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January 7, 2025

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After Budget, Energy Could be a Top Priority for Md. Lawmakers

When the Maryland General Assembly opens its 2025 session Jan. 8, lawmakers’ top priority is expected to be the state’s looming budget deficits, estimated at $1 billion this year, $2.7 billion in 2026 and close to $6 billion by 2030, according to state budget analysts.  

Energy, however, could be a close second, according to some lawmakers and advocates, who are preparing to introduce a range of bills, from initiatives requiring all new buildings in the state to be energy efficient and electrified to mandates for utilities to undertake comprehensive distribution system planning every three years. 

These and other potential bills were the focus of an online summit Jan. 4, hosted by a group of energy and environmental advocacy groups, including the Maryland Legislative Coalition, the Sierra Club and ShoreRivers, an Eastern Shore environmental group. 

The focus on energy comes as Maryland is looking at how to close the budget gap, meet its ambitious climate and clean energy goals, and keep utility bills low for consumers, all while importing 40% of its power from the regional grid operated by PJM. The Climate Solutions Now Act of 2022 commits the state to a 60% cut in greenhouse gas emissions, below 2006 levels by 2031, and Gov. Wes Moore (D) has set a 100% clean energy target for 2035. 

“Success in addressing environmental issues, and especially climate change, demands policies that are consistent with customer interests,” said People’s Counsel David S. Lapp, the state’s chief consumer advocate, during his keynote presentation at the summit. “Efforts to address the climate that disregard customer interests and economic justice are doomed to failure and get and give environmentalists a bad name. 

“Fortunately, many of the most effective climate policies also promote customer interests, though they may be politically challenging as they often require taking on powerful corporate interests.” 

A case in point is Del. Vaughn Stewart’s (D) Reclaim Renewable Energy Act (H.B. 220/S.B. 10), which would amend the state’s renewable portfolio standard to exclude waste incineration as a source of renewable generation.  

“It’s the simplest bill in the world,” said Jennifer Kunze of Clean Water Action, a nonprofit working with Stewart on the bill. “It just deletes two lines of code from the definition of renewable energy for the Renewable Portfolio Standard — ‘waste to energy’ and ‘refuse-derived fuel,’ both of which are different ways for describing different forms of trash incineration, and that is all the bill does.” 

But with millions in state subsidies paid to Maryland’s three major incinerators at stake, similar bills have been introduced and failed eight years in a row, Kunze said. The goal is to free up those millions to support more “actual” renewable energy, like wind and solar, she said. 

“This bill won’t create a trash crisis where we don’t have anywhere to put the trash, because it will not shut the incinerators down right away,” Kunze said. “It is part of right-sizing the waste markets and making sure that as we’re trying to move away from trash incineration, [we are] building businesses and programs that can handle our waste in more sustainable means.” 

Other bills being reintroduced in the 2025 session include: 

    • Del. Adrian Boafo’s (D) Better Buildings Act, which would require all new construction in the state to be energy-efficient and electric. Parts of the law were originally in the CSNA but were removed in negotiations to get the law passed, Boafo said. 
    • The GREEN Act, another Boafo bill, which would establish a state fund to provide no-interest loans to small nonprofits, with budgets under $1 million per year, to help them finance energy efficiency and renewable energy upgrades. The Senate has passed a version of the bill each of the past three years, and Boafo is hoping to get it through the House in 2025. 
    • Del. Andre Johnson’s (D) Utility Transparency and Accountability Act, which stalled out at the end of the 2024 legislative session. It would prohibit the state’s utilities from using ratepayer funds for political activities. ranging from direct political donations and lobbying to membership fees for industry trade associations. 

Build Battery Storage Now

The rising opposition to the Maryland Piedmont Reliability Project, a 67-mile, 500-kV transmission line, and general dissatisfaction with PJM and utility grid-planning and interconnection policies, are also driving several new bills. 

PJM has said the line is essential to prevent system collapse or blackouts in Maryland in the coming years, as coal plants in the state are retired. But opponents say the line will disrupt farmland and communities along its proposed route in Baltimore, Carroll and Frederick counties, without providing major benefits to the state.  

The Public Service Enterprise Group, the New Jersey-based utility building the project, filed an application for a certificate of public convenience and necessity with the Maryland Public Service Commission on Dec. 31. (See PSEG’s Piedmont Transmission Project Faces Opposition in Maryland.) 

Del. Lorig Charkoudian (D) is tackling the problems underlying the MPRP with the Abundant and Affordable Clean Energy Act, which aims to increase carbon-free generation in the state via a multipronged approach. First, the law would create an emergency procurement for energy storage, which would allow energy storage currently in the PJM queue to get connected in Maryland over the next three to five years, Charkoudian said. 

“If we build battery storage now, it buys us the time to think clearly about our energy future and to bring on additional clean energy and to not rush toward a somewhat reckless path of building a new gas plant before, one, we know it’s needed and, two, putting that kind of a thing on our ratepayers,” she said. 

Other provisions in the bill would revise solar renewable energy credits and introduce a competitive process for onshore wind projects, in both cases to encourage the construction of more clean energy projects in or near Maryland. It also would support the relicensing of the Calvert Cliffs nuclear plant and dedicate 75% of state sales and franchise taxes from new data centers to pay for clean energy projects. 

Del. Lily Qi (D) plans to introduce the Affordable Grid Reliability and Improved Distribution (GRID) Act, complementary legislation focused on distribution planning. This bill would require utilities to submit comprehensive distribution system plans to the PSC every three years “utilizing bottom-up load forecasting that incorporates developments in vehicle and building electrification and the goals of state and local decarbonization policies,” according to a bill summary from the summit.  

The distribution plans would have to be supported with appropriate investment strategies, as well as operational objectives that prioritize the needs of communities already overburdened with pollution from energy generation and optimize the siting of distributed energy resources.  

Sen. Karen Lewis Young (D) has two bills aimed at data center and transmission planning. The first would mandate a “robust” study of data centers’ potential impacts in the state, looking at economics, GHG emissions and energy demand.  

Lewis Young said the economic benefits and jobs predicted for specific data centers are often based on inconsistent numbers and may vary across regions. While the Maryland Tech Council has done some analysis about planned data centers in Frederick County, Lewis Young, who represents the area, wants a second opinion, with the Department of Legislative Services and the University of Maryland on board to direct the analysis. 

A second grid enhancement bill would require utilities to prioritize optimizing capacity on their existing transmission and distribution systems through grid-enhancing technologies and “other means of reducing green-field transmission construction,” Lewis Young said. 

“It will require local utility companies to submit a report to the PSC … [to] forecast load growth, their plans and resources to meet the growing demand, a list of projects they are working on with PJM and what they’re doing to connect renewable generation to their grid,” she said. 

The bill is intended to increase transparency, accountability and local input, Lewis Young said. “The thoughts … about transmission lines in Frederick County could be different from Baltimore versus Carroll or Howard. So, we need that local perspective.” 

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NYPA Files Petition with New York PSC to Save Clean Path Project

The New York Power Authority on Dec. 23 filed a petition with the Public Service Commission asking it to designate Clean Path NY as a Priority Transmission Project (PTP) under the Accelerated Renewable Energy Growth and Community Benefit Act.

The $11 billion Clean Path’s renewable energy certificate between the developers and the New York State Energy Research and Development Authority was terminated in November. (See $11B Transmission + Generation Plan Canceled in NY.) The project is a public-private collaboration of NYPA and Forward Power, which is a joint venture of energyRe and Invenergy.

It would consist of 178 miles of HVDC line between Delaware County and Queens to bring 3.8 GW from 23 new solar and onshore wind projects to New York City. The line is engineered to be bidirectional so that offshore wind could serve upstate load when needed.

The November announcement led many to assume the project was effectively dead. But “it’s important to remember that a NYSERDA contract cancellation does not equal a project cancellation,” wrote Marguerite Wells, president of the Alliance for Clean Energy New York. “As we saw with many clean energy generation projects over the last couple of years, developers continued advancing projects after a contract cancellation, and many of them have since secured new contracts. This filing shows that the idea and development of Clean Path continues.”

PTPs are projects deemed necessary on an “expeditious” basis to access and deliver renewable energy resources, and they are referred to NYPA exclusively for development.

“Expedited development of the Clean Path transmission project is critical to advancing the state’s achievement of the aggressive” mandates of the Climate Leadership and Community Protection Act (CLCPA), NYPA wrote in its petition.

But PTP designation would not save the entire project. The NYSERDA contract included the 23 new renewable facilities.

“Our proposal would accelerate development and address the state’s need to transmit upstate renewable energy directly into New York City, reducing congestion to support the decarbonization of the electric system in line with the state’s climate goals,” NYPA spokesperson Lindsay Kryzak said in a statement. “NYPA awaits a decision on its petition by the PSC.”

NYPA estimated that the project would reduce emissions and produce cost savings to ratepayers both in terms of capacity payments and congestion payments to the tune of about $6.2 billion over a 23-year period. This would help the state meet its climate goals by increasing the availability of renewable energy downstate while bypassing the relatively slow project planning processes of NYISO and the PSC, it said. It also argued that a new project would not be selected until mid-2027 at the earliest, delaying the in-service date until after 2030.

NYPA estimated that it can complete the project before 2030 if the petition is approved. It cited many planning and interconnection hurdles that are already finished or well in progress, including federal applications, NYISO interconnection studies and pre-secured fabrication slots with cable manufacturers.

It also cited NYISO’s most recent Reliability Needs Assessment that found a reliability need in New York City starting in 2033. Furthermore, NYISO estimates that by 2030 the system will transition from a summer peak to a winter peak.

The Champlain Hudson Power Express line, which will inject hydropower from Quebec to the city, should be in-service by then but is not obligated to deliver electricity to New York during the winter. 2030 is also the deadline for meeting some of the emissions targets of the CLCPA.

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PJM Capacity Market in Flux Going into 2025

Two years after PJM CEO Manu Asthana warned stakeholders that the RTO will have to move quickly to ward off a reliability crisis brewing around 2030, the Board of Managers has stated that a capacity shortage could now come as early as the 2026/27 delivery year.

PJM now heads into 2025 with several proposals before FERC seeking to rework its capacity market and generator interconnection queue, while stakeholders work on an expedited Quadrennial Review of the market and changes to resource accreditation.

Two capacity auctions are scheduled for 2025 following several delays: The Base Residual Auction for the 2026/27 delivery year is set to be conducted in July, with the auction for the following year scheduled for December. The rules for those auctions, however, remain unclear amid the ongoing stakeholder processes and pending proposals.

While those changes are being considered, consumer advocates argue there is a break between capacity prices and the ability for developers to bring new resources online to lower prices. In a complaint to FERC, they make a case that so long as that gap persists, PJM’s Reliability Pricing Model (RPM) cannot deliver capacity in a just and reasonable manner. (See Consumer Advocates File Wide-ranging Complaint on PJM Capacity Market.)

One of the pillars of the advocates’ complaint is that capacity supply is being suppressed by several categories of resources being exempt from the requirement that all resources offer into the market, which would be addressed by a PJM proposal to expand the requirement to intermittent, hybrid and storage resources. Some stakeholders have advocated for the change on the basis that capacity is being withheld from the market, while renewable developers have pushed back, saying that making a change of this magnitude on such short notice could have a chilling effect on development.

Another PJM proposal would model the output of the Brandon Shores and H.A. Wagner generators outside Baltimore as supply. Both units left the market for the 2025/26 auction to operate on reliability-must-run agreements, which the Independent Market Monitor said was a major component in the substantial increase in clearing prices (ER25-682). (See PJM Market Monitor Releases Second Section of 2025/26 Capacity Auction Report.)

The proposal would also establish criteria for determining when an RMR unit can be counted as supply, limiting the practice to the next two delivery years and only applying to resources that can meet the needs of the transmission constraints they are being retained for while also retaining operational flexibility to provide capabilities akin to capacity. PJM told FERC it intends to pursue a more long-term solution to how RMR agreements interact with the capacity market.

The third prong of the filing would add language stating that resources that are categorically exempt from the requirement that market sellers offer into the capacity market do not hold “safe harbor against allegations of the exercise of market power that benefits an affiliated portfolio of market manipulation power.”

Queue Proposals

Another pair of filings propose to create expedited processes for new resources to proceed through the interconnection queue.

The Reliability Resource Initiative (RRI) (ER25-712) would allow 50 resources to be added to the Transitionary Cycle 2 queue, which PJM is about to begin studying. Projects would be scored and prioritized based on their capacity and effective load-carrying capability (ELCC) ratings, impact on zones facing capacity shortfalls, constructability and transmission headroom availability. PJM said it is meant to be a “one-time” solution that could allow about 10 GW of unforced capacity to quickly come online to address projected capacity shortfalls toward the end of the decade.

The RRI has been met with a mixed response from stakeholders, with some generation owners saying it would allow them to bring shovel-ready projects and uprates to existing resources to the market, while those with projects that have been in the queue for years have argued it would amount to cutting in line and discriminatory treatment. (See PJM Stakeholders Wary of Expedited Interconnection Proposal.)

PJM has also proposed changes to its surplus interconnection service (SIS) process, which allows accelerated interconnection studies on projects co-located with existing resources that would improve their average output without exceeding the site’s capacity interconnection rights (CIRs). The changes would loosen the eligibility rules to allow projects that would require network upgrades, consume transmission headroom or result in “material adverse impacts” on short circuit and thermal limits. It would also expand SIS to apply to planned resources not yet completed.

And PJM plans to file in January yet another proposal, to create a parallel process for resources that would replace a deactivating generator at the same point of interconnection. The new process would take advantage of CIRs from deactivating generators to construct a new resource.

Endorsed by stakeholders in October, the proposal would create a nine-month timeline from when a developer submits an application to the drafting of an interconnection agreement. It would allow projects with minor network upgrades to proceed, including storage resources — a sticking point throughout the stakeholder deliberations.

Quadrennial Review Could See Changes to Demand Curve

To address the longer-term concerns PJM and its members have with the capacity market design, the Quadrennial Review of the market has been moved up by one year, with the aim of submitting a filing at FERC in the third quarter.

Through a handful of conceptual meetings in the fall and winter, the Brattle Group laid out its thinking on the demand curve and reference resource. In the most recent Quadrennial Review, PJM shifted to a combined cycle for the reference resource over a combustion turbine, but it has sought to reverse that in one of its capacity market proposals.

That change was proposed out of a concern that higher energy and ancillary service (EAS) revenues for CCs would lead to the net cost of new entry (CONE) falling to zero for some locational deliverability areas. Several additional parameters use net CONE as an input, including the penalty rate for generators that fail to perform during an emergency, compensation of black start units and the overall shape of the demand curve. The 2026/27 auction would be the first to use a CC reference resource.

Brattle also is exploring the possibility of PJM shifting from a variable resource requirement (VRR) curve to a marginal reliability impact curve, which could improve price stability and be adaptable to a sub-annual design if that is sought in the future. The design could yield a flatter demand curve, one of the major concerns stakeholders have voiced about the VRR curve, particularly as EAS revenues are projected to rise.

Data Center Growth Driving Transmission Upgrades

On the transmission side, PJM is grappling with how to supply rising load growth in the east, particularly around “Data Center Alley” in Northern Virginia, with new generation expected to come online in the west.

Staff have announced their intention to recommend a $5.8 billion package of Regional Transmission Expansion Plan upgrades to the board, with a vote on approval expected in the first quarter. (See “PJM Unveils Recommended Projects for 2024 RTEP Window 1,” PJM PC/TEAC Briefs: Dec. 3, 2024.)

In Transmission Expansion Advisory Committee presentations on the recommended project components, PJM staff said one of the factors it weighed in its selections was expandability because of the likelihood that additional grid reinforcements will be needed as load growth continues.

Presentations to the RTO’s Load Analysis Subcommittee on the preliminary 2025 Load Forecast included several transmission owners projecting tens of gigawatts of large load additions (LLAs). Those additions represent expected load growth not captured in PJM’s standard economic load growth models, but consumer advocates have argued the process by which they are included requires more transparency.

Bill Fields, deputy of the Maryland Office of People’s Counsel (OPC), said the transparency and standardization of data center load projections will be a major focus for advocates going forward. He said it is unclear how PJM is vetting LLAs, and he is concerned that developers scoping out one project across multiple utilities could lead to speculative or duplicative additions making it into the forecasts.

Consumer Advocates Seek More Capacity Market Changes

Consumer advocates laid out their own priorities at a December meeting of the PJM Public Interest and Environmental Organizations User Group (PIEOUG), including incentivizing storage and demand response participation in the capacity market, a sub-annual market design and changes to RTO governance. (See Rising Transmission Costs in PJM Concern Consumer Advocates, Enviros.)

Fields said there are roadblocks limiting the participation of DR and storage resources, both of which have been the subject of stakeholder discussions in recent months. The Market Implementation Committee has been examining the winter availability window for DR, which defines the hours in which the resource is considered available for dispatch for capacity emergencies in ELCC modeling. Curtailment service providers have argued the window limits consumers with a flat load profile from responding in winter.

The Markets and Reliability Committee voted to delay action on a PJM issue charge to establish rules for storage as transmission assets in October, with several stakeholders suggesting that the membership is saturated with work. Speaking at the Dec. 10 PIEOUG meeting, Greg Poulos, executive director of the Consumer Advocates of the PJM States, said the advocates are broadly supportive of expanding storage development, and they may seek changes to market rules through the PIEOUG.

Fields said it’s hard to see how PJM’s capacity market filings will be enough to address the concerns that advocates have with the market. While the RRI would allow some projects to progress and mitigate high prices, a mechanism is needed to keep prices reasonable so long as capacity prices cannot result in an actionable price signal, he said.

Under normal circumstances, PJM’s filings would constitute years’ worth of stakeholder attention and effort, not concentrated into a few months. Adequate analysis will be needed to ensure that stakeholders understand the possible market impacts and to identify any unintended consequences, Fields said.

Capacity Accreditation

While several stakeholder efforts are focused on overhauling aspects of the capacity markets, they also continue to fine-tune the redesign to come out of the 2022 Critical Issue Fast Path (CIFP) process.

Three issue charges introduced by LS Power in the fall focus on the marginal ELCC accreditation methodology at the heart of the CIFP changes and are being worked on through the newly formed ELCC Senior Task Force. It is charged with considering the process’s transparency, how it contributes to resource accreditation, and a “disconnect” between the winter-focused risk modeling behind ELCC and the use of summer peaks to calculate zonal capacity emergency transfer limits.

When introducing the issue charges, LS Power argued that market participants have limited ability to understand how changes to their assets would affect their ELCC ratings. Because the framework relies on performance during past capacity emergencies, it may also take years for any improvements that could bolster capacity performance to result in higher accreditation.

LS Power’s Dan Pierpont told RTO Insider that the issue charges are just the first steps in improving ELCC; there needs to be a larger discussion on creating an accreditation framework that reflects future capability rather than historical performance. Without that, he said, the market cannot deliver a clear investment signal.

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ERCOT Faces Uphill Battle to Meet Large Loads

Known for his no-nonsense demeanor, ERCOT COO Woody Rickerson was especially candid in December when he appeared before a legislative committee overseeing the state’s grid. 

Asked to respond to a lawmaker’s concerns that assessments of Texas’ energy supplies are offering a misleadingly optimistic portrayal of the state’s energy production, Rickerson replied, “I don’t have a positive sense on this at all.” 

State Sen. Charles Schwertner (R), the joint committee’s chair and architect of many of the new laws put in place after the disastrous 2021 winter storm, asked Rickerson to clarify. 

“I don’t have a positive sense that we have enough generation on the books to serve the load that’s expected,” Rickerson replied. 

The Texas grid operator raised eyebrows last April when it said its load-growth forecasts had ballooned by 40 GW over the previous year’s estimates. It said it anticipates about 152 GW of new load by 2030. 

The state’s business-friendly environment attracts investors and developers who want to build data centers, mine bitcoin and employ artificial intelligence, all massive energy consumers. Industrial electrification, electric vehicles and now hydrogen facilities will only increase the strain on the ERCOT grid. The ISO has about 103 GW of installed capacity for a system that peaks around 85 GW of load in the summer and 78 GW in the winter. 

“We’re the best market in the country to react to that kind of growth potential,” ERCOT CEO Pablo Vegas said during the ISO’s April Board of Directors meeting, pointing to the ability to interconnect resources “faster than anyplace else in the country.” 

ERCOT CEO Pablo Vegas | © RTO Insider LLC

“We continue to add generation at really an incredible rapid pace,” he told his board in December, pointing to an interconnection queue with more than 371 GW of capacity. 

Still, ERCOT has decided it had to adapt and take a different approach to meeting future demand that ensures all system-planning processes can “adapt to better serve” the state’s economy. Central to that is a new law requiring the ISO to include prospective load identified by transmission service providers, rather than factoring in unsigned load. 

Solar resources (155 GW) and battery storage (141 GW) account for 83% of the 1,775 active interconnection requests. At the same time, Texas is trying to attract more thermal generation with its Texas Energy Fund, established by state law and approved by voters in 2023.  

The fund’s In-ERCOT Generation Loan Program offers a low-interest (3%) loan and grant program of up to $7.2 billion for dispatchable generation. It has received 18 applications for 9.72 GW of potential new generation seeking $5.34 billion in loans; the Public Utility Commission will vet the applicants during the year before awarding the grants. 

Dealing with Growing Loads

Meanwhile, ERCOT is tracking more than 40 GW of large-load requests that may or may not show up. 

“There’s no real cost associated with saying, ‘Hey I’m a load, and I want to come to the grid,’ and there’s no forking over of ‘X’ dollars if you’re a large load, for instance,” Schwertner said during the December joint committee meeting. “We should have a great handle on what that load is, where it’s going to be added.” 

Schwertner suggested assessing an upfront fee for those wanting to interconnect their large loads with ERCOT, an issue that will likely be discussed during this year’s legislative session, which runs from Jan. 14 to June 2. 

Vegas says the current generation mix is more diverse than ever, can be built faster and is located farther from load centers. While the generation is coming online quickly and load growth increasing faster, it still takes three to six years to energize transmission in ERCOT (about half the time required in other regional grids). 

Speaking at an Energy Bar Association symposium in October, ERCOT General Counsel Chad Seely said the ISO is often asked how much its recommended transmission improvements will cost consumers and whether the new buildout will be sufficient “if all that load eventually shows up over the next five, seven years.”  

ERCOT staff is continuing to work with stakeholders to define rules and has completed its Permian Basin Reliability Plan, as directed by the PUC. The plan recommends five 345-kV import paths into the region and, in a first for the state, three 765-kV import paths. 

With estimated costs of $13.77 billion for the 765-kV lines and $12.95 billion for the 345-kV imports, the plan exceeds the price tags of previous annual infrastructure portfolios. Seely said the plan is necessary to meet the region’s load growth, which comes not just from oil and gas production but also data centers, crypto facilities and other large industrial users. 

“That is the equivalent of taking North Texas [and the DFW Metroplex], from a load standpoint, and putting it out in West Texas,” Seely said. “They want reliable service, so we’ve recommended a lot of transmission infrastructure, both locally and large-scale highway infrastructures.” 

Transmission providers are already preparing certificates of convenience and necessity applications. The PUC has set May 1 as a date to determine which import paths will be used. 

Prompted by a 35.7% increase in projected load growth from the year before, ERCOT’s annual Regional Transmission Plan (RTP) included more than 50 GW of individual loads larger than 75 MW. Released just before the holidays, the plan includes more than 274 transmission projects and about 6,000 miles of line upgrades, rebuilds, conversions and additions to meet the forecasted load growth in the traditional 345-kV plan. In comparison, the grid operator identified a combined 262 projects in its 2023 and 2022 RTPs. 

The 2024 plan also considers a 765-kV plan as an alternative to the traditional 345-kV plans. ERCOT will file a 345-vs.-765 comparison with the PUC by late January and will host a workshop on the differences Jan. 27. 

RTC with an ERCOT Twist

After the commission shelved the once-favored performance credit mechanism market change, the ISO says its staff and stakeholders will work to complete the real-time co-optimization (RTC) project by the end of the year. Postponed after Winter Storm Uri, RTC will save about $1.6 billion annually in reduced energy costs by procuring energy and ancillary services every five minutes. (See Texas PUC Shelves PCM Design Over Lack of Benefits.) 

RTC market trials are scheduled to begin in May. The project has a December targeted go-live date.  

Once RTC becomes a part of the ERCOT market, staff will begin adding a new standalone ancillary service, dispatchable reliability reserve service. DRRS will be procured in the day-ahead and real-time markets from eligible generators who must be online within two hours of instruction and run at least four hours at their high-sustained limit. The amount of DRRS procured will reduce reliability unit commitments. 

While RTC is already common in most regional grids, ERCOT is tacking in a different direction with its reliability standard. As currently proposed, the standard includes the normal one-in-10 days loss-of-load expectation found in other regional grids, but the ISO will also measure duration (no more than 12 hours in any event) and a yet-to-be-determined magnitude. (See ERCOT’s Vegas Touts New Reliability Standard.) 

ERCOT says this will result in a comprehensive reliability standard that better characterizes the real risk probabilities of a grid event and its impact on consumers. Staff are finalizing the magnitude element and working on the various parameters and scenario modeling for the new standard. 

Speaking to the Texas Reliability Entity in December, Vegas said, “We’re going to now have a yardstick that is going to effectively help us measure how we think the ERCOT market will perform in some period of time.” 

ERCOT is also working to improve its reliability must-run and must-run alternative processes, a result of CPS Energy’s attempt to retire three aging gas units this year. Staff has said the units are needed for reliability purposes and are pursuing an RMR contract for the largest resource. (See related story, ERCOT Finds Little Interest in MRAs for San Antonio Units.) 

“Some of our thermal fleet is getting quite aged,” Vegas told the board in December. He said about 40% of the ERCOT fleet is over 30 years old and 30% is over 40 years old. 

“Over time, as new resources are built and developed and brought onto the grid, you will expect the older, less economic resources to be retiring,” Vegas said. “We want to make sure that we’ve got a robust reliability must-run or must-run alternative process that we can leverage to get the most efficient and effective solutions when we are faced with that circumstance again in the future.” 

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Mass. Electricity Rates Working Group Issues Recommendations

Prior to the deployment of advanced metering infrastructure (AMI), the adoption of simple, near-term rate reforms could help Massachusetts achieve its electrification goals while minimizing effects on ratepayers, an interagency working group concluded in a report released in late December. 

The Massachusetts Interagency Rates Working Group (IRWG) recommended that each utility adopt an opt-in seasonal heat pump rate and establish a “non-bypassable fixed charge” to encompass some of the policy costs that currently are recovered through volumetric charges. 

The working group includes members of the Department of Energy Resources, the Executive Office of Energy and Environmental Affairs, the Massachusetts Clean Energy Center and the Attorney General’s Office. 

“The Working Group’s primary recommendation for the near term is for the DPU [Department of Public Utilities] to require all the EDCs [electric distribution companies] to establish a seasonal heat pump rate, similar to those recently approved and directed by the DPU for Unitil and National Grid, but with larger winter differentiation to ensure energy bill savings for customers transitioning from gas heating to electric heat pumps,” the IRWG wrote. 

Under the current rate structure, electrifying a natural gas heating system typically increases a household’s total energy costs, the group noted. It added that the cost disincentive to electrification could become more pronounced in the coming years, as both distribution and transmission rates are set to increase.  

About 54% of homes in Massachusetts use natural gas heating, 26% use oil and 13% use electric resistance, the working group noted.  

The working group recommended seasonal household-wide heat pump discounts on distribution and transmission charges. It noted that the New England power system currently peaks during the summer, and the increased winter electricity demand would be unlikely to significantly increase overall system costs. Supply rates would not be affected by the discount.  

“The winter volumetric charge of a seasonal heat pump rate can be set on a revenue neutral basis, such that, based on the expectation for increased kWh usage, the rate will still recover the same level of total fixed costs,” the IRWG wrote.  

Estimated heating cost by fuel type in Massachusetts | Massachusetts Interagency Rates Working Group

If adopted, the seasonal heat pump rate may be a short-lived design. The rollout of AMI, combined with the expected transition of the New England grid to a winter-peaking system by the mid-2030s due to heating electrification, likely will necessitate broader changes to rate design. 

The report’s other major recommendation was for a fixed charge to cover some state policy costs and system reliability costs that currently are calculated based on electricity consumption.  

While programs related to energy efficiency, decarbonization and low-income discounts historically have been funded through volumetric charges to incentivize lower energy use, high electricity rates can inhibit customers from electrifying, the report said.

“A non-bypassable fixed charge could fund crucial programs that support the state’s energy, affordability and decarbonization goals in a way that does not increase volumetric charges, a key barrier to electrification,” the working group noted.  

“These recommendations, principally the seasonal heat pump rate, can be implemented in the near term and are essential for affordability and decarbonization,” the working group added. It called on the state’s DPU to facilitate the rapid deployment of the seasonal heat pump rate for the winter of 2025/26. 

The DPU has an ongoing investigation into energy affordability and tiered discount rates (DPU 24-15). The IRWG said its recommendations are intended to be complementary to this proceeding and added that it’s considering petitioning the DPU to take up its short-term recommendations. 

The working group said it plans to issue more long-term recommendations focused on “AMI-enabled rate design, ratemaking, and regulatory mechanisms,” noting that a DPU investigation likely will be necessary for implementing these long-term changes.  

The group said the state’s three electric utilities are scheduled to complete their rollouts of AMI between 2025 and 2029, and “widespread [time-varying rates] will likely be in effect between 2029 and 2033.” 

Larry Chretien, executive director of the Green Energy Consumers Alliance, expressed strong support for the working group’s main recommendations. 

Chretien wrote that implementing the recommendations likely would require action from the DPU, adding that, “based upon some recent actions by the DPU, we anticipate that the recommendations will be met with favor.” 

“To enable a proper level of civic engagement, we encourage the DPU to consolidate the recommendations into one statewide docket,” Chretien said.  

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BPA Market Decision on Track Despite Calls for Delay

The Bonneville Power Administration remains on track to issue a decision on which day-ahead market to join by May 2025 despite calls to delay until fall to give itself more time to reconsider its leaning toward SPP’s Markets+. 

BPA spokesperson Doug Johnson told RTO Insider on Jan. 6 that the agency is “not contemplating a delay at this time,” while urging stakeholders to view recent production cost models with some skepticism.  

Johnson’s comments followed concerns presented in a Dec. 19 letter from Northwest environmental organizations that joining Markets+ instead of CAISO’s Extended Day-Ahead Market (EDAM) could lead to multimillion-dollar cost increases for the agency and its customers.  

Ten organizations, including Northwest Energy Coalition, Natural Resources Defense Council, Sierra Club and Earthjustice, signed the letter, which was published in support of four U.S. senators from Oregon and Washington who voiced similar concerns in separate correspondence with BPA. 

Antoine Lucas, SPP vice president of Markets+, said in an email that the RTO is “disappointed the letter from the Northwest NGOs perpetuates mischaracterizations of the Markets+ design, benefits and governance structure in ways that have already been addressed.” 

BPA has previously stated that it will issue its market decision by May 2025. The agency has leaned toward SPP’s Markets+, pointing mainly to its governance framework, which BPA believes provides greater independence from California state influence compared to the EDAM option. 

However, the environmental organizations urged BPA to delay its decision to at least fall 2025 “to accurately assess the governance structures proposed by EDAM and Markets+ and to ensure that any decision delivers the greatest economic and other benefits to our states and region,” according to their letter. 

The organizations argued that Markets+ also faces governance issues. They pointed out that FERC has yet to approve Markets+’s proposed governance structure and that the market’s independent panel “is subject to the direct control of SPP.”  

Meanwhile, the West-wide Governance Pathways Initiative, a group of stakeholders, is addressing governance concerns in EDAM by developing proposals to create an independent entity to govern the EDAM and WEIM markets, the letter stated. 

In his statement to RTO Insider, Lucas said SPP “remains confident FERC will approve the Markets+ tariff, and we look forward to continued conversations about the competitive benefits Markets+ brings to Western stakeholders and their customers.” 

Financial Considerations

BPA also participates in CAISO’s Western Energy Imbalance Market, which has “generated over $6 billion in benefits,” according to the letter. The agency’s investments in WEIM could go to waste in the Markets+ scenario, the groups contended. 

Additionally, a study by Environmental and Energy Economics found that EDAM could generate economic benefits “ranging from $65 [million to] $221 million per year compared to Markets+,” the organizations wrote. 

BPA has previously questioned this finding. In correspondence with Seattle City Light, the agency’s administrator, John Hairston, said these numbers are only accurate under a scenario in which there is only a single West-wide market rather than the more likely scenario that there will be multiple markets in the future.  

Johnson reiterated this point to RTO Insider, saying, “The model benefits under a single West-wide market footprint should be viewed with some skepticism.” 

“For example, a production cost model study does not capture the material impacts of resource adequacy requirements, greenhouse gas accounting, fast-start pricing, scarcity pricing, bid caps, market power mitigation, out-of-market actions and other differences in market design between EDAM and Markets+,” according to Johnson. 

He added that those models also fail to consider changes in market rules “or the lack thereof, that are influenced by a given market’s governance structure, which may impact and influence market outcomes depending on the process for updating market rules.” 

He also targeted the letter’s claim that BPA considers spending “$25 million in customer money” to fund Phase 2 of the Markets+ proposal despite expecting “to miss revenue projections for this year by $375 million, leading to $280 million in losses.” 

The letter relies on information from BPA’s second quarter business review for 2024, and Johnson said the organizations have “extrapolated that into a completely different financial operating year.” 

“We would absorb that $25 million cost if we were to execute a Phase 2 agreement with SPP this year, and we haven’t even done a first-quarter report yet, so we’re not even talking about our finances this year,” Johnson said. 

A spokesperson for U.S. Sen. Jeff Merkley (D-Ore.) — one of the four lawmakers who signed the initial letter that spurred the environmental organizations’ support — told RTO Insider that Merkley “is following this discussion closely.” 

“His priority remains ensuring there are deliberate processes to maximize the benefits for Oregon families,” the spokesperson added. 

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NYISO’s Busy 2025 Begins

NYISO capped off a roller coaster of a year full of reliability needs, the Demand Curve Reset and contentious stakeholder meetings by announcing a new record level for hourly wind power generation on Dec. 16.

The grid operator reported that 2,309 MW were generated from 30 wind power facilities at 11 p.m. This served 14.4% of energy demand statewide. The previous record of 2,213 MW was set in November.

With more wind power on the way, NYISO’s latest Public Policy Transmission Need seeks to get up to 8 GW of offshore wind into New York City by 2033. It received four bids from the New York Power Authority, New York Transco, Viridon New York and energyRE Giga-Projects USA. The ISO will spend most of 2025 evaluating and selecting projects. A draft report on the top projects will be released between the second and third quarters, with a final decision by the Board of Directors by the end of the year.

NYISO’s early 2025 will likely be dominated by the Reliability Needs Assessment process again. Now that the board has accepted the results of the RNA, which identified a reliability need in New York City starting in summer 2033, the ISO will seek system updates to try to address the need without opening a formal solicitation process. This will incorporate any ongoing or planned upgrades, generation additions and other changes that might address the need.

If this is not sufficient to address the reliability need, NYISO will seek solutions to fix the issue. This would trigger an additional process that looks at the proposed solutions and eventually culminate in the development of a Comprehensive Reliability Plan. The CRP then serves as the blueprint for system reliability for the next 10 years, up to and including ranking any solutions to the need if it still exists.

At the same time, NYISO will continue to update its quarterly Short-Term Assessment of Reliability reports, the most recent of which found the continued operation of two generators on the Gowanus Canal and two barge-based peakers to be necessary for reliability. These peakers were supposed to close because of the Department of Environmental Conservation’s “peaker rule” by May 1. NYISO is keeping them active for an initial period of up to two additional years until “permanent solutions to the need” are in place.

NYISO 2025 Projects and Developments

May 1 also marks when the DCR is due to go into effect.

Pending FERC approval, the reset will redraw the demand curves for wholesale electricity based on the estimated cost of a proxy peaker plant, which for the first time has been designated a battery by NYISO.

The previous 2021-2025 DCR was challenged by a lawsuit because of FERC’s rejection of NYISO’s amortization period. It is unclear if any parties, including FERC, will issue changes or challenges to the new demand curve, but the selection of a battery as the proxy unit was controversial with stakeholders.

NYISO is also going to be embroiled in nested planning projects throughout the year. The third year of the Coordinated Grid Planning Process with the New York Public Service Commission and utilities will see a report in the fall or winter. This report will highlight the least-cost planning assessment for transmission upgrades and solutions across the state.

Simultaneously, NYISO will be implementing FERC Order 1920, which requires NYISO to change its regional transmission planning process to examine long-term needs over a 20-year horizon. The ISO expects to file its compliance with FERC in mid-2025.

This year also marks the first in which NYISO’s new interconnection study cluster process will go into effect. The ISO hopes it will streamline and expedite the backlogged interconnection queue. The big change is that interconnection requests are being examined in clusters as opposed to individually. Projects also have a limited number of “midstream” modifications they can make to avoid bogging down the rest of the cluster.

Beyond the ISO

There are several other developments in New York to keep an eye on in 2025.

Smart Path Connect, a major NYPA and National Grid transmission project, is due to finish its rebuild of 100 miles of lines in April. The new substations for the project are due to be energized in the fall 2025 and spring 2026. When completed the project will allow an additional 1,000 MW of energy to travel across the state.

Raya Salter, an environmental justice advocate serving on the New York Department of Public Service’s Energy Policy Planning Advisory Council, told RTO Insider that she would be pushing to get environmental justice issues folded into the transmission planning process. In a report developed in collaboration with the Columbia Climate School, she identified gaps in the planning process that hinder meeting the state’s environmental justice goals under the Climate Leadership and Community Protection Act.

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ISO-NE in 2025: Capacity Reforms, Tx Solicitation and FERC Orders

ISO-NE’s multiyear effort to overhaul its forward capacity market likely will continue to dominate ISO-NE and NEPOOL work in 2025. The RTO’s workload also will feature a first-of-its-kind transmission procurement, compliance with FERC Orders 2023 and 1920, the development of an energy shortfall threshold and a myriad of other efforts focused on balancing affordability, reliability and decarbonization.  

The capacity market already is a major revenue source for generators in the region and is poised to gain value as renewables supported by long-term contracts reduce prices in the energy market. 

The RTO anticipates total revenue from the capacity market and power purchase agreements surpassing the value of the energy market by 2035. The capacity market was valued at $1.8 billion in 2023, while the energy market was valued at $4.8 billion.  

Meanwhile, resource capacity accreditation changes, which have been under development since 2021, could significantly affect capacity revenues for different resource types. 

ISO-NE has broken up the capacity auction reform (CAR) project into two phases, with the first phase focused on reducing the time between the auction and the capacity commitment period from years to months, and decoupling the resource retirement process from the capacity market. 

The RTO plans to ramp up work with stakeholders on the detailed design for the first phase in early 2025, targeting a FERC filing by the end of the year. (See NEPOOL Markets Committee Briefs: Dec. 10, 2024.) 

The second phase of the CAR project will focus on accreditation and seasonal reforms, which would split CCPs into distinct seasons with separate auctions. ISO-NE plans to begin discussions on these changes at a high level in 2025 before moving into more detail by the end of the year. It plans to file the second phase with FERC in late 2026.  

The RTO reached an advanced stage with its accreditation reforms in early 2024 before pausing this work to widen the project scope. (See ISO-NE: RCA Changes to Increase Capacity Market Revenues by 11%.) ISO-NE told stakeholders in December that it plans to “explain and discuss all proposed changes to capacity accreditation … as if they are being presented for the first time.”  

New Transmission and Aging Infrastructure

Also in 2025, the RTO is set to roll out its first request for proposals (RFP) for its longer-term transmission planning (LTTP) process, and likely will have to devote significant resources to complying with FERC Orders 1920 and 1920-A.  

The LTTP process was developed by the New England states and ISO-NE and approved by FERC in July. It creates a process for selecting and paying for transmission projects to fulfill long-term needs identified in ISO-NE studies. (See FERC Approves New Pathway for New England Transmission Projects.) 

In December, the states officially directed ISO-NE to develop the first LTTP RFP, which will be focused on increasing the north-to-south transmission capacity in Maine. ISO-NE plans to issue the RFP by March. (See ISO-NE to Work on State-backed RFP for Northern Maine Transmission.) 

The LTTP process mirrors many of the requirements of FERC Orders 1920 and 1920-A, which direct transmission providers to adopt long-term transmission planning procedures and establish cost-allocation methods with the states. Order 1920 compliance filings will be due in the summer of 2025.  

| Vineyard Wind

Prior to the release of Order 1920-A, ISO-NE paused stakeholder discussions on Order 1920 compliance, citing uncertainty regarding the pending rehearing order. It has yet to resume compliance discussions and has not announced whether it will pursue an extension of the compliance deadline. (See ISO-NE Announces Pause of Order 1920 Compliance Discussions.) 

The orders do not directly require changes to the LTTP process. However, using parts of the LTTP process to comply with the orders would “require extra justification and could result in commission modification to those processes on compliance,” Day Pitney LLP, counsel for NEPOOL, said in a December presentation.  

“The LTTP provisions might be better as an entirely separate supplemental process under the tariff,” Day Pitney added. “ISO, the [relevant state entities], the [participating transmission owners] and NEPOOL will need to consider.” 

2025 also will bring continued scrutiny of asset condition projects, which are intended to address deteriorating transmission infrastructure. Asset condition spending by the region’s transmission owners has ballooned in recent years, and states and consumer advocates have raised alarms about a lack of transparency and oversight into the investments.  

The region’s transmission owners have introduced over $3 billion in asset condition investments since the start of 2023, arguing that the investments are necessary to maintain the region’s aging grid. The states have pushed for reforms to the asset condition project review processes to ensure the investments are prudent, and also have expressed interest in right-sizing projects to capture long-term cost reductions when possible. 

Interconnection

ISO-NE and stakeholders still are waiting for a response from FERC on their compliance filings for Orders 2023 and 2023-A. The RTO submitted its compliance filing in May, requesting that FERC approve the proposal by Aug. 12 to preserve the compliance timeline.  

However, FERC has yet to rule on the RTO’s compliance filing for Order 2023, and ISO-NE has paused its work to implement its compliance with the order.  

This delay has created significant uncertainty for projects in the interconnection process. The queue is closed for new projects, and likely will reopen only after the completion of the first cluster study, which will take about a year to complete after its initiation. If FERC requires significant revisions to ISO-NE’s proposal, this could further delay the start of the first interconnection study. (See New England Clean Energy Developers Struggle with Order 2023 Uncertainty and With FERC Inaction, ISO-NE Delays Order 2023 Implementation.) 

“A commission order on the compliance proposal is sorely needed to help alleviate existing interconnection challenges and to provide certainty to both stakeholders and ISO-NE,” the New England States Committee on Electricity (NESCOE) wrote in a letter to FERC in late November.  

“The continued uncertainty around the timing of an order places ISO-NE on a tightrope where it is forced to balance the need to be postured to move quickly toward compliance once an order is issued with the need to continue to process resources under the currently effective tariff,” NESCOE added. 

At the state level, Massachusetts Energy Secretary Rebecca Tepper has said interconnection reform will be a major focus for Bay State energy officials in 2025. (See Overheard at Raab Electricity Restructuring Roundtable: Dec. 13, 2024.) 

Reliability Backstops and Fossil Resources

ISO-NE also aims to establish a regional energy shortfall threshold (REST) in 2025, which likely will be a key factor in potential future out-of-market reliability actions to retain resources or ensure an adequate supply of stored fuel. 

In November, the RTO said it plans to base the REST on two key metrics: normalized unserved energy over a 72-hour period — intended to capture the intensity of an energy shortfall — and total shortfall duration. (See ISO-NE Details Regional Energy Shortfall Threshold Metrics.) 

ISO-NE plans to finish discussions on the REST metrics in early 2025 before proposing an initial risk threshold to stakeholders in March or April. These discussions could pose difficult questions about how much the region is willing to pay for reliability, and to what extent it will keep fossil resources online to support reliability as renewable generation increases. 

The RTO’s inventoried energy program, which compensates fossil resources for maintaining fuel storage on-site in the winter, is set to expire in the spring of 2025. The RTO has yet to announce whether it plans to bring the program back for future winters. 

In 2024, New England saw the closure of the 1,400-MW Mystic Generating Station, while Granite Shore Power announced its plans to retire Merrimack Station, the region’s last remaining coal plant, by 2028. While the coal generator struggled to pass an emissions test throughout 2023, one of the station’s two units passed the emissions test in July 2024. The other unit is not allowed to run until it passes the test.  

Carbon emissions from electricity generation across New England likely increased in 2024 relative to 2023, according to ISO-NE data calculated through Nov. 25. The added emissions came from increased gas generation and do not account for gas system methane leaks, a key driver of climate change. (See Climate Activists Ask ISO-NE Board Members for More Transparency.) 

ISO-NE has faced continued pressure from activist groups at public meetings to take a more activist approach to reducing power sector emissions. ISO-NE has said frequently it favors putting a price on emissions in the wholesale markets but would need unanimous state support to pursue this mechanism.  

Consumer and environmental advocates also criticized for a lack of transparency into the proceedings of NEPOOL and the RTO’s board of directors. NEPOOL meetings remain closed to nonmembers, which has been a major point of contention for some environmental groups. 

State Clean Energy Policy

To ensure resource adequacy amid the clean energy transition, new capacity additions must keep pace with resource retirements and load growth. ISO-NE projects peak demand to grow from about 24,800 MW in 2024 to 25,700 MW in 2030. The RTO expects load growth to accelerate after 2030, projecting peak demand reaching up to 57 GW in 2050.  

New renewables are on the horizon — Vineyard Wind 1 and the New England Clean Energy Connect transmission line could come online by the end of 2025, potentially adding about 2 GW of combined generation capacity to the system. However, the subsequent wave of offshore wind projects likely will not be online until 2030.  

The obstacles to large-scale renewable deployment are daunting; state policymakers and advocates face a less friendly federal administration, increasing costs and long delays for offshore wind projects and transmission lines, and mounting affordability pressures on ratepayers. 

Two offshore wind projects, New England Wind 1 and SouthCoast Wind, remain in contract negotiations following their selection in the 2024 tri-state offshore wind solicitation. Connecticut declined to buy any offshore wind capacity from the solicitation amid worries about costs. (See Connecticut Closes the Door on 2024 OSW Procurement.)  

New England states likely will pursue major new procurements in 2025, potentially building on the 2024 multistate coordinated offshore wind procurement. Massachusetts is authorized to pursue multistate clean energy solicitations through the end of 2025 and may pursue an additional offshore wind solicitation. 

Maine is considering procurement of onshore renewable generation in the northern part of the state and also is developing its first offshore wind solicitation. Its first offshore wind RFP is scheduled to be finalized in January 2026. 

New England officials have discussed the possibility of more transmission lines to Canada, which may be bolstered by an agreement in December between Eastern Canadian provinces that could lead to a significant increase in the country’s hydropower capacity.  

With additional transmission capacity, Canadian hydropower could help balance renewable resources in New England, reducing reliability costs and renewable curtailment. While political and technical challenges remain, top energy officials in both Massachusetts and Quebec have expressed an interest in exploring the potential of new interregional transmission lines to unlock this potential. (See Overheard at Raab Electricity Restructuring Roundtable: Dec. 13, 2024.) 

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Uncertainty Clouds NJ Clean Energy in 2025

Amid nationwide concern about the impact on clean energy initiatives of President Trump’s return to the White House, New Jersey in 2025 faces the added uncertainty of a governor’s race to replace clean energy champion Gov. Phil Murphy and his release of a new energy master plan.

Murphy (D), who will step down in January 2026, has in his seven years in office aggressively pushed solar and offshore wind projects and the adoption of electric vehicles. His energy master plan could help shape the state’s energy use for years.

Yet the lack of clarity over what leadership comes next could complicate the state’s efforts to keep on track Murphy’s ambitious goals, which include developing 11 GW of ocean wind capacity by 2040, adding another 130,000 EVs on the road by the end of 2025 and launching a new Storage Incentive Plan (SIP) this year to provide stability to the state’s growing reliance on electricity.

“It is still, definitely a race to the finish line for the Murphy administration’s clean energy priorities,” said Doug O’Malley, director of Environment New Jersey. “There’s a real moment in the Trump era for gubernatorial candidates to talk about their plans for climate action and clean energy.”

The state’s last master plan, issued in 2020, formed the foundation of Murphy’s energy policy based around electricity. To date, that has included four solicitations of offshore wind projects and the adoption of the Advanced Clean Cars II act and the Advanced Clean Trucks rules, which took effect Jan. 1. Murphy also promoted the transformation of building heating and hot water systems to run on electricity.

Offshore Wind Challenges

The state’s biggest challenge in 2025 could be maintaining momentum in the state’s OSW projects. Since Ørsted abandoned two of the state’s three most advanced projects — Ocean Wind 1 & 2 — in October 2023, the state’s leading project has been the 1,510-MW Atlantic Shores, which received its Construction and Operations Plan approvals from the Bureau of Ocean Energy Management in October 2024.

To help the developer adjust to the changing OSW financial and supply chain environment, it submitted a rebid in the New Jersey Board of Public Utilities’ fourth solicitation. The BPU, which was scheduled to announce the solicitation outcome in December 2024, has yet to do so. And the BPU also expects to launch a fifth OSW solicitation in early 2025.

In addition, another project — Leading Light Wind, one of two projects totaling 3,742 MW of capacity endorsed in the state’s third solicitation in January 2024 — is struggling to advance. After the developer said it was looking for a new turbine manufacturer, the BPU extended by two months to the end of 2024 a deadline by which the developer should make “significant financial obligations.” (See New Jersey BPU Approves Invenergy Offshore Wind Delay.)

On Dec. 19, developer Invenergy Wind Offshore filed a motion with the BPU asking for an extension of the delay until May. The project supported its request by saying the “wind equipment market continues to experience significant price volatility, and the company has not yet identified a solution to that volatility.”

Vigorous Debate

Elsewhere, the Murphy administration is striving to reach the governor’s goal, set in February 2023, of electrifying 400,000 more dwelling units and 20,000 more commercial spaces or public facilities by December 2030. And the governor, after announcing in December that the number of EVs in the state has doubled since 2022 to 208,000, continues to push for more growth and more charging points. The state currently has 4,000 chargers in place, he said.

Those plans likely will be subject to debate in the gubernatorial race, said Sen. Bob Smith (D), who heads the Senate Environment and Energy Committee, which shapes many of the Legislature’s clean energy bills. Six Democrats and eight Republicans have announced their intent to seek the governor’s office.

“There is going to be a very vigorous discussion of energy policy and where New Jersey gubernatorial candidates see our energy policy going” on both sides of the aisle, he said.

Even if a pro-clean-energy governor is elected, he said, Trump’s presence in the White House “would mean New Jersey would have to do more on its own and not in partnership with the federal government.”

Master Plan Divisions

The state’s current master plan calls for the state to reach 100% clean energy by 2050, mainly by improving energy efficiency and shifting to wind and solar generation. The new plan was scheduled to be completed by the end of 2024, ready to form the cornerstone of a state “comprehensive climate action plan” to be released in 2025, Murphy’s Office of Climate Action in the Green Economy has said.

The release of the report is likely to be contentious, as were the four public hearings held by the BPU in the spring, when environmentalists said the last master plan had been too weak and the next one should be tougher. Business groups, who have long complained that the last master plan did not include an analysis of the cost of implementing the plan, said that should be a priority in the next report. (See NJ Wrestles with Clean Energy Priorities.)

As in many states, clean energy supporters say the state’s grid needs to be strengthened to handle a future electricity demand surge that BPU officials predicted in October 2024 will increase by 20% by 2034. (See NJ Offshore Infrastructure Plans Spark Electromagnetic Fears.)

“We have a grid that doesn’t work,” said Smith. “We’re not investing enough in it. … As a result, even if we get wind moving at a decent rate, and that hasn’t started yet, you’re going to have some trouble in getting the renewable energy where it needs to be.”

Ray Cantor, a lobbyist for the New Jersey Business & Industry Association, agreed the state needs to “ensure our electrical grid has adequate resources and remains reliable.” His organization, one of the state’s largest business groups, wants it done in a “manner that is affordable and reliable,” he said.

Yet there is little agreement on how to do it. A bill sponsored by Smith to appropriate $300 million for grid upgrades has not moved since leaving his committee in March. He said he thinks public sentiment may not be ready to endorse the necessary investment in 2025 until the state suffers even more extreme weather impact than the recent run of storms, wildfires and heat waves.

Stimulating Storage

Also on the state’s agenda is the BPU’s SIP initiative, which is designed to help the state reach 2,000 MW of installed storage in the state by 2030 and provide stability to an energy system based on the vicissitudes of wind and solar power.

The proposal, for which the state gathered stakeholder input in November and December, seeks to stimulate storage development through two programs: one to be launched in 2025 that would offer fixed incentives for grid supply projects; and another to offer fixed incentives for distributed energy projects, with a 2026 launch date. (See Developers Seek Deadline Extension in NJ Storage Plan.)

Solar supporters see the storage program, and new remote net metering rules, as important for continued solar growth. The state, with a goal of 12.2 GW of installed capacity by 2030, was expected to reach 5 GW of capacity in 2024. But the latest BPU figures, for the first 10 months of 2024, show the state installed 201,935 kW in the period. At that rate, the full-year capacity installed would fall short of the 447,697 kW installed in 2023.

Fred DeSanti, executive director of the New Jersey Solar Energy Coalition, estimated the state’s residential solar installations in 2024 were 25% lower than the year before, commercial projects were down 50% and community solar was down 66%.

A key issue to be addressed in 2025, he said, is that the “solar sector is still struggling with utility interconnection cost issues and the number of circuits now closed or severely restricted to new solar installs statewide.” Those issues can be addressed by electric delivery companies, he said, adding that to make those changes there also needs to be a “rational split of costs between ratepayers and solar developers.”

“Ratepayers need to make some meaningful contribution toward grid modernization,” he said.

EV Advance

In the EV sector, the New Jersey Coalition of Automotive Retailers is skeptical the governor’s 200,000 EV milestone means the state can reach its 330,000 EV goal.

President Laura Perrotta said New Jersey consumers in 2024 bought fewer than half the 100,000 EVs sold that is required by the ACCII rules. The rules require that 23% of vehicles sold in 2024 in the state are EVs, far larger than the actual figure of 11.2%, she said. Sales were hampered by the state’s decision in 2024 to remove a sales tax exemption on EV purchases and to add a registration fee of $250 a year for four years on the purchase price of an EV to pay for road repairs.

Pam Frank, CEO of ChargEVC, a nonprofit coalition that promotes the sustainable growth of the EV market, said the state has passed through the “early adopter” phase to the “mass market” era. Despite the added fee, the sales tax loss and the state’s reduction of incentives for all buyers except those on a low income, “the good news here is that the industry is moving along pretty well,” she said.

The state in 2025 should see the rollout of EV chargers along the New Jersey Turnpike and Garden State Plaza, which at present host mainly Tesla chargers, she said. Applegreen NJ Welcome Centres in 2023 committed to installing chargers on the state’s two highway arteries, with 80 installed by the end of 2025. (See NJ EV Charger Plan Advances as Enviros Demand ACC II Adoption.)

In addition, she said, her organization is helping put together the state’s first ever EV car show, a four-day event in April that will be held at the state’s largest mall, American Dream in East Rutherford.

“We’re hoping to make it the largest gathering of EVs on the East Coast,” she said.

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SMR Manufacturer, Texas and Utah Sue NRC Over Licensing Requirements

Two Republican state attorneys general and micro nuclear reactor firm Last Energy filed a lawsuit in federal court seeking an easier regulatory hand from the Nuclear Regulatory Commission on small reactors. 

Attorneys general in Texas and Utah signed onto the lawsuit that was filed Dec. 30 in the U.S. District Court’s Eastern District of Texas, Tyler Division (6:24-cv-00507). 

“With a preference to build in the United States, Last Energy nonetheless has concluded it is only feasible to develop its projects abroad in order to access alternative regulatory frameworks that incorporate a de minimis standard for nuclear power permitting, limiting requirements with a consideration of proportionality to the risk embodied in the technology,” the lawsuit said. 

Last Energy builds very small reactors of 20 MW that operate inside fully sealed containers with 12-inch-thick steel walls and thus have “no credible mode of radioactive release even in the worst reasonable scenario,” said the complaint. 

The firm has deals to build more than 50 reactors in Europe and has invested $2 million to set up a factory in Texas. But unless the NRC dials back regulatory requirements for small reactors, the lawsuit argued, its business would never get off the ground in the United States. 

The NRC, despite its name, does not really regulate new nuclear reactor construction so much as ensure that it almost never happens, the lawsuit said. The NRC’s interpretation of its regulations goes against congressional intent, which the lawsuit argued was to exempt small reactors that do not use significant amounts of nuclear material from federal licensing requirements. 

“The NRC imposes complicated, costly and time-intensive requirements that even the smallest and safest SMRs and microreactors — down to those not strong enough to power an LED lightbulb — must satisfy to acquire and maintain a construction and operating license,” the lawsuit said. “These requirements threaten the health and prosperity of Texans by hindering the rollout of safe and reliable power — precisely the sort of thing that Last Energy could provide.” 

The Atomic Energy Act of 1954 authorizes the NRC to require licenses only for reactors “capable of making use of special nuclear material in such quantity as to be of significance to the common defense and security, or in such a manner as to affect the health and safety of the public.” 

As written, the lawsuit said the Atomic Energy Act appropriately requires licensing for large nuclear power units, but those that use only a little nuclear material should be exempt, the lawsuit said. 

“To be clear, this regime hardly gives free rein to operators of even small, safe reactors,” the lawsuit said. “Such operators still must comply with the NRC’s stringent oversight of the special nuclear material that fuels reactors, not to mention state regulation, export controls, restrictions on nuclear weapons production, and prohibitions on weapons- grade nuclear material. Further, state governments would retain, and likely exercise, their traditional power to regulate power generation within their borders.” 

An earlier version of the act passed in 1946 gave atomic regulators licensing authority over “any equipment or device capable of making use of fissionable material,” but the lawsuit argued that in 1954, Congress deliberately narrowed that authority with thresholds related to national security, and health and safety. 

When NRC’s predecessor agency implemented the new law in 1956, it kept the broader licensing requirements in place and did not explain why any reactor used enough material to “be of significance to the common defense and security, or in such manner as to affect the health and safety of the public.” 

NRC has exempted tiny research reactors like the five-watt reactor at Texas A&M University, which is barely strong enough to power a small LED lightbulb. 

The lawsuit wants the court to require the NRC to implement a new rulemaking that considers the statutory limits around smaller reactors, and to declare that Last Energy’s proposed small modular reactors and microreactors “are not utilization facilities” under the Atomic Energy Act.