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December 24, 2024

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ISO-NE Stakeholders Respond to Potential Long-term Transmission RFP

Regional stakeholders widely support the New England States Committee on Electricity’s (NESCOE’s) proposed procurement of transmission solutions in Maine and New Hampshire but have differing views on the scope and format of the solicitation, according to public comments published Dec. 2

The proposed transmission solicitation would be the first to emerge from the longer-term transmission planning (LTTP) process, which NESCOE developed in collaboration with ISO-NE and FERC approved in July. (See FERC Approves New Pathway for New England Transmission Projects.)

The process allows NESCOE to identify a transmission need and direct ISO-NE to issue a request for proposals. It also includes a default cost allocation method in which the costs of a selected project would be regionalized by load, while NESCOE also could provide an alternative cost structure or opt to terminate the process.

In October, NESCOE told stakeholders it plans to focus the first LTTP solicitation on increasing the capacity of two interfaces in Maine and New Hampshire, which ISO-NE estimates will be overloaded by the mid-2030s. In a letter to ISO-NE, the states also expressed interest in projects that would help “facilitate the integration of additional generation resources located in northern Maine.” (See New England States Seeking Increase of North-South Tx Capacity.)

NESCOE asked for feedback on how to successfully achieve these goals, and said it still is considering whether it should expand the RFP to include “a requirement for solutions that extend farther north into Maine.”

“While such a requirement would further facilitate the transfer of cost-effective power across these interfaces, NESCOE seeks to avoid an overly prescriptive scope that may hinder the success of a potential RFP,” NESCOE added.

Clean Energy Groups

In joint comments, RENEW Northeast, the American Council on Renewable Energy and American Clean Power said NESCOE’s October memo is “an important first step … that will unlock additional renewable energy sources in Maine and reduce curtailment of existing resources.”

The clean energy groups said the RFP should be structured to encourage competition and be open to a range of technologies, “including the use of grid-enhancing technologies and high-performance conductors, as well as storage that performs a transmission function.”

Because the RFP will not allow partial solutions to the identified needs, “NESCOE should carefully consider the minimum requirements it identifies,” the groups wrote, adding that “allowing for a comprehensive solution to be comprised of discrete segments or sections could provide additional flexibility for meeting transmission needs.”

For future iterations of the LTTP process, the groups recommended ISO-NE and NESCOE adopt “a forward-looking solicitation schedule to provide project developers with longer-term market visibility.”

Advanced Energy United advocated for adequate flexibility to enable non-incumbent transmission developers to meaningfully participate in the process. The trade association said breaking the solicitation into multiple RFPs may enable more participation, but said a multi-RFP format should be pursued only if it does not hurt the timeline or the likelihood of success.

Hydro-Québec said the solicitation will be essential for reducing congestion and wrote that the “resulting transmission solutions will optimize the use of existing and future resources.”

The company touted the potential of its hydro resources to help balance renewables in New England and urged the region to consider “market reforms to complement and optimize future transmission solutions,” including the elimination of exit fees on electricity exported from New England to Québec.

“Market structures should be created and implemented that properly compensate clean and dispatchable resources and long-duration storage to support the integration of significant volumes of renewable generation into the New England system,” Hydro-Québec wrote.

Multi-day energy storage developer Form Energy said its batteries could help address constraints on the interfaces by absorbing energy when the interfaces are constrained and discharging when capacity is available.

Incumbent Transmission Owners

Eversource and Central Maine Power (CMP) both advocated for a defined, clear RFP scope to maximize the likelihood of success.

“A broad RFP seeking large, complex projects may limit the quality of the solutions proposed because bidders may be hesitant to dedicate significant resources to sufficiently developing very large projects,” Eversource wrote. “A targeted RFP is more likely to be successful and would not foreclose the possibility of pursuing a larger transmission expansion program via a sequence of several additional RFPs over time.”

CMP expressed concern that allowing projects to address needs in Northern Maine could overlap with a separate upcoming transmission procurement by the state of Maine and could delay Maine’s solicitation.

National Grid asked for more clarity around how projects will be evaluated and urged the RTO to “adopt and make known a relative weighting of evaluation criteria.”

The company also recommended “that NESCOE define the need to focus on renewable energy deliverability rather than interface limits to give participants greater flexibility in solution development and provide customers with the optimal solution.”

In contrast to CMP and Eversource, Vermont Electric Power Co. (VELCO) and Grid United submitted joint comments advocating for “flexible definitions to encourage a diverse range of innovative responses.”

VELCO and Grid United have proposed a $2.5 billion transmission project connecting New England, Québec and potentially New York, which is intended to increase interregional transmission capacity, reduce congestion and enable the interconnection of new renewables.

“We would respectfully request that NESCOE give strong consideration to this project for its second LTTP solicitation,” the companies wrote.

Non-incumbent Transmission Developers

Non-incumbent transmission developers, including NextEra Energy Transmission (NEET), LS Power and Con Edison Transmission (CET), stressed the need to allow bidders to include upgrades within an existing right of way.

“Allowing bidders to submit transmission solutions that include new or upgraded incumbent-owned transmission facilities and that solve for discrete needs will eliminate unnecessary obstacles to the development of competitive, innovative and cost-effective transmission solutions,” NEET wrote.

To make this RFP a competitive success, it should be clear that the need for new infrastructure defined in the RFP is outside of the [right of first refusal] rights of incumbent transmission owners,” CET wrote.

CET called for “an ample window” for developers to submit proposals, while LS Power advocated for shorter application and evaluation periods. ISO-NE has outlined a six-month application window, followed by a yearlong review process. LS recommended a 60‐ to 90-day application window and a 6-month evaluation period.

Consumer and Environmental Advocates

A coalition of environmental nonprofits said the RFP should explicitly consider potential interconnections of offshore wind upstream of the selected interfaces.

“Focusing solely on the potential integration of 3,000 MW of new onshore generation from northern Maine could result in a lack of grid transfer capacity for offshore wind and other resources that interconnect in Maine,” the coalition wrote.

The groups also stressed the need to move the process as quickly as possible and said NESCOE “should consider the possibility of initiating a second solicitation before the completion of the first.”

The Acadia Center submitted additional comments advocating for flexibility in potential solutions, a priority for using existing rights of way, and consideration of benefits related to increased interregional transmission capacity and offshore wind compatibility.

The Massachusetts Office of the Attorney General and the New Hampshire Office of the Consumer Advocate submitted joint comments advocating for a greater role for consumer advocates in the process.

“The Consumer Advocates seek to enhance our ability to participate more proactively in the LTTP process and to be included in critical discussions at key decision points to assure ratepayer interests are effectively represented and meaningfully considered,” the offices wrote.

Synapse Energy Economics, representing the Maine Office of the Public Advocate and nonprofit energy buying consortium PowerOptions, echoed the calls for a “flexible approach” to maximize competition.

“Synapse encourages NESCOE to include a recommendation that bids utilize alternative transmission technologies and particularly storage options when demonstrated to be cost-effective,” the company wrote.

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Meta Seeks Nuclear Partners; AWS Boosts Efficiency

Meta and Amazon Web Services continue to search for ways to meet their data centers’ growing power demand, requesting proposals for nuclear reactor construction and announcing new efficiency measures. 

Meta said Dec. 3 it wants to add 1 GW to 4 GW of new U.S. nuclear generation capacity by the early 2030s to help meet its AI innovation goals and sustainability objectives. It said it is taking an open approach with its RFP so it can partner with others in the industry to bring new nuclear generation online. 

AWS said Dec. 2 it has designed new data center components to support innovation with artificial intelligence and boost the energy efficiency of its facilities. It said this simultaneously will support the next wave of generative AI, increase computing power 12% and improve the availability and efficiency of the data centers. 

Meta’s announcement is Big Tech’s latest embrace of nuclear power, which holds the potential to supply large amounts of baseload emissions-free electricity — if new reactors can be built quickly, affordably and in large numbers. 

Microsoft, Google and Amazon earlier in 2024 announced deals to run their facilities on nuclear power. In November, media outlets were abuzz about a report that Meta’s plan to build an AI data center next to an existing nuclear plant was thwarted by the presence on-site of a population of rare bees that could be disrupted by the construction. 

So Meta is looking elsewhere to meet its parallel goals of reducing its carbon footprint and increasing its computing power, an effort that already has yielded more than 12 GW of renewable energy contracts for its operations. 

“Supporting the development of clean energy must continue to be a priority as electric grids expand to accommodate growing energy needs,” it said in its announcement. “At Meta, we believe nuclear energy will play a pivotal role in the transition to a cleaner, more reliable and diversified electric grid.” 

Meta explained it is engaging projects earlier in the process because nuclear generation is more expensive, takes longer to build, faces more regulatory oversight and has a longer operating lifespan than other generation technologies. 

It said: “We are looking to identify developers that can help accelerate the availability of new nuclear generators and create sufficient scale to achieve material cost reductions by deploying multiple units, both to provide for Meta’s future energy needs and to advance broader industry decarbonization.” 

The growth of power-intensive AI and the data centers in which it exists has been presented as a seismic change, and one the U.S. power industry is not prepared to meet. 

In the past several months, for example, Goldman Sachs predicted a 160% increase in data center demand by 2030. EPRI predicted data center demand could more than double to as much as 9% of U.S. electricity generation by 2030. The U.S. Department of Energy predicted total U.S. demand could grow 15 to 20% in the next decade. S&P Global predicted a need for 50 GW of new generation capacity by 2030, with accompanying upgrades in transmission — total cost $75 billion. 

Not everyone is convinced the increase in electric demand from data centers will be so steep, however — the sector may not grow as expected, or technology improvements could reduce the power consumption of the hardware. 

This latter scenario is the focus of the AWS initiative. 

The new data center components announced Dec. 2 incorporate improvements in power, cooling and hardware design. They will be used in new U.S. data centers starting in early 2025; some existing facilities already have been retrofitted. 

The upgrades include: 

    • Simplified electrical and mechanical designs reduce the required number of conversion and distribution processes, each of which is a point of inefficiency, energy loss and potential failure. 
    • Backup power is moved closer to the server racks, reducing the number of cooling fans needed. 
    • Novel liquid-to-chip mechanical cooling solutions are integrated with air cooling systems to maximize performance and efficiency while minimizing cost. 
    • AI is used to predict the most efficient way to position racks, reducing the amount of power that is stranded, unused or underused. 
    • In-house innovations in power delivery are expected to yield a 6X increase in rack power density within two years and an additional 3X increase further in the future. 
    • Telemetry tools provide real-time diagnostics and troubleshooting to optimize operating conditions. 

Prasad Kalyanaraman, vice president of infrastructure services at AWS, said in the news release: “These data center capabilities represent an important step forward with increased energy efficiency and flexible support for emerging workloads. But what is even more exciting is that they are designed to be modular, so that we are able to retrofit our existing infrastructure for liquid cooling and energy efficiency to power generative AI applications and lower our carbon footprint.” 

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NYISO Energy Costs up in Q3 2024

The NYISO energy market performed competitively in the third quarter of 2024, with all-in prices ranging from $42/MWh in the North Zone to $72/MWh in New York City, a decline of 4 to 14% from the same period in 2023, according to the Market Monitoring Unit’s third-quarter State of the Market report.

Presenting to the NYISO Installed Capacity Working Group, Pallas LeeVanSchaick, vice president of MMU Potomac Economics, said that even though all-in prices were slightly down, energy costs generally were up by 4 to 26% in most areas, despite relatively flat natural gas prices compared to 2023. The MMU found that the driver was higher emissions costs: Regional Greenhouse Gas Initiative carbon prices rose by 78% between 2023 and 2024, adding $4 to $5/MWh to energy prices.

The exception to this was in the Long Island zone, which benefited from additional offshore wind and imports across the Cross Sound Cables.

A graph of all-in prices by region comparing Q3 of 2022-2024. There was a sharp decline in energy prices (light blue) caused by a decrease in natural gas prices. Overall prices are still much lower than they were two years ago. | NYISO

“There was an outage of one of the 354-kV circuits into Long Island which would tend to make prices higher,” said LeeVanSchaick. “But on the other hand, imports over the Cross Sound Cable increased a lot due to higher availability in 2024 … so you actually saw a drop in prices on Long Island despite a significant outage there.”

Capacity costs fell by 29 to 39%, depending on the zone, because of lower demand curve reference points, reduced locational capacity requirements and a lower peak load forecast.

“Congestion rose modestly from the previous year but remained low, marking the second-lowest level for a third quarter since 2014,” the report says.

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MISO to Skip 2024 Queue Cycle While it Automates Study Process with Tech Startup

MISO has officially decided it will forgo acceptance of a 2024 queue cycle of projects while it works with Pearl Street to automate interconnection studies.

MISO announced during a Dec. 3 Interconnection Process Working Group teleconference that it will close its currently open queue application window sometime in the third quarter of 2025 to begin a freshly automated study process on submitted projects.

MISO’s Ryan Westphal said staff and Pittsburgh-based Pearl Street Technologies have worked diligently on standing up an automated study process, paying attention to how the program selects network upgrades and estimates upgrade costs.

“Determining the network upgrade is one of the most time consuming pieces of the queue. We’re trying to distill that down into something that’s workable, reasonable and fast,” he explained.

Westphal said MISO will introduce Pearl Street’s SUGAR (Suite of Unified Grid Analyses with Renewables) software to “finish off” studies beginning with the 2022 cycle of project entrants. He said MISO will not rebuild its study models using SUGAR for the 2022 cycle, leaving that to subsequent queue classes. Instead, Westphal said the software will help finalize network upgrades and associated cost estimates.

MISO plans to begin using the software in earnest and “start from scratch” on model-building, Westphal said, in the first quarter of 2025, when it kicks off studies on the 123 GW of submittals that entered under the 2023 cycle. He predicted a busy January for MISO.

“We do have a pretty robust I would say, first draft of what will work,” Westphal told stakeholders. “With everyone’s participation and help, we can make this even better than what we have today.”

The grid operator originally said it would postpone a possible 2024 cycle while it waits on FERC approval of an annual megawatt cap on its queue. (See 2023 Queue Cycle Delayed into 2025 as MISO Seeks Software Help on Studies.)

MISO filed Nov. 21 to implement a 50% peak demand cap on the project submittals it will accept into its interconnection queue annually (ER25-507). The RTO has said it needs the cap to limit project proposals year to year, making for more realistic study outcomes and potentially reducing network upgrade costs.

MISO also promises to debut a special brand of faster interconnection processing for projects needed for resource adequacy. (See MISO Outlines Plan on Fast-track Queue for Resource Adequacy.)

For the 2025 cycle, MISO will use SUGAR to conduct pre-queue, “quality assurance” technical checks of applicants to test whether projects are feasible, Westphal said.

“Right now, the technical work is done sort of manually, by an engineer,” he said, adding that SUGAR should allow for “near instantaneous” checks.

Westphal also said MISO likely could accommodate stakeholders’ requests to provide a primer on how files and supporting documents should be submitted under the new automated study process.

He said under SUGAR, MISO’s input files still would be available to interconnection customers so they’re able to conduct their own analyses and look for alternative mitigations to upgrades.

Westphal predicted the SUGAR software will be in use in MISO for years and evolve over time with improvements.

“We’re hopeful that it’s a long-term partnership on this tool,” he said.

Pearl Street has said it is “thrilled” to partner with MISO and explained that a pause while MISO incorporates the software is regrettable but necessary.

“Any delay in the schedule is always unfortunate, but we see this as an investment to enable a truly transformative payoff: a fast, repeatable and transparent process that all interconnection stakeholders will ultimately benefit from. Let’s move some projects through the queue!” the company said in a statement in September.

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FERC Upholds MISO Sloped Demand Curve, Lets Opt-out Provision Stand

FERC was not persuaded by environmental nonprofits, utilities or Mississippi regulators to order MISO to rework the sloped demand curve it’s been cleared to use in the spring capacity auction.  

The commission issued a Dec. 3 order, refusing all rehearing requests tied to the demand curve’s opt-out provision, elimination of a clearing price cap and the curvature itself (ER23-2977).  

Starting in 2025, LSEs that decide to opt out of the auction and sloped demand curve must obtain more capacity than strictly necessary to meet MISO’s one-day-in-10-years system reliability standard. The rule is a feature of the new curve and applies an “X% adder” — which changes yearly — beyond strictly necessary load obligations in an attempt to create congruence between LSEs that participate in the auction and are subject to the sloped demand curve and LSEs that opt out of the auction by assigning them similar reserve requirements. (See FERC Approves Sloped Demand Curve in MISO Capacity Market.)  

The Sierra Club, Natural Resources Defense Council and the Sustainable FERC Project argued over the summer that it’s unfair for the RTO to require utilities that opt out to procure capacity beyond resource adequacy needs. (See Environmental Groups Seek Rehearing of MISO Sloped Demand Curve.)  

But FERC said it’s appropriate for MISO’s sloped demand curve plan to place a value on incremental capacity above a loss of load requirement. As such, the commission said LSEs that choose to opt out shouldn’t “be exempt from contributing to these incremental reliability benefits.”  

“LSEs that opt out of the auction are not also opting out of the overall resource adequacy construct, which, as MISO notes, is crafted as a ‘risk-sharing pool across all LSEs, regardless of the LSE’s choice of participation model,’” FERC decided.  

The commission pointed to a previous finding that “a downward-sloping demand curve provides a good indication of the incremental value of capacity at different capacity levels” and that “incremental capacity above the [reserve margin] is likely to provide additional reliability benefits.”  

FERC said MISO’s opt-out as its stands neither motivates LSEs to participate in MISO’s voluntary capacity auctions nor incentivizes bowing out.   

FERC disagreed with the nonprofits that MISO is obliged to offer a “truly compelling justification” before it forces LSEs to buy more capacity than necessary to meet its reliability targets. The commission also said it is not MISO’s concern if incremental capacity procured outside the auction is more expensive than incremental capacity procured within the auction — a theoretical argument of the nonprofits.  

“While public interest organizations would prefer an opt-out mechanism that considers parity of cost of incremental procurement rather than parity of quantity, we do not need to evaluate the relative reasonableness of such a mechanism, given that we continue to find MISO’s proposed design to be just and reasonable,” FERC explained.  

The commission also decided MISO remains free to terminate its current 1.75-times-the-cost-of-new-entry (CONE) annual price cap for local resource zones. Transmission-dependent utilities in the Midwest had argued that MISO should have preserved the annual cap to discourage excessive prices and protect consumers. 

FERC’s refusal leaves MISO using a setup where the total annual price for a local resource zone could reach as high as four times the CONE, depending on whether capacity shortages occur in all four seasons of the auction.  

FERC said the annual cap was necessary under the previous vertical demand curve because even an “extremely small,” 1-MW shortage could have prices shooting up to CONE in all four seasons. Conversely, FERC said the sloped curve should return more gradual increases in shortage pricing that are commensurate with the missing capacity quantities.  

FERC said it’s “extremely unlikely” MISO would experience shortages in all four seasons, and if it did occur, the four-times-CONE clearing prices would properly reflect “unprecedented and severe capacity shortages.” The commission also dismissed as speculative the utilities’ argument that price protections are needed because a sloped curve would introduce the potential for more erroneous market results.  

Finally, FERC rebuffed arguments from the Mississippi Public Service Commission that it shouldn’t have accepted the sloped curve because it supported MISO’s vertical demand curve in past dockets.  

FERC said it never foreclosed MISO’s ability to adopt a sloped curve just because it found a vertical curve reasonable at the time and it “expressly left open the possibility that MISO could adopt a different market design if it so desired.”  

FERC noted that in the past, it has found both sloped and vertical demand curves practical and said it did not “change course” from its precedent regarding a sloped versus vertical curve, as the Mississippi PSC suggested.  

“Rather, this was the first instance in which MISO proposed a shift to a sloped demand curve design,” FERC said.  

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Podesta: Economics of Clean Energy ‘Have Simply Taken Over’

WASHINGTON, D.C. — David Crane opened the Department of Energy’s Deploy 2024 conference with the facts and figures of the money he and other DOE officials have helped to distribute from the Infrastructure Investment and Jobs Act and the Inflation Reduction Act over the past three years.

“We’ve committed over $95 billion in grants and loans, and with more [going out] each day,” Crane, DOE’s under secretary for infrastructure, told an audience of more than 1,800 at the Walter E. Washington Convention Center. “So, within the next few days and weeks, it will be over $100 billion and moving northwards.”

That money has gone to about 1,900 grant selectees and another 4,500 recipients of formula grants, Crane said. “And all that is tied with over $100 billion — well over $100 billion — committed from the private sector.”

Those public and private dollars have created irreversible momentum the U.S. clean energy transition, said White House Senior Advisor John Podesta, who closed the conference’s opening plenary with a call to action for the private sector facing the uncertainties of the incoming Trump administration.

Donald Trump and congressional Republicans have declared their intention to roll back the IRA and other clean energy initiatives. Chris Wright, a fracking CEO and Trump’s nominee for secretary of energy, is an unabashed advocate of fossil fuels.

But, Podesta countered, “the economics of the clean energy transition have simply taken over. New power generation is going to be clean. The desire to build our next generation nuclear is still there. The [data center] hyperscalers are still committed to powering the future with clean energy. The auto companies are still investing in electrification and hybridization.

“All those trends are not going to be reversed,” he said. “Are we facing some new headwinds? Absolutely. But will we revert back to the energy system of the 1950s? No way.”

Echoing Podesta, the buzz at the conference was upbeat. Crane noted that many of DOE’s funding opportunities have continued to draw more applicants than could be funded. The Grid Resilience and Innovation Partnerships Program was eight times oversubscribed, he said.

Crane also pitched to investors at the event that DOE-funded projects are well-vetted and derisked.

energy

David Crane, DOE under secretary for infrastructure | © RTO Insider LLC

“One of the most important things … the Department of Energy has done for the private sector is that we put immense effort into picking the best of the best in terms of projects,” he said. “Of course, any [investor] here is going to do their own due diligence, but I think it’s fair to say that if the Department of Energy has … provided a grant to a company, if we’ve provided a loan to a company, they’ve been subject to extensive due diligence, and we believe the technology that we’re financing can scale and the projects can be commercially viable.

“Treat us as like a Good Housekeeping seal of approval,” he said.

Podesta also argued that U.S. innovation in clean energy will continue to be critical to ensure the nation can compete in global markets.

“The prices of clean technologies will keep dropping, and the need to compete with the rest of the world, as they move full steam ahead on clean energy, is going to only increase and increase and increase,” he said. “Now it’s up to you, America’s clean energy entrepreneurs and clean energy companies, to lead that transition.

“We need you to keep innovating, showing the world that America leads with big ideas.” Podesta said. “We’re counting on you to carry this work forward, for the sake of your businesses, for the sake of the communities you’ve invested in, for the sake of the American people, of our economy, our security, our young people and our planet.

“Thank you for what you’re doing. Just keep doing it. Do it faster. Do more of it, and we’ll all be better off.”

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New Jersey Plans for 2025 Community Solar Solicitation

New Jersey has launched a stakeholder input campaign for its community solar program as the state prepares to solicit interest for 250 MW of capacity in 2025 after two nearly fully subscribed allocations in the program’s first 12 months. 

The New Jersey Board of Public Utility (BPU) allocated 225 MW in the fully subscribed first allocation, which the agency launched in November 2023, and an additional 275 MW of capacity in the second allocation, which was launched in May 2024, agency officials said at a Dec. 3 public hearing. The BPU said it allocated all but 4.8 MW of the available capacity in the second solicitation. 

The BPU said it will collect written stakeholder comments until Dec. 16 and review whether the program needs to be adjusted before the opening of a new solicitation in coming months. 

Most of the dozen or so speakers at the hearing, many from the solar development community, commended the progress of the program, which is a key element in the state’s goal to reach 12.2 GW of solar energy by 2030 and 32 GW by 2050. 

Yet the most salient comments focused on the future, and how the state responds to the incoming Trump administration. The president-elect has expressed opposition to renewable energy and the subsidies for solar and other sectors in the Inflation Reduction Act. 

Lyle Rawlings, president of Mid-Atlantic Solar Energy Industries Association (MSEIA) and a solar developer, asked how the BPU would “account for potential changes” in the Investment Tax Credit, which at present can cover 30% of a solar project cost. 

Industry analysts have expressed fears that the new administration will seek to shrink or delete the ITC, citing the more than 50 votes taken by Republicans in the House of Representatives in the past to repeal parts of the IRA. (See Chesapeake Solar Industry Prepares for Trump 2.0 ‘Solarcoaster’.) Trump also has said he expects to implement a wide-ranging tariff program, including a 10% tariff on China, the source of much solar equipment. 

“The tariffs and changes to the ITC could be making things much more expensive for community solar,” Rawlings said. “And if this application window incorporates a new incentive rate that does not take that into account, then a whole year-plus of development is going to be severely handicapped by that.” 

Uncharted Territory

Fred DeSanti, executive director of the New Jersey Solar Energy Coalition, urged the BPU to prepare for sector changes. “We’re in kind of uncharted territory with federal policy,” he said. “The need to remain flexible during this period, I think, is very important because we don’t know what’s coming.” 

Sawyer Morgan, a research scientist at the BPU’s Division of Clean Energy, said the BPU is not aware of any changes in the ITC and would appreciate input from the solar sector on how to address the issue. 

“At this point, we can’t account for what we do not know,” he said. “In the event that there are changes to the ITC, I would anticipate that the board would take these into account in any future evaluations. We would certainly consider any incentives to be responsive to changes in the general marketplace, and would take that into account for future registrations.” 

In response to another question about a cut in the ITC, Sawyer said “any future changes made to the ITC will be taken into account for incentives made available to future rounds of applications.” 

Pent-up Demand

Community solar projects target users who either cannot or do not want to have solar on their roofs but seek to support a clean energy initiative. To make the projects work, the developer must sign up subscribers, who commit to using the clean energy and in turn receive a credit on their utility bill, reducing the electricity cost by a set percentage. 

New Jersey had 4.98 GW of installed solar capacity in October, including 109 community solar installations that total 166,632 kW, or about 4% of the state’s installed capacity, according to BPU figures. The state has an additional 364 projects, or 522,291 kW of capacity, in the pipeline. 

The state enacted its first community solar pilot program in 2019 and its second in 2021. The first program, which attracted 252 applicants, approved 45 projects totaling 75 MW. The second pilot, which attracted 412 applications, awarded 105 projects totaling 165 MW.  

The BPU enacted a permanent program in August 2023, creating a program for community solar projects smaller than 5 MW developed on rooftops, carports, canopies over impervious surfaces, contaminated sites, landfills or bodies of water. Projects in the program are eligible for an incentive of $90/MWh (See NJ Opens Community Solar and Nuclear Support Programs.) 

Charles Coggeshall, mid-Atlantic regional director for the Coalition for Community Solar Access (CCSA), said the program is “doing well.” He attributed it in part to the “pent-up demand that was building up over several years as we were awaiting the final rules, and then ultimately, the program opening.” 

The fact that the first two solicitations under the permanent program were so well subscribed is “indicative of that pent-up demand and the kind of energy and interest by the market,” he said. 

“We believe that the pent-up demand, and sort of lowest-hanging fruit, has been kind of tapped in large part,” Coggeshall said, adding that he expects sites from now on to be “more challenging” and interconnection costs to rise as “the grid becomes kind of more constrained with regards to available places to interconnect.” 

The next few months, and “potential impacts on tax incentives and tariffs,” would indicate a preference for not rocking the boat by changing incentive levels, he said. 

Attracting Subscribers

Rawlings, of MSEIA, urged the BPU to do more to increase the percentage of low- to moderate-income (LMI) subscribers to community solar projects beyond the 51% requirement that is the current rule, and to have an “aspirational goal” of 100%. He said they could include in the ranking of applications to the program the percentage of LMI subscribers they expect to sign up and the discount the subscribers would receive. 

“We believe this will drive developers to find ways to serve more LMI customers,” he said. 

Other developers said the expected introduction in January of a consolidated billing system for new and existing projects will make it easier to attract subscribers. Since the program began, subscribers have received two bills: their regular bill plus a separate bill for their community solar subscription. (See Billing Key to NJ Community Solar Growth.) 

Supporters of a consolidated bill say it would be simpler for subscribers to understand, and its clarity would encourage potential subscribers to get involved. 

DeSanti called the introduction of consolidated billing “absolutely essential to making this program work well and to drive some cost out.” 

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Texas PUC’s Glotfelty to Resign from Commission

Jimmy Glotfelty said Dec. 4 he will resign from the Texas Public Utility Commission at year’s end, leaving the regulator two short of a full complement. 

In a letter to Gov. Greg Abbott, Glotfelty offered his resignation, effective Dec. 31, saying it has been “an honor and privilege to serve the people of Texas” as a commissioner. Also leaving at the same time will be Lori Cobos, who announced her resignation in November. (See Texas PUC’s Cobos to Leave Commission.) 

Asked to elaborate on his decision, Glotfelty told RTO Insider, “Just time to go build some infrastructure and nuclear plants in Texas. You cannot do that inside the government.” 

Glotfelty chaired Texas’ Advanced Nuclear Reactor Working Group, which wrapped up more than a year’s worth of work in November with a 78-page report meant to ensure Texas is “the energy capital of the world.” 

“We hope this is a springboard to greater, bigger, better things in the nuclear space in Texas, and this is just the beginning,” he said as he rolled out the report during the Texas Nuclear Summit. (See Texas Now Wants to be No. 1 in Nuclear Power.) 

In his letter, Glotfelty said he was “especially grateful” to lead the nuclear working group and implied that’s where his future will take him. 

“We now have a lot of work to do [to] implement its recommendations, and I remain committed to continuing the effort to support the leadership on this issue,” he wrote. 

Glotfelty told Abbott he was “proud of the work we have accomplished to address the challenges that face the Texas electric system.” He listed efforts to strengthen the ERCOT system after the disastrous 2021 winter storm, expanding the transmission system, developing an aggregated distributed energy resource pilot program, and improving the grid’s reliability.  

With the departures of Glotfelty and Cobos, the PUC will begin the new year with only three commissioners, two short of a full slate. 

Abbott appointed Glotfelty to the PUC in 2021. His term expired in September, but he has continued to serve at the governor’s pleasure.  

Glotfelty brought a long career in the energy industry to the PUC, including leadership roles with Calpine, ICF Consulting and Quanta Services. He was a founder and executive vice president at transmission developer Clean Line Energy and founded and led the U.S. Department of Energy’s Office of Electricity. Glotfelty served as policy adviser and legislative directors for several political figures, including DOE Secretary Spencer Abraham, Texas Gov. George W. Bush and U.S. Rep. Sam Johnson (R). 

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Industry Seeks Flexibility on New Supply Chain Reliability Standards

Electric industry participants asked FERC for flexibility in setting the new supply chain risk management (SCRM) standards the commission suggested in a notice of proposed rulemaking issued in September (RM24-4).  

Edison Electric Institute, Electric Power Supply Association and the National Rural Electric Cooperative Association filed joint comments Dec. 2 saying they support efforts to improve supply chain risk management practices but have qualms with FERC’s specific proposals. 

“As FERC states in this NOPR, while the global supply chain introduces risk to the security and reliability of the BPS by creating potential attack surfaces for threat actors to exploit, it also provides the opportunity for significant customer benefits such as low cost, product variety and rapid innovation,” the joint trade groups said. 

As the technology to operate the grid evolves, grid owners and operators will continue to be responsible for security, but that responsibility is shared by suppliers, vendors and manufacturers. Revisions to mandatory standards need to strike the proper balance between the responsibilities of industry and suppliers, the trade groups said. 

FERC’s proposed rule would require responsible entities to evaluate equipment and vendors to better identify supply chain risks, requiring NERC to establish a maximum time frame between when an entity performs its initial risk assessment during the procurement process and when it installs the equipment. Responsible entities would have to take steps to validate supplier claims around any risks. (See FERC Proposes Further Cybersecurity Measures.) 

The trade groups said they don’t support the commission’s recommendation that entities should reevaluate the risks of installing any piece of equipment that has sat in storage for a long time.  But they did agree with a proposal to perform periodic reassessments of vendors that consider the criticality of a service or product and changed circumstances, such as a merger or a security event associated with a supplier. 

Forcing such reassessments could prove difficult contractually with overseas suppliers, who might not be required to go through reviews, the groups said. 

While FERC stopped short of requiring responsible entities to guarantee the accuracy of information they get from vendors, the trade groups oppose overarching requirements for vendors to supply supporting evidence or independent certifications. 

“Mandatory Reliability Standards should use a risk-based approach that allows entities to determine when and what validation is required for vendor-provided supply chain risk management information based on entity-defined criteria,” the groups wrote. “This approach allows entities to focus on products and services that represent the greatest risk to reliability while minimizing the increased workload associated with validating vendor responses.” 

The trade associations asked FERC to support a risk-based approach to developing future supply chain standards, which, given the growing number of suppliers, will require scalable mechanisms to identify and address risks. 

‘Continuous Monitoring’

Amazon Web Services (AWS) also weighed in on the NOPR, urging FERC to use a risk-based approach on any requirement to restudy equipment in storage before it gets installed. AWS advised against a blanket requirement for reassessment, saying it should only be triggered by events such as a change in supplier ownership, geopolitical events or new security exploits. 

Rigid time frames could lead industry participants to miss important risks that arise right after a reassessment, while adding costs with no major benefits, AWS said. 

“Continuous monitoring of assets in production is a more effective approach to supply chain risk management by increasing visibility into potential risks and the ability to respond to emerging risks,” AWS said. “NERC should credit programs that include continuous monitoring to complement periodic full reassessments.” 

AWS urged FERC to accept the use of third-party certifications and technology solutions to help responsible entities stay on top of supply chain risk management. 

“Use of third-party certifications should be explicitly supported as a valuable aspect of risk assessment because such use leverages high-quality risk analyses and security practice verification provided by disinterested third parties,” the company added. 

‘Aggressive Approach’

The ISO/RTO Council said it supports robust supply chain risk management practices and argued that any directives to NERC should recognize that responsible entities are best suited to determine how and when to evaluate risks. 

“Neither NERC nor a NERC standards drafting team will fully understand or appreciate each individual responsible entity’s unique supply chain risks,” the IRC said. “Although NERC can develop a requirement that responsible entities identify risks and specify the timing requirements for equipment and vendor evaluations, each individual responsible entity is in a better position to understand the risks related to its unique supply chain.” 

IRC also urged FERC to tread lightly on requiring confirmation of vendor’s claims about supply chain risks because that is difficult and potentially cost-prohibitive. Any rules should give responsible entities flexibility to pick a validation process — such as a direct or third-party audit, it said. 

“This flexibility will assist compliance in the short-term,” IRC said. “Any commission directive to NERC should also encourage and drive further consideration of a longer-term evolution that would take validation responsibilities off of each responsible entity and allow for the development of third-party verification and other means to more efficiently undertake this important validation task.” 

While many in the industry argued for flexibility, the Secure the Grid Coalition, which calls itself “an ad hoc group of policy, energy and national security experts,” argued the NOPR is a small step and said FERC should do more to secure the industry’s supply chain risk management (SCRM). 

“The continued reliance on generic improvements to SCRM standards without targeted action against known risks from Chinese-manufactured transformers and other critical grid equipment leave significant vulnerabilities unaddressed,” the conservative group told FERC. “To ensure the reliability and safety of the U.S. electric grid, FERC must take a more comprehensive and aggressive approach.” 

Utilities should be incentivized to buy American products, something FERC can encourage with an aggressive messaging campaign that it is no longer satisfied with the “status quo of its entities purchasing vital assets — particularly transformers and other critical grid equipment — from hostile nations,” the coalition said. 

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NY Contracts for $4.7B of Wind, Solar Projects

New York state has executed contracts for proposed onshore wind and solar projects totaling 2,341 MW of capacity at an expected cost of over $4.7 billion.

The New York State Energy Research and Development Authority (NYSERDA) reported the contracts Dec. 3, a little over a year after it launched the state’s 2023 Renewable Energy Standard solicitation.

The 23 contracts are intended to get New York closer to its decarbonization goals and are expected to generate about 5 million MWh of electricity per year. The nominal weighted average strike price of the projects over their lifetime is $94.73/MWh, which would average about 70 cents on the average customer’s monthly utility bill.

All the projects are in upstate New York, and all but one is far removed from the New York City area, where the need for clean energy is greatest. Thanks to upstate nuclear and hydropower generation, a high percentage of northern New York’s electricity already is emissions free. The densely populated downstate area still relies heavily on fossil-fired generation.

Eliminating transmission bottlenecks to move the clean power north to south is another priority for the state.

NYSERDA President Doreen Harris said in a news release: “Today we celebrate 23 more projects that will deliver clean, sustainable energy to our state’s electric grid. New York continues to provide a reliable market for renewable energy projects, and by facilitating responsible development of these projects, we are protecting our natural resources and creating healthier communities.”

The word “celebrate” is appropriate, given events of the past 13 months.

Developers holding New York Tier 1 renewable energy certificate (REC) contracts sought inflation adjustments after the contracts became financially untenable. The state rejected the request in October 2023, prompting a mass cancellation of contracts and evisceration of the state’s renewable energy portfolio.

The 2023 Tier 1 solicitation, launched Nov. 30, 2023, was one of the state’s efforts to recover.

Importantly, the 23 contracts awarded in this solicitation are going to later-stage projects, which should limit the delay and cancellation risks that face early-stage projects. NYSERDA said several of the contracted projects already have started construction, and all are expected to be operational by 2028.

This will help the state get closer to its statutory 2030 target of 70% renewables; earlier this year, officials acknowledged they are likely to miss that goal, perhaps by a wide margin.

The upfront investment to build these 23 projects, expected to surpass $4.7 billion, will be borne by the private sector. The REC money does not start flowing to the developers until the projects are fully permitted and fully operational.

The contracts announced Dec. 3 are for the following projects and developers:

    • Dog Corners, Cordelio Power, Cayuga County.
    • Scipio Solar, Cordelio Power, Cayuga County.
    • ELP Granby Solar II, VC Renewables, Oswego County.
    • Garnet Energy Center, NextEra Energy Resources, Cayuga County.
    • Trelina Solar Energy Center, NextEra Energy Resources, Seneca County.
    • Cider Solar Farm, Hecate Energy and Greenbacker Renewable Energy Co., Genesee County.
    • Highview Solar, Cordelio Power, Wyoming County.
    • Heritage Wind, Apex Clean Energy, Orleans County.
    • Excelsior Energy Center, NextEra Energy Resources, Genesee County.
    • Little Pond Solar, Greenbacker Renewable Energy Co., Orange County.
    • Tayandenega Solar, Greenbacker Renewable Energy Co., Montgomery County.
    • Rock District Solar, Greenbacker Renewable Energy Co., Schoharie County.
    • Grassy Knoll Solar, Cordelio Power, Herkimer County.
    • Flat Hill Solar, Cordelio Power, Herkimer County.
    • Watkins Road Solar, Cordelio Power, Herkimer County.
    • Hills Solar, Cordelio Power, Herkimer County.
    • Flat Stone Solar, Cordelio Power, Oneida County.
    • Brookside Solar, AES, Franklin County.
    • Baron Winds II, RWE, Steuben County.
    • Canisteo Wind Energy Center, Invenergy, Steuben County.
    • Valley Solar, Cordelio Power, Tioga County.
    • Alle-Catt Wind, Invenergy, Allegany and Cattaraugus counties, Wyoming County.
    • Bear Ridge Solar, Cypress Creek Renewables, Niagara County.