT’s vice president of system planning and weatherization, told the workshop’s attendees. “Then you can deal with any changes to the large loads through the subsequent underlying 345-kV network that will support it.” 

Staff conducted steady-state transfer capability, dynamic stability and system strength analyses to gain a clearer picture of how either option could support reliability and grid stability. Staff said the higher-voltage option would reduce congestion costs by $229 million annually and cut system production costs by $28 million, both annually. (ERCOT has incurred $4.27 billion in congestion costs the past two years.) 

The 765-kV STEP would reduce energy losses by 560 GWh each year, equivalent to a 128-MW thermal unit operating at a 50% capacity factor, staff said in its report. It also would yield an increase of up to 3,000 MW in power transfer capability and a 13% stability limit in West Texas. 

ERCOT used $6.2 million/mile and $4.2 million/mile as “generic cost estimates” for the 765-kV and 345-kV facilities. The 765-kV cost estimate is based on the same dollar figure used in MISO’s Long-range Transmission Plan, approved in December and including 1,800 miles of new 765-kV projects. The 345-kV number is based on the average cost for new 345-kV lines provided by transmission service providers in the Permian Basin study. 

“As we look at the additional transfer capability of the higher-voltage network, which also would be setting us up for future growth as well and giving us some breathing room … the TSPs and stakeholders that try to take outages on the system today can tell you that we have maximized or optimized the use of our current system,” Hobbs said. 

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BPA Considers Impact of Fees in Day-ahead Market Choice

PORTLAND, Ore. — The Bonneville Power Administration could face high implementation fees and operating costs under both SPP’s Markets+ and CAISO’s EDAM, but exact amounts are still in flux, and various factors could soften the financial blow, staff members said during BPA’s member meeting Jan. 29.

Rachel Dibble, vice president of bulk power marketing at BPA, told RTO Insider that implementation fees are “one part of the puzzle” in the agency’s final market decision. The agency will weigh those considerations against results of production cost models, “as well as all the other quantitative elements that weren’t included in the production cost model,” Dibble added.

“As far as the magnitude of those numbers, they probably sit more in the ongoing revenue … and costs that we would generate from participating in the market,” Dibble said. “I would expect over time, we would make back all of the money that we would be investing in getting ready to enter a market. So, we will certainly consider them, and they will be part of the decision.”

SPP estimates that Phase 2 implementation costs across the entire Markets+ footprint will be approximately $150 million, and it is unclear exactly how much of that BPA would be responsible for. Agency staff have noted it is probably about $25 million, which is more than the $2.5-$3 million in implementation fees expected under an EDAM scenario.

However, CAISO has also projected $29 million annually in grid management charge fees for the BPA BAA across all scheduling coordinators. The charge is a transactional fee applied to each transaction, and the agency itself would “bear only a share of these charges based on its activities representing its loads and resources in the market,” according to a staff presentation.

Andy Meyers, market initiatives policy lead with BPA, noted the agency itself would pay less than $29 million under EDAM, adding that “knowing exactly what Bonneville’s portion of that is an … outstanding question, but knowing kind of where the maximum is for the BAA is helpful in providing a reference point.”

By contrast, the $150 million Phase 2 costs associated with Markets+ would be financed, and BPA would repay its portion of the loan with a market transaction fee applied to each transaction made in the market. The $150 million covers staff, facilities, infrastructure, tools and applications.

BPA would pay its share of the Phase 2 funding fees on top of annual operating costs, which are projected to be between $13 million and $15 million, according to the staff’s presentation.

Still, Laura Trolese with The Energy Authority noted that BPA would pay Phase 2 funding fees on market transactions over several years, which could potentially limit the financial impact.

Spencer Gray, executive director of the Northwest & Intermountain Power Producers Coalition, asked whether BPA would still be on the hook for its share of the Phase 2 portion if the agency decides to leave Markets+ after signing a Phase 2 agreement.

BPA Chief Business Transformation Officer Nita Zimmerman responded that it “gets into the specifics of the funding agreement. That’s up to SPP to share and not me. It really depends on how far the funding agreements go as to how much we would be on the hook for and at what point.”

Likewise, BPA could not provide a definite answer to what extent the fee agreements factor in “inflationary assumptions,” following a question by Stefanie Johnson, strategic adviser at Seattle City Light.

There are still details, like specific amounts, timing and mechanics, that BPA needs to iron out before it can give stakeholders a clearer picture of how implementation fees would impact the agency under either Markets+ or EDAM. The agency is also working on estimates for internal implementation costs, staff said.

BPA has said it will issue a draft day-ahead market decision in March and a final decision in May.

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New England Gas Generation Hit a Record High in 2024

As overall power production ticked up in New England in 2024, natural gas generation reached its highest annual total in the region’s history, accounting for over 55% of all generation and 51% of net energy for load, according to new data from ISO-NE. 

Natural gas generation provided 59,883 GWh of power in 2024, up from 55,585 in 2023, which resulted in an increase in annual power sector emissions. Oil generation remained steady year-over-year, while coal generation accounted for 234 GWh, a small increase relative to 2023. 

One of the largest year-over-year changes came from a major reduction in power imported from Canada, as a massive drought caused Hydro-Québec to reduce its exports. Net imports from Canada declined for the second straight year, dropping to 6,067 GWh, less than half of the 2023 levels. 

For renewables, solar and wind generation both increased in 2024 compared to 2023, but they remain a relatively small part of the region’s resource mix. Solar increased from 3,852 GWh in 2023 to 4,554 GWh, while wind increased from 3,302 GWh to 3,517 GWh. This does not include power from behind-the-meter solar, which reduced net load by about 4,300 GWh in 2023. 

New England annual solar and wind generation (GWh) | © RTO Insider LLC

While solar has grown steadily over the past 10 years, wind power production has been largely stagnant since 2017. Despite the year-over-year increase, wind was lower in 2024 compared to 2019-2022. This could change rapidly if Vineyard Wind 1 and Revolution Wind ramp up power production in 2025 and 2026. 

Nuclear generation rebounded in 2024 after a significant down year in 2023. It has remained relatively consistent around 26,000 GWh of annual generation after the closure of the Pilgrim Nuclear Power Station in 2019. 

The decrease in imports, coupled with the spike in gas generation, contributed to the highest annual generation total in the region since 2013. The peak load in 2024 was 24,871 MW, up 828 MW from 2023 but in line with the region’s average annual peak over the past 10 years. 

Both the peak load and total annual generation remain well below the highs reached in the mid-2000s. The region hit its all-time peak in 2006 at 28,130 MW, while total generation peaked at 131,877 GWh in 2005. 

In the coming years, ISO-NE’s peak load and overall generation requirements are projected to exponentially increase with heating and transportation electrification. The RTO projects the peak load to increase by about 10% by 2033, coupled with a 17% increase in electricity consumption. (See ISO-NE Predicts 10% Increase in Peak Demand by 2033.) 

These increases will likely accelerate in the years prior to 2050. ISO-NE projected in its Economic Planning for the Clean Energy Transition study that the region’s peak load will reach 60.8 GW by 2050. Massachusetts’ 2050 Decarbonization Study projected a more modest 57 GW. 

New England annual net imports (GWh) | © RTO Insider LLC

As demand increases, the states will need to find a way to reverse the increase in gas generation to meet their climate goals for 2030 and beyond. ISO-NE has expressed interest in establishing new market mechanisms to support low-carbon resources and dispatchable resources, but the states have been slow to pursue these options. 

Beyond emissions concerns, there are physical constraints to how much more gas generation the region could add to meet rising demand, particularly during the winter. Gas utilities reserve much of the pipeline capacity into the region in the winter to meet heating needs, limiting gas generation during these periods. 

In 2023, Enbridge proposed a significant pipeline expansion project, intended to help ease some of the region’s gas constraints. The company marketed the project to meet growing demand from generation and local distribution companies. (See Enbridge Announces Project to Increase Northeast Pipeline Capacity.) 

It has not filed the project with FERC, and it told a municipal utility in May that it is “looking to get signatures on the precedent agreements, and at that point, we will file with [FERC].” 

However, Enbridge and the gas utilities could face a challenging regulatory environment to approve contracts for the project in Massachusetts, where regulators are pushing the utilities to transition away from natural gas in accordance with the state’s decarbonization requirements. 

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MISO Unveils Later Timeline for Queue Processing Restart

MISO is pushing back a restart of its swamped generator interconnection queue by a few months while it tries to study through the backlog with tech company Pearl Street.

The RTO now plans to finish the first phase of studies on the 2022 batch of project proposals before it begins studying the 2023 class in May. It won’t begin analyzing 2025 entrants until the fourth quarter. However, MISO hopes to have all projects striking interconnection agreements over 2026, with the 2022 cycle proceeding in the second quarter, 2023 in the third quarter and 2025 by the end of 2026.

Last year, MISO tentatively scheduled the 2025 cycle of queue projects to begin in the third quarter. It also said it would begin studying the 123 GW of 2023 interconnection requests in February. (See 2023 Queue Cycle Delayed into 2025 as MISO Seeks Software Help on Studies.)

MISO skipped acceptance of a 2024 queue class altogether. The RTO hasn’t processed a new queue cycle in more than a year, saying it needs to introduce study automation and implement a megawatt cap to make processing requests less daunting. (See MISO to Skip 2024 Queue Cycle While it Automates Study Process with Tech Startup.)

It is betting that Pittsburgh-based tech startup Pearl Street’s SUGAR (Suite of Unified Grid Analyses with Renewables) can get its overtaxed queue down to a one-year process.

Pearl Street and MISO are automating several aspects of the queue, including the studies that select network upgrades and estimate costs, study reports, and the process behind power flow model building, dispatching and solving.

In a teleconference Jan. 28, MISO’s Ryan Westphal told the Interconnection Process Working Group that the RTO is “testing and getting things tuned in” on the automated work.

Westphal said that while MISO and Pearl Street have made “significant progress” on implementing SUGAR, they “need a little more time” to refine the process and make it more user friendly as stakeholders have requested.

He said that by Feb. 10, MISO will begin using Pearl Street in earnest on the proposals that entered the queue in 2022. It hopes to finish the first phase of interconnection studies for the 2022 cycle by early May.

Westphal said MISO is choosing to complete the 2022 cycle’s first phase studies before it starts on 2023’s class to limit ambiguity in study results. He said a prior cycle’s resources become assumptions in future study cycles, so MISO should avoid study overlap. The sheer size of the 2022 and 2023 queue cycles — 171 GW and 123 GW, respectively — also makes some separation a wise call.

“The 2022 cycle is large, as everyone remembers, so it’s really prudent to get it through the queue,” Westphal said.

Westphal said at this point, MISO plans to kick off the 2022 cycle on Feb. 10 and the 2023 cycle on May 5. The RTO hopes the technology can help it shrink the first phase of studies to 90 days.

It further estimates that SUGAR will reduce time spent on the 2022 and 2023 cycles by anywhere from 270 to 365 days, a “massive engineering time savings.”

“We have to move through the backlog to get through to the place we want to be,” Westphal said. He predicted “a lot of work” and MISO continuing to process simultaneous cycles until it can cut its queue down to a one-year interconnection process.

“We think that SUGAR gives us the best chance to do that,” Westphal said. “We’re hoping this is a big piece of us being able to achieve a one-year queue process.”

The RTO also hopes that SUGAR can speed up the first phase of interconnection studies in particular so its engineers can devote more attention to the more intricate, back-end studies of the queue, Westphal said.

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Global 2024 Energy Transition Investments Estimated at over $2T

Worldwide investments in the energy transition totaled $2.1 trillion in 2024, BloombergNEF reports.

While it is the first time BNEF calculated the investments at greater than $2 trillion in its annual report, the 11% year-over-year growth was less than in the preceding three years, which saw annual increases of 24% to 29%.

China dominated the global tally with $818 billion. The United States was a distant second at $338 billion, and the other eight nations in the Top 10 list of economies ranged from $109 billion (Germany) to $29 billion (Japan). The 27 EU nations totaled $381 billion, and all other nations combined for $333 billion.

The bulk of the spending was in three sectors: electrified transport ($757 billion), renewable energy ($728 billion) and power grids ($390 billion).

Investment in the remaining sectors (carbon capture and storage, clean industry, clean shipping, electrified heat, hydrogen, nuclear) accounted for just 7.4% of total investments and collectively was 23% lower than in 2023.

This demonstrates the challenge of scaling up “emerging” clean technologies, the authors wrote. The exception was energy storage, which jumped 36% to a record $54 billion investment despite the headwinds facing it.

energy

China dominated global investment in the clean energy transition in 2024. | BloombergNEF

BNEF also notes the record level of investment still is far short of what is needed to reach net zero by 2050.

Albert Cheung, deputy CEO of BNEF and lead author of “Energy Transition Investment Trends 2025,” said in a Jan. 30 news release:

“Our report shows just how much growth we’ve seen in the energy transition over the past few years, despite political uncertainty and high interest rates. There is still much more that needs to be done, especially in emerging areas like industrial decarbonization, hydrogen and carbon capture, in order to reach global net-zero goals. True partnership between the private and public sectors is the only solution to unlock the potential of these technologies.”

Along with energy transition investment, the report examines three other types of funding: clean energy supply chain investment, climate-tech equity finance and energy transition debt issuance.

    • Supply chain investment — new factories commissioned in 2024, mines and battery metal processing facilities — totaled $140 billion, down from $145 billion in 2023. Despite efforts to move supply chains away from mainland China, it still accounted for 81% of the total.
    • Climate-tech companies raised $51 billion in private and public equity in 2024, a 40% drop from 2023 that BNEF attributes in part to artificial intelligence startups competing for funding. Clean power and transport companies accounted for the majority of equity, $32 billion.
    • Debt issuance rose 3% to $1 trillion in 2024. The United States ($206 billion) and China ($169 billion) were the largest markets by a wide margin and were 5% and 13% higher respectively than in 2023. European issuances dropped 7% year over year while volume in the Middle East/Africa was down 35%.
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NYPA Finalizes Road Map for Renewables Development

The New York Power Authority has finalized a plan to begin executing in its expanded role as a renewable energy developer. 

NYPA said it is pursuing 37 solar and storage projects totaling 3 GW of nameplate capacity, most of them in partnership with private-sector developers. 

The final plan is noticeably smaller than the draft plan offered in October 2024, which envisioned 40 proposals rated at 3.5 GW. NYPA officials had cautioned at the time that there would be substantial attrition among that initial list of proposals, as there would be with any list of early-stage renewable energy projects. 

Public power advocates have been hoping for a 15-GW road map and have been sorely disappointed with NYPA’s much lower ambition for its first tranche. With release of the final plan, they renewed their call for the ouster of CEO Justin Driscoll. 

During a budget hearing Jan. 28, Driscoll faced some pointed questioning by legislators who also had hoped for more from NYPA, which until recently had limited itself to small solar and battery projects, often in cooperation with other entities. 

In 2023, they and like-minded legislators gave the U.S.’ largest state-owned power entity expanded development powers as private-sector efforts to decarbonize New York’s power grid were proving to be slow and expensive. 

The idea was that without a profit motive, NYPA could accomplish the task at lower cost to New Yorkers, who already pay some of the highest electricity rates in the U.S. and are looking at significant increases as aging power infrastructure is expanded or replaced. 

The move would also democratize energy, they hoped, giving the public a greater voice in how its state is powered. 

The initial interaction of this vision, the Build Public Renewables Act, never made it into law; the version that subsequently was enacted is less ambitious or more achievable, depending on one’s perspective. 

Driscoll did not bend under questioning, telling legislators that NYPA is proud of its freshman effort. Three gigawatts is only the first tranche, he said. 

“We’re going to be amending the plan that we just approved today to add additional projects within the next six months. … This is a long journey toward achieving these goals, but we think we’re playing a significant role, along with others.” 

Driscoll noted that the three projects that dropped out of the draft plan are not dead; they are just moving forward separately from NYPA. 

State Sen. Kevin Parker (D), chair of the Energy and Telecommunications Committee, asked Driscoll what NYPA needed from the legislature to help it move forward. 

The requirement that NYPA own at least 51% of joint projects has caused some setbacks, Driscoll responded. 

“We’re finding that some developers don’t want to have a minority interest with us,” he said. 

The coalition Public Power NY ripped into this idea.  

“Justin Driscoll’s suggestion to strip the public ownership requirement out of the Build Public Renewables Act shows he is unfit to serve as NYPA CEO and not accountable to New Yorkers, legislators and labor demanding NYPA build 15 GW of renewables, but instead serves the interest of private energy developers,” it said in a press release. 

Other legislators wanted to know about progress toward another mandate placed on NYPA in the same 2023 law: retirement of its 11 small natural gas power plants by 2030, if grid resource adequacy allows. 

NYPA is making progress and on schedule to meet the May 2025 deadline to report its plans, Driscoll said. It has reached the framework for a potential agreement with developers who want to convert two of the peakers into battery facilities and is in similar negotiations on three others. 

NYPA generates up to a quarter of the state’s electricity, mainly through huge hydropower projects that harness the outflow of two of the Great Lakes; it operates a third of the state’s high-voltage transmission; its pumped hydro facility is by far the largest energy storage system in New York; and it is 94 years old. 

A PPNY activist and an NYPA executive who spoke separately to NetZero Insider after release of the draft plan in October laid out a classic chicken-and-egg impasse: 

PPNY: NYPA could use its strong bond rating to boost the energy transition at a lower cost.  

NYPA: Our bond rating is strong because we operate judiciously. 

PPNY: NYPA should concentrate less on preserving its bond rating and more on preserving the planet. 

NYPA: Our ability to develop planet-saving renewables depends on our strong bond rating. 

This week’s events suggest the two sides will have to agree to disagree a while longer.