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November 14, 2024

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FERC Permits Elliott to Buy up to 20% of NRG Stock amid NOI

While an inspection into its approval process plays out, FERC has allowed another investment firm to purchase a sizable chunk of a public utility.

With Jan. 8’s decision, New York-based Elliott Investment Management is free to bump up its current 2.36% ownership of NRG Energy common stock to a maximum 20% through direct or indirect purchases (EC23-112).

FERC allowed the transaction over extensive protest from Public Citizen, which warned that the investment firm was seeking to control the utility. Elliott said it eventually may exercise voting rights depending on NRG’s financial and operation performance.

The approval follows FERC initiating a Notice of Inquiry last month on its practice of issuing blanket authorizations for investment companies seeking a stake in public utilities. (See FERC Reconsidering Blanket Authorizations for Investment Companies.)

In this case, FERC said the transaction won’t harm competition because Elliott doesn’t currently own or control generation in the markets where NRG operates. The commission also noted that the transaction doesn’t involve any handover of generation facilities and doesn’t disturb market concentration or operational control.

Elliott does, however, own a 15% ownership interest in Peabody Energy Corp., which supplies coal to some NRG plants in PJM and ERCOT. Elliott pledged that it doesn’t involve itself in Peabody’s day-to-day operations.

Public Citizen protested that assertion. The group pointed out that two Elliott executives, Samantha Algaze and Dave Miller, serve on Peabody’s board of directors. Public Citizen argued that Peabody’s management is “directly accountable” to the board and that board members have “unfettered access to influence management.”

Nevertheless, FERC rejected Public Citizen’s request for a hearing to probe how Peabody’s coal supply contracts with NRG would affect competition.

The Elliott executives included sworn affidavits that they do not oversee Peabody’s day-to-day operations, nor do they set pricing, negotiate contracts with customers or “seek to influence Peabody management decisions concerning to whom or what Peabody sells coal or the markets in which they sell coal.”

Public Citizen further argued that FERC couldn’t authorize the deal because it couldn’t allow Elliott executives to simultaneously serve on the NRG and Peabody boards. That would violate the Clayton Act, the organization reasoned.

Elliott argued that FERC is not tasked with enforcing the Clayton Act and that Peabody isn’t a competitor of NRG because it doesn’t mine coal.

FERC said Elliott’s board control and representation at either Peabody or NRG was “irrelevant” to its evaluation of the transaction. It also agreed that its jurisdiction doesn’t extend to Clayton Act enforcement.

Additionally, Public Citizen said it was troubled that prior to seeking FERC approval, Elliott attained indirect control of more than 10% of NRG through acquiring derivatives that “likely convey indirect voting control.” It said the Securities and Exchange Commission is similarly uneasy over the use of derivatives to covertly control public companies and has proposed a rulemaking to treat holders of cash-settled derivatives as owners for reporting purposes.

Public Citizen claimed that Elliott has a history of acquiring derivatives to “amplify their indirect control over a target company.” The consumer group said Elliott follows a playbook of using their economic interests to exert corporate control and then switch out board members and executives. Public Citizen said Elliott’s use of derivatives to control voting rights means Elliott meets FERC’s definition of an affiliate company.

FERC, however, decided it wouldn’t address the allegations of investor activism. It also said any existing affiliation between Elliott and NRG wouldn’t affect its competition analysis. FERC said though it wasn’t making a finding of affiliation now, it wasn’t foreclosing on the possibility of determining it later.

Elliott said Public Citizen’s concerns were “speculative” and its use of derivatives “merely [confers] economic interest and [does] not permit the holder to ‘force’ any change at such companies.”

Public Citizen warned FERC that “this is a proceeding of first impression for the commission, and therefore requires careful consideration, as it will likely establish precedent for both hostile takeovers of public utilities and affiliation treatment of cash-settled swaps.”

It said FERC should curb Elliott’s ability to enter into cooperation agreements and ban it from appointing board members at other public utilities. Public Citizen alleged that “at least once a year,” Elliott appears to scoop up direct and indirect interests in jurisdictional utilities and then pressure personnel and investment changes. The group said cooperation agreements allow Elliott access to nonpublic material of other utilities while simultaneously serving as a de facto affiliate of NRG, posing a risk to competition.

Public Citizen asked FERC to force Elliott to disclose how many arrangements it has with utilities and limit its ability to enter into future cooperation agreements.

Finally, Public Citizen further alleged that Elliott is collaborating with Bluescape Energy Partners to force operational changes at NRG. It said Bluescape and Elliott have enjoyed “a yearslong relationship of successfully conspiring to bend target companies to their demands.” According to Public Citizen, this is the sixth time Elliott and Bluescape have “joined an effort to usurp management of a public utility without first securing” a FERC order through a combination of cash-settled derivatives, acquisition of NRG stock and coordination with Bluescape.

FERC said any possible collusion with Bluescape was beyond the scope of the proceeding.

Commissioner Mark Christie said though he concurred with FERC’s decision to allow the stock purchase, Public Citizen’s allegations regarding Elliott and its investments in public utilities are of interest to the commission.

“To that end, in future proceedings, interested entities should continue to file information they believe may be of interest to the commission in its review, including, as Public Citizen has done here, information regarding investment practices in jurisdictional utilities commenters believe may suggest indicia of influence as they relate to affiliation and control,” Christie wrote.

He said such information on investment firm behavior led FERC to publish the notice of inquiry on its policy in the first place.

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Md. Emission-reduction Plan: High Ambitions, No Funding

To meet its ambitious goals of reducing greenhouse gas emissions 60% by 2031 and getting to net zero by 2045, Maryland should adopt a Clean Power Standard (CPS) ― 100% carbon-free by 2035 ― increase state rebates for electric vehicles to $7,500 for low-income buyers and quadruple the installation of heat pumps for HVAC and water heating, according to the state’s Climate Pollution Reduction Plan. 

The state also will have to come up with an extra $1 billion per year in public funding to pay for those proposals and the dozens of other initiatives laid out in the plan, even as it faces increasing budget shortfalls over the next few years. 

Released by the Maryland Department of the Environment (MDE) on Dec. 28, the plan lays out emission-cutting recommendations for every sector in the state’s economy, and to-do lists for the General Assembly and the administration of Gov. Wes Moore (D). 

“The policies in this plan, if fully implemented … will nearly put an end to the fossil fuel era and accelerate the transition to a clean energy economy,” the report says. 

The plan also stresses that a major portion of that $1 billion in new public spending each year “would focus on providing financial support to Maryland’s low-, moderate- and middle-income households and small businesses,” with the primary goal of improving equity and affordability. 

The state’s energy transition will be “intentional but also practical and methodical,” the report says, laying out “a sustainable path where incentives are provided at key decision points to consumers.” For example, when a furnace needs to be replaced, state incentives ― added to federal tax credits from the Inflation Reduction Act ― could cover up to 100% of the cost of installing a heat pump for low- and moderate-income households and 50% for middle-income households. 

Clean energy advocates have mostly praised the plan but cautioned that the nitty-gritty details of implementation remain to be worked out. 

The plan is “scientifically sound; it’s technically strong,” said Kim Coble, executive director of the Maryland League of Conservation Voters. “Where we are disappointed is that … there isn’t a plan to implement it. There’s [no] action. There’s not a funding source. There’s not even a discussion about how we are going to determine a funding source.”  

Rather, she said, the plan lays out an extensive list of tasks for lawmakers and different state agencies, without providing concrete next steps. 

    • The Maryland Energy Administration (MEA) would determine a legal framework for the CPS and whether the needed regulations could be implemented under its existing statutory authority.  
    • The MDE would begin drafting new regulations to establish zero emission standards for heating equipment, with final regulations to be released by the end of 2025.  
    • Responsibility for providing new point-of-sale incentives for EVs and EV chargers would be split between the Department of Transportation and MEA, respectively.  
    • The Public Service Commission would have the role of initiating a proceeding this year “to require natural gas utility companies to develop plans to achieve a structured transition to a net-zero economy in Maryland.”  
    • As a first step toward the CPS, the General Assembly would update the state’s existing Renewable Portfolio Standard specifically to exclude solid waste incineration, which is currently defined as renewable power. 

The Elephant in the Room

People’s Counsel David S. Lapp, the state’s top consumer advocate, likes the plan’s focus on building electrification, which “is the least-cost path forward for customers, including residential customers,” he said. Heat pumps can replace both home heating and cooling equipment, Lapp said. 

PSC action on gas utility planning is critical, but not enough, he said. “The legislature at some point, the sooner the better, will need to get involved.” 

By continuing to approve long-term investments by the gas utilities, “the state is effectively subsidizing fossil fuel infrastructure investments that are entirely contrary to virtually everything you see in the MDE report,” Lapp said. 

Even before the plan came out, the Maryland Chamber of Commerce raised concerns that any new regulations and fees could result in businesses moving “their operations to other states with less restrictive carbon emissions reduction regulations to avoid the high costs of compliance. Businesses in those states can also emit greenhouse gases then import their products into Maryland, creating an unfair playing field for Maryland businesses,” it said in an October letter to MDE. 

But Stephanie Johnson, founder of the newly formed Maryland Renewable Energy Alliance, countered that “the plan does a really good job of identifying the problems the state is facing, and it provides an overview of the potential solutions.” 

“The elephant in the room is the cost and timeline,” Johnson said. “I think there’s a political disconnect between the desire to move towards clean energy and the political will to make that happen, and I don’t think the plan gets at that problem.” 

Getting to 60%

The passage of the Climate Solutions Now Act (CSNA) in 2022 put Maryland on the map as a state with some of the most aggressive GHG emission reduction goals in the nation ― 60% below 2006 levels by 2031 and net zero by 2045 ― making it a potential model for other states. 

The law also required MDE to formulate a plan ― to be submitted to the governor and the General Assembly by the end of 2023 ― to reach those targets while creating jobs and economic benefits for the state. Moore upped the ante with his commitment to decarbonize the state’s electric power system by 2035. 

MDE released a preliminary plan laying out multiple options for implementing the CSNA in June ― also required by the law ― followed by a comment period that included a series of public meetings across the state. (See Maryland Climate Report Lays out Pathways to Achieving Goals.) 

Maryland is already halfway to the 2031 goal, according to MDE, and existing policies could get the state to 51%. In the past year, the state has adopted the Advanced Clean Cars II rule, requiring all new light-duty vehicles sold in the state to be zero emission by 2035. The General Assembly also passed a bill making the state’s community solar pilot a permanent program. 

Getting to 60% could be achieved by a mix of policies focused on specific sectors ― like the CPS and zero emission heating standards ― as well as economywide initiatives, such as a carbon fee or statewide cap-and-invest program, the report says. 

On the benefit side, MDE estimates that reaching net zero by 2045 could generate $1.2 billion in public health savings while creating 27,400 jobs and increasing personal incomes by a total of $2.5 billion. Factoring in heat pumps, EVs and other energy-saving measures, individual households could save as much as $4,000 per year, the report says. Statewide GHG emissions would drop by 646 million metric tons by 2050. 

Such dramatic cuts in emissions will not keep Maryland and its residents from experiencing the potentially catastrophic impacts of climate change. “Maryland’s climate will get warmer, wetter and wilder,” the report says. 

In 50 years, the state’s climate could be more like Mississippi’s, and by the end of the century, “islands throughout the Chesapeake Bay and much of Dorchester County will be lost to the sea,” the report says. Located in the middle of Maryland’s Eastern Shore, Dorchester is considered “ground zero” for sea-level rise in the state, according to a 2018 report. 

Money

Beyond the impacts of climate change, the greatest challenge ahead for Maryland is money. The ambitious targets in the CSNA did not come with any funding, and figures from the state’s Department of Legislative Services show budget gaps expanding to $418 million in 2025 and to as much as $1.8 billion by 2028. 

Maryland lawmakers must not only raise an extra $1 billion per year for clean energy and emissions reductions but do so without leaving consumers to pick up the tab through higher electricity rates or other expenses, the report says. 

“I don’t know that everybody’s figured out how to budget for climate change yet,” said Del. David Fraser-Hidalgo (D), pointing to impending budget cuts for the state’s Department of Transportation. The state also needs to increase teacher pay and hire more police officers, he said. 

“These are things that have been a known issue for a while now,” Fraser-Hidalgo said. “So, to come with a report and say, ‘Hey, we need another billion dollars for the next 10 years’ … is a challenge for the General Assembly, and the governor to find creative ways to come up those monies to make those changes.” 

Lapp said, “It’s going to take a variety of state policies to support what needs to happen, [and] that should not be subsidized, in effect, by ratepayers. It should be supported through other government policies because paying for a lot of the policies through rates is regressive.” 

“A key approach should be taxing polluters … getting money from fossil companies,” said Del. Lorig Charkoudian (D). She points to the plan’s recommendations for a carbon fee or a statewide cap-and-invest program, with some of the money raised used to offset the effects of any price increases on low- and moderate-income consumers. 

Maryland already participates in the Regional Greenhouse Gas Initiative (RGGI), a consortium of 11 East Coast states that sets ever-decreasing caps on emissions from power plants that burn fossil fuels and holds quarterly auctions to sell allowances to plants to offset their emissions. 

At the last auction of 2023, on Dec. 6, Maryland received more than $50 million from allowance sales, according to figures on the RGGI website. Now, it is pushing the other states in the consortium ― many with their own emission-reduction goals ― to set the emission caps even lower in their upcoming program review, expected this year. 

A statewide cap-and-invest program would go beyond power plants to cap emissions and sell allowances to other major industrial or commercial GHG emitters. 

Other recommendations in the plan include green revenue bonds and pollution mitigation fees for both interstate and in-state drivers. Interstate drivers would pay a “clean air toll” by mail to help mitigate the emissions their vehicles produce while traveling in the state. 

For Maryland residents, the report envisions a pollution mitigation fee paid as part of the registration process for vehicles that burn fossil fuels. The state is considering joining the growing number of states that have increased registration fees for EVs to make up for lost gas taxes, used for highway maintenance. 

If the EV fees are established, the pollution mitigation fee and clean air toll for gas-burning cars should be set at comparable amounts, the report says. 

Maryland also must go after federal funding available from the Infrastructure Investment and Jobs Act and the IRA. The report calls for all state agencies to “work closely with local governments, nonprofits and community-based organizations to ensure Maryland is competitive for federal climate action implementation funds and build capacity for local-level implementation.” 

The General Assembly

As the General Assembly opens its 90-day regular session Jan. 10, it must pass several laws before agencies can implement the plan’s top priorities. 

For example, before Maryland can set up a cap-and-invest program, the legislature would need to pass a new law that would allow the state to regulate emissions from the manufacturing sector, something it is currently prohibited from doing. 

The plan also calls for legislative action to update the state’s energy efficiency program, known as EmPOWER Maryland, to allow the PSC to set emission-reduction goals for electric and gas utilities and “require the utilities’ programs to facilitate beneficial electrification of fossil fuel heating equipment.” 

Another proposed bill would require new multifamily housing to be built either with EV chargers already installed or with the wiring necessary for installation. A new law would also be needed to allow state EV rebates to be paid at the point of sale. 

Charkoudian sees low-hanging fruit in a bill that would remove waste incineration as an eligible form of renewable generation in the RPS as a first step toward the CPS. Although previous efforts to update the RPS have failed, she said, “that absolutely can be done this year. … The idea that we are subsidizing trash incineration as a renewable source … is absurd, and it’s unjust, and it flies in the face of everything we’re trying to do with our environmental justice policies.” 

Both Charkoudian and the Chesapeake Climate Action Network (CCAN) are hoping for progress on a bill called the Responding to Emergency Needs from Extreme Weather (RENEW) Act, which was introduced by Fraser-Hidalgo last year but did not get past an initial hearing. The bill proposes that major fossil fuel companies pay a series of annual, fixed fees to compensate the state for the impacts of extreme weather events exacerbated by climate change.  

“It requires every company that has emitted more than a billion tons of greenhouse gas emissions cumulatively between 2000 and 2020 to pay [fees] to the state of Maryland,” said Jamie DeMarco, CCAN’s Maryland director. If passed, the bill could raise close to $1 billion per year for 10 years, he said. 

Fraser-Hidalgo plans to reintroduce the bill this session, and both he and DeMarco said they are going to make a major effort to get the bill to the governor’s desk. 

The LCV’s Coble says the General Assembly should approach funding with a two-step strategy, beginning with green bonds as a short-term solution. The second step would be a cap-and-invest program, which she said, “is going to take some time because it has to go through a whole regulation and rulemaking process. I would like to see the administration start that effort now because it probably wouldn’t be effective for several years.” 

Both Coble and DeMarco said direct support from Moore could be essential in getting the needed laws through the legislature. The governor has not yet released a public statement on the MDE plan. 

Fraser-Hidalgo said the funding issue could be holding Moore back from a full commitment to the MDE plan. 

“I think he would like to do that. I think he will do that,” he said. “These are expensive transitions ― electrification and decarbonization. They’re very expensive [and] haven’t really been done before and not in the way we’re talking about.” 

“We want to see Gov. Moore do three things,” DeMarco said. “One is [to] speedily and effectively implement all the executive actions … in this report. Then we also want to see him pick specific revenue raisers and fight for [them], and we also want to see him support specific legislation in Annapolis that aligns with the legislative goals” in the plan. 

Coble has a similar challenge for the governor and the legislature. “We’ve got a strong base to work from here; and we need leadership, and we need a sense of urgency, and then it will happen,” she said. “I mean, we’re the state of Maryland. Of course, it will happen.” 

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NYISO Finds No Need for New Capacity Zones

NYISO will not need to create any new capacity zones to ensure grid reliability over the next four years, the grid operator told stakeholders Jan. 9. 

That was the conclusion of NYISO’s quadrennial new capacity zone (NCZ) study, the results of which the ISO presented to a meeting of the Installed Capacity/Market Issues working groups (ICAP/MIWG). The study found that none of New York’s six “highway interfaces” — the transmission links between capacity zones — are constrained, eliminating the need to establish an NCZ. 

The NCZ study’s deliverability tests assess whether each highway interface can accommodate additional power flows and has an “additional transmission capacity” (or deliverability “headroom”) or cannot support more power and has “bottled generation capacity” (a deliverability “constraint”). The results showed, however, that each interface has additional transmission capacity, negating the need for new zones. The finding aligns with the 2019/20 NCZ study, which also identified no constraints. 

NYISO performs the NCZ study in conjunction with its demand curve reset (DCR), another quadrennial process to review and adjust the demand curves in its capacity market to ensure they accurately reflect the current costs and market conditions for providing reliable electric service in New York. 

NYISO must share the NCZ study with its Market Monitoring Unit for review and commentary and submit the study’s results to FERC as an informational filing by March 31. 

Final LCR Results

At the ICAP/MIWG meeting, NYISO also presented the final locational minimum installed capacity requirements (LCR) for the 2024/25 capability year, which were based on the 22% installed reserve margin (IRM) approved by the New York State Reliability Council’s Executive Committee (NYSRC EC) late last year. (See NY Reliability Council Approves 22% IRM for 2024/25.) 

The IRM determines the additional amount of capacity New York load-serving entities must maintain as a precaution against unexpected outages or demand surges. 

Final locational minimum installed capacity requirements (LCR) for the 2024/25 capability year | NYISO

Stakeholders raised questions about future discussions on transmission security limits (TSLs) and the assumptions contained within them, highlighting their growing relevance in LCR determination. TSLs define the maximum power capacity that can be safely transferred over the transmission network in a particular area, directly influencing the LCR and IRM by indicating the minimum generation required to maintain grid reliability within transmission constraints. 

NYISO staff confirmed it is engaged in ongoing discussions with the NYSRC and its subcommittees to refine TSLs and their assumptions and indicated those talks are expected to continue throughout 2024. 

The ISO intends to seek stakeholder approval for the final LCR results at the Jan. 18 Operating Committee meeting. 

Capacity Accreditation

NYISO staff also told ICAP/MIWG meeting attendees that the second set of informational capacity accreditation factors (CAFs), derived from the base case that produced a 23.1% IRM, will soon be published online. 

The IRM was derived from a technical study produced by both NYISO and the NYSRC’s Installed Capacity Subcommittee, which concluded that, under base conditions, a 23.1% IRM would satisfy the resource adequacy criteria without violating a loss-of-load expectation of no more than 0.1 event-days/year in the next capability year. 

The ISO said this second set of materials will include emergency assistance updates not captured in the first set of CAFs and must be posted by March 1. 

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New Jersey Broadens Public Solar Remote Net Metering Rules

New Jersey has enacted new remote net metering rules that increase the size and scope of solar projects eligible for the program but are less ambitious than lawmakers sought because Gov. Phil Murphy limited the expansion to protect ratepayers.

The Senate and Assembly voted unanimously Dec. 21 on a bill, S2848, that incorporated changes required by Murphy (D) when he conditionally vetoed the legislation.

Murphy, explaining his reasoning for the changes in a Nov. 27 veto statement, applauded the bill’s intent to “make solar energy more accessible to municipalities, schools and other public entities throughout New Jersey.” But he added that “the bill as currently drafted could prove extremely costly for New Jersey ratepayers.”

The Legislature, concurring with the veto, limited the size of remote net metering projects to 5 MW in the final bill, down from 10 MW initially sought by lawmakers. The final bill also placed remote projects under the state’s small solar facility incentive, in which the New Jersey Board of Public Utilities (BPU) sets the size of incentives through the Administratively Determined Incentives (ADI) program. The small solar facility program also limits the total annual capacity for all projects it awards each year to 50 MW.

In addition, the final version of S2848 allows eligible remote net metering projects to serve multiple public entities as subscribers without the need for a single host entity, which current rules require, and allow several hosts. The bill also allows public utilities to recover costs related to the remote net metering program in the same way they are able to do under the Community Solar program.

Sen. Bob Smith (D), a bill sponsor, said that despite the veto, the program will nevertheless “allow for more opportunities” for remote net metering.

Growth and Costs

The legislative tussle is part of the ongoing effort to stimulate the development of remote net metering projects that can help the state reach its solar capacity installation goals while also ensuring those developments don’t cost ratepayers too much. (See NJ Steps up Remote Net Metering Approvals.)

Remote net metering allows for the energy to be generated in a different place than where the energy is consumed. It enables an entity, such as a company or a government agency, that does not have space to erect a solar array to generate power at its main location to site a solar project at one or more separate sites and use the energy at the first location. State rules also allow a public agency to generate electricity that can be used remotely by other public bodies.

New Jersey implemented the state’s remote net metering program to create a solar option for municipalities and other public bodies that could meet several requirements of the state’s community solar program but could not match that program’s requirement to have a large number of subscribers.

State officials see remote net metering as part of the solar package that can help the state reach its goal of zero emissions by 2050, with solar reaching 12.2 GW of solar capacity installed by 2030 and 17.2 GW installed by 2035.

Smith said the aim of S2848 was to broaden the use of remote net metering beyond the private sector, which accounts for a large proportion of remote net metering projects installed to date.

“Why shouldn’t schools or school boards or county governments or township governments also be involved in net metering?” he said. “So it increases who can do net metering pretty significantly.”

One way the bill does that is by allowing the size of a remote net metering project to be set by the size of the aggregated energy use of the participating entities, not the average energy use, as has been the case up to now. The bill also allows the solar project and the energy receiving customers to be located on any property within the electric distribution company’s service territory, rather than requiring it to be on the public body’s own property.

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DOE Planning up to $70M in Energy Resilience Investments

The Department of Energy is preparing to invest up to $70 million in technology to reduce risks to energy infrastructure from cyber and physical threats, natural disasters and extreme weather events as part of the All-Hazards Energy Resilience Program, according to an announcement issued last week.

Funding will be provided competitively through DOE’s Office of Cybersecurity, Energy Security and Emergency Response (CESER), the department said. As many as 25 projects will receive grants of between $500,000 and $5 million. Groups associated with universities; national laboratories; nonprofits; companies; and state, local and tribal governments are eligible to apply.

CESER’s cyber and physical security investments will focus on addressing threats from “the growing digital landscape” and vandalism, sabotage and ballistic damages like the substation shootings of December 2022 in Moore County, N.C., which knocked out power for 45,000 customers. (See House Energy and Commerce Examines Moore County Attack.)

FERC has praised NERC’s Critical Infrastructure Protection (CIP) reliability standards, which govern cyber and physical security for electric utilities, as an “effective technical baseline” for the industry and even held them up as a model for other energy sectors following the 2021 ransomware attack on Colonial Pipeline. (See Colonial Hack Sparks Competing Recommendations at FERC.) But DOE said in its release that “today’s approaches to prevent these attacks” — physical attacks in particular — don’t go far enough to “minimize intrusions and damage.”

University-based research and development into cyber and physical security is a particular focus of the program. DOE said applicants in this area must be from historically Black colleges and universities, and research teams must include participants from the energy sector such as utility owners and operators or service providers.

In addition, CESER is seeking projects that will address climate and wildfire mitigation, including “opportunities to harden infrastructure against wildfires” and reducing the impact of extreme weather on energy transmission resources.

Climate change and the expected increase in severe weather have become standard topics of conversation among FERC, NERC and electric industry stakeholders, with the ERO’s 2023 Long-Term Reliability Assessment released last month highlighting the issue as a significant threat in the coming decade.

CESER said successful applicants should “span all types of energy delivery infrastructure,” including electric utilities, gas pipelines and renewable energy sources. The program is seeking “innovative and unique solutions that are not ‘one size fits all.’” According to the projects’ funding opportunity announcement, the department hopes to identify “next-generation tools and technologies … that will become widely adopted throughout the energy sector to reduce an incident disruption to energy delivery.”

Funding applications are due by March 4. CESER will notify selected recipients in May to begin award negotiations, with the amounts of the final awards to be announced in September.

“Making smart investments in America’s energy systems today is essential to ensuring they’re more reliable and resilient against tomorrow’s threats,” Energy Secretary Jennifer Granholm said. “As we build our clean energy future, these investments will help save money in the long run by identifying and developing innovative solutions that ensure our nation’s energy infrastructure can withstand emerging threats and the challenges of a changing world.”

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NY Gov. Proposes Streamlined Transmission Review, Permitting

New York’s governor is proposing to streamline the transmission permitting process, which she calls a chokepoint that is slowing progress of the state’s clean energy transition. 

The RAPID Act — Renewable Action through Project Interconnection and Deployment — would create a one-stop process for environmental review and permitting of major renewable energy and transmission facilities.  

A single transmission project can take up to 24 months to permit, which is too slow, Gov. Kathy Hochul (D) said. To meet the goals of the state’s Climate Leadership and Community Protection Act, the need for environmental protection and community input must be balanced with rapid decision-making, she said. 

The RAPID Act was one of 204 proposals Hochul offered Jan. 9 with her State of the State Address. She did not mention it during the address itself, which focused heavily on social programs and quality-of-life issues.  

But it is on the table for the opening round of the intense spending and policy deliberations that will continue into spring at the Capitol. 

Significant Changes

“As New York continues to strive to build the clean energy infrastructure of the future, our pace of progress is jeopardized by the lack of a mechanism to fast-track transmission projects and grid interconnection decisions,” Hochul wrote in her State of the State message. 

To help address this, she proposes to modify and expand the state’s Office of Renewable Energy Siting.  

ORES is a product of the Accelerated Renewable Energy Growth and Community Benefit Act of 2020, a first-of-its-kind effort to streamline review of large-scale renewable power generation projects in New York. Developers have been complimentary about its work as an improvement over past practices, though with some suggestions for further improvement. Notably, ORES has permitted 15 projects in its short existence. 

Hochul wants to move ORES from the Department of State to the Department of Public Service and expand its powers of review to transmission facilities. The goal is to combine the successes of DPS and ORES with a clear statutory framework for transmission permitting. 

Also, Hochul said she will direct DPS to open a proceeding to improve interconnection of distributed energy resources. It will consider incentives, penalties and other ways to move New York utilities toward faster, more-efficient interconnection of DERs. 

NYISO is working toward many of the same goals in the transmission planning process. In response to Hochul’s proposals Tuesday, Vice President Kevin Lanahan said:  

“Connecting large-scale renewable generation to the grid as quickly and reliably as possible is among the highest priorities of The New York Independent System Operator. We look forward to participating in the Department of Public Service proceeding once it is initiated. The NYISO worked collaboratively throughout 2023 with utilities, renewable developers, and state policymakers to identify and implement significant efficiencies and improvements to the interconnection process. Our work is not done, and Governor Hochul’s proposal comes at an important and opportune time.” 

Other Proposals

In other energy- and utility-related matters, Hochul also proposed: 

    • The Affordable Gas Transition Act, designed to limit new utility investment in the fossil fuel infrastructure the state is trying to phase out while also promoting affordability for customers who switch from natural gas to electricity for heating. She will seek the end of the 100-foot rule, requiring utilities to provide free hookup for anyone within 100 feet of existing gas infrastructure. 
    • The Smart Energy Savings Initiative, which seeks to integrate the current patchwork of utility programs and state policies into a time-of-use demand management program that would reduce the need for costly generation and transmission investment while also providing participating customers with significant savings.
    • NY Grid of the Future, a Department of Public Service proceeding that would identify smart grid technologies that would enable flexible services such as virtual power plants. The goal is to produce by the end of 2024 a plan that would lay out capabilities, costs, benefits and savings. 
    • Statewide Solar for All, which would combine the utility-managed Energy Affordability Program and Community Solar to save 800,000 low-income households $40 per year.

Reaction 

Hochul’s proposals drew quick reaction from advocates and stakeholders. 

The Alliance for Clean Energy New York has a long list of green priorities it is advocating on its own and praised some of those Hochul laid out Tuesday, particularly the need for transmission upgrades: “New York needs a speedy and fair permitting process for clean energy. ORES has issued permits more efficiently than the previous process, but there are still problems. In the application review, for example, deficiencies are identified in multiple rounds rather than all at once, and ORES has been inconsistent in application requirements. These issues are unnecessarily delaying the process without any additional benefit to communities or the environment. We hope today’s proposal will fix those problems as well.”  

NY Renews called for firmer action backed with heavy spending: “We applaud Governor Hochul for including parts of the NY HEAT Act in the State of the State policy agenda, ending the regressive policy where New Yorkers pay hundreds of millions of dollars to expand the state’s fracked gas pipelines. It’s time New York starts shifting our state’s energy infrastructure away from fossil fuels and toward the electric and thermal energy networks that we’ll need to power our homes, workplaces, and public buildings in the future. But we’ll need much more to protect the safety and survival of our families, communities, and environment for generations to come.” 

Advanced Energy United applauded the clean energy initiatives, particularly the transition away from natural gas and strengthening the transmission infrastructure: “Building a bigger, better electric grid and electrifying buildings are investments in home-grown energy resources that will create in-state jobs and a more resilient energy system, and benefit the health and financial wellbeing of all New Yorkers.” 

The Building Decarbonization Coalition found a lot to like: “BDC applauds Governor Hochul’s commitment to advancing New York’s nation-leading energy affordability and building decarbonization efforts with a plan that will help transform how New York heats and cools its buildings, making families’ energy bills more affordable, fortifying the state’s clean heating and cooling infrastructure with union jobs, and lowering the state’s climate emissions.” 

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Group Says Inslee, Dems Knew About Cap-and-invest Impact

A Seattle-based conservative think tank says Gov. Jay Inslee (D) knew nearly a decade ago that Washington’s cap-and-invest program — launched in 2021— would dramatically increase gasoline prices in the state. 

In 2021, Inslee and other Democrats contended that cap-and-invest — which went into effect Jan. 1, 2023 — would increase gas prices by “pennies on a gallon.” In reality, prices at the pump have increased 21-50 cents per gallon, depending on how the calculations are done. 

In a press release issued Jan. 4, the Washington Policy Center (WPC), a “free market” think tank opposed to the cap-and-invest program, noted that one of Inslee’s staff members briefed the Washington Senate’s Environment, Energy and Technology Committee in 2014, predicting that a cap-and-trade program could raise gas prices by 44 cents per gallon.  

“It has been obvious the governor and his administration knew they were lying,” Todd Myers, the WPC’s environmental director, said in the press release. 

Asked by NetZero Insider whether it was appropriate to compare 2014 and 2021 calculations on different incarnations of cap-and-trade, Myers emailed in reply: “The physics and math haven’t changed. Gasoline still emits 19.6 pounds of CO2 per gallon.”  

Myers argued that the two incarnations of the program are the same, but Democrats in the Washington Legislature made significant changes and compromises in the cap-and-invest legislation in 2020 and 2021 to get enough votes to pass the program. 

At a Jan. 4 press conference in Olympia, Inslee pointed to the challenge of predicting the movement of gasoline prices. The Washington Department of Ecology, which administers cap-and-invest, came up with the “pennies per gallon” estimate partly based on estimates from California’s cap-and-trade program. 

“Ecology made a good faith effort. It’s like a weather report — hard to predict,” Inslee said. 

The governor said the state’s experts predicted lower gasoline price increases because they expected allowance auction prices to be similar to California’s when it began its program in 2012. Auction prices have been a factor in setting gas prices. 

Washington’s quarterly settlement prices in 2023 — $48.50 to $63.03 per metric ton of emissions — were much higher than what state experts predicted in 2021. By comparison, California’s allowance prices started at $10 in 2012 and rose to slightly above $36 in 2023. 

A reason for California’s lower auction prices is that Washington is trimming carbon emissions at roughly twice the rate as the Golden State over the next decade before flattening out, according to observers. That translates to Washington having fewer allowances to auction off than California, driving up prices in the Evergreen State.  

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New Jersey Backs Geothermal Study, EV Charger Bills

New Jersey lawmakers gave final passage to bills Monday to study geothermal heat pump systems, promote electric vehicle charger installation and require clarification of the status of a residential solar system when a house is sold. 

The Senate voted 35-1 for a bill, A5442, that would direct the New Jersey Board of Public Utilities (BPU) to study the “feasibility, marketability and costs of implementing large-scale geothermal heat pump systems in the state,” and to consider creating a pilot program to evaluate their use. The Assembly approved the bill 76-1 in June. 

Each of the bills passed Monday go to Gov. Phil Murphy (D), who has until Jan. 16 to sign, or not, his office said. 

Part of the geothermal study would look at whether a financial incentive system, or other strategies such as public-private partnerships, financial investments or university involvement would, “encourage and incentivize the development and successful deployment of geothermal energy and large-scale geothermal heat pump systems.” 

The study would evaluate the costs and savings to ratepayers, government entities, electric public utilities and the state.  

Although there are 3,400 geothermal heat pump systems in operation, and a major “geo-exchange” project is coming online at Princeton University, geothermal has not been a priority for New Jersey even as it has aggressively pursued other clean energy sources, such as wind and solar.  

Advocates say geothermal projects can heat or cool air and hot water extremely efficiently by harnessing the temperature of the earth below the surface. But the up-front costs can be high, requiring deep excavation and space to bury pipes underground. (See New Jersey Moves to Embrace Geothermal Heat Pumps.) 

Clean Energy EV Charging

The Senate also gave final approval to a bill, A4794, that would set up a program to develop clean energy electric vehicle (EV) charging depots with energy supplied by one or more distributed energy resources. The bill, which passed 24-9 in the Senate, passed out of the Assembly 62-12 in June. 

The bill would require the BPU, Department of Environmental Protection (DEP) and Economic Development Authority (EDA) to issue a request for proposal (RFP) seeking entities to set up demonstration depot projects in six locations around the state. The bill makes each project eligible for $2 million in unspecified “assistance.” 

At least one depot would be required to be located in the area covered by each of the state’s four electric utilities, and the bill directs the agencies to favor projects that result in the installation of direct current fast chargers (DCFCs) and creates opportunities for charging medium- and heavy-duty vehicles and fleets. 

Other criteria set out in the bill that would make certain depot locations preferable to others include those located on brown fields, those that are publicly accessible or can serve public-serving fleets, and those that charge private fleets that serve overburdened communities. Also identified as preferable in the bill are projects that manage a charging program at peak periods or minimize demand charge peak. 

The Assembly also sent to the governor with a 31-2 vote a second bill, A4715, designed to make EV charging stations more accessible.   

The bill requires that any charging station that receives financial assistance from the BPU, DEP, Department of Transportation or any other state agency be operational at least 97% of the time. It also requires the state agencies to monitor compliance with the law and enforce it.  

The bill, which passed the Assembly with a 53-23 vote Monday, secured Senate approval by 35-1 in June.  

Easing Community Solar Accessibility

A third bill, S3234, given final approval by the Senate in a 36-0 vote, seeks to inject transparency into the status of a solar system mounted on a single-family home when it is sold. 

The bill, which the Assembly backed 78-0 in June, requires the contract with the purchaser to include the name and contact information of the developer that installed the system. It also requires the contract to “contain clear and precise language regarding if the owner selling the home is transferring the lease of the panels to a new residence or to the buyer of the home contracted for sale.”  

If the lease is going to be transferred to the new property owner, the name and details of the developer that installed the panels must be disclosed. 

Property owners who misrepresent or make false claims about the company that installed the solar system or who transfers the responsibility of a leased solar system to the buyer can face a penalty of up to $1,000 under the law. 

The legislative approval followed the signing by Murphy on Thursday of a bill, S3123, that will make it easier for ratepayers — especially low-income subscribers — to sign up to receive energy from projects developed in the state’s community solar program.  

The bill’s passage followed the enactment by the BPU of a permanent Community Solar program on Aug. 16, after two rounds of pilot programs that attracted extensive developer interest. (See NJ Opens Community Solar and Nuclear Support Programs.) 

The bill sets out similar annual capacity targets to the BPU program: 225 MW each year in the first two years and 150 MW each year after. It also allows low- and moderate-income residential customers to self-attest to their modest incomes in the application process to become a Community Solar subscriber. 

The state program requires that 51% of the subscribers to a Community Solar program have a low or moderate income. Developers have for a while argued that many eligible ratepayers either do not have the documentation required to prove their income level or are reluctant to divulge personal details, which made it difficult for them to reach the subscriber targets. 

“The Community Solar Energy Program isn’t just about achieving our clean energy goals — it is also about enabling households that ordinarily would not be able to reap the benefits of solar power to do so, such as renters or families whose homes cannot support solar panels,” said state Sen. Linda Greenstein (D-Cranbury), a sponsor of the bill. “Families that choose to participate can annually save hundreds on their utility bills, and with the Governor’s signature, those savings will be felt by thousands more across New Jersey.” 

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Eversource Takes Hit of up to $1.6B on Offshore Wind

Eversource will take a fourth-quarter 2023 impairment of up to $1.6 billion due to the ongoing struggles of its offshore wind joint ventures with Ørsted.

New England’s largest utility disclosed the news Jan. 8 in an 8-K filing with the SEC.

Also Jan. 8, Eversource said it is continuing its long-running effort to exit offshore wind development altogether and is in advanced negotiations with the selected buyer. It described the unnamed potential buyer as “a leading global private infrastructure investor,” but offered no insight on the likelihood of negotiations succeeding.

Eversource and Ørsted have two joint ventures: one for South Fork Wind, one for Revolution Wind and Sunrise Wind. Separately, Eversource holds a tax equity investment in South Fork.

South Fork is under construction and recently became the first utility-scale offshore wind project to send power to the U.S. grid. The partners also have committed to building Revolution.

But they have said they cannot build Sunrise under the terms of their contract with New York state. New York in November allowed them, and other renewables developers struggling with financial pressures, to cancel their contracts and rebid.

Ørsted and Eversource are considering whether to submit a new bid for Sunrise, and if so, how much that new bid should ask for, and what chances of success that bid might have. Based on this, Eversource expects to record an after-tax, other-than-temporary impairment of $600 million to $700 million for Sunrise.

Meanwhile, in the fourth quarter, both joint ventures revised their projections to reflect the higher cost of building the three wind farms and, as a result, substantially reduced their fair value. Consequently, Eversource expects to record an after-tax, other-than-temporary impairment of $800 million to $900 million for the three projects.

Previously, Eversource reported a second-quarter 2023 impairment of $400 million ($331 million after taxes) and Ørsted reported more than $4 billion in impairments in the first three quarters of 2023, both due to offshore wind.

The U.S. offshore wind industry has been struggling for more than a year now, as developers who locked in the value of their projects’ electricity saw the cost of building those projects soar amid high interest rates, spiking inflation and supply chain shortages.

In late 2023, Ørsted’s Ocean Wind 1 and 2 became the first contracted offshore wind project in the United States to be canceled. Three others canceled power purchase agreements and went into limbo in 2023, and a fourth followed early this year.

In a news release Jan. 8, Eversource CEO Joe Nolan cited those pressures: “Offshore wind projects continue to experience major supply chain disruption and inflationary challenges in the early stage of this growing industry in the U.S., and this impairment is an unfortunate reflection of the current market conditions we are facing. Eversource remains focused on advancing the efforts to decarbonize the energy sector and accelerate electrification with much-needed investments in transmission and other clean energy infrastructure through our regulated utilities.”

In its 8-K filing Jan. 8, Eversource offered one positive update: It is now very confident that construction of an onshore substation will qualify for a 10% investment tax credit adder that was factored into the sale price negotiated with the potential buyer. That is worth nearly $400 million.

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PJM Tackled Market Changes and Transmission Expansion in 2023

A long shadow was cast over 2023 by the final days of the preceding year as the December 2022 winter storm, known as Elliott, brought the PJM grid to the brink, ushering in a year of stakeholder discussions to shore up the issues that the storm revealed. 

While the RTO avoided the widespread outages seen in other regions during the storm, 46 GW of generation went on forced outage — prompting control room operators to issue a voltage-reduction alert and prepare for the possibility that load shedding might be required. Once the dust had cleared and the performance shortfalls for underperforming generators had been calculated, market sellers faced $1.8 billion in penalties. 

In the months following the storm, PJM and stakeholders discussed concerns that capacity market structures had only narrowly avoided outages and the penalties meant to incentivize performance might prove punitive to the point of causing a surge in retirements and deceleration in new entry. 

The largest set of changes drafted this year are a pair of filings pending before FERC, encompassing components of proposals stakeholders drafted through the Critical Issue Fast Path (CIFP) process the PJM Board of Managers launched in February. The proposed market design would leave much of the Reliability Pricing Model (RPM) design intact while revising the Capacity Performance construct, market seller offer cap (MSOC) calculation, risk modeling and generation accreditation. (See “PJM Steams Ahead with CIFP Filing Timeline After FERC Deficiency Notices,” PJM MIC Briefs: Dec. 6, 2023.) 

The first of the two proposals (ER24-98) would effectively lower the maximum CP penalties a resource can face in a year by basing the penalty calculation on the Base Residual Auction (BRA) clearing price, rather than the net cost of new entry (CONE). It would also limit bonus payments, which are derived from penalty payments, to capacity resources, making energy-only generation ineligible.  

The filing would also revise the MSOC calculation to allow generators to include more cost of risk in their offers even when their net avoidable-cost rate (ACR) is zero or negative. 

The second filing (ER24-99) includes accrediting all resources under a marginal effective load-carrying capability (ELCC) framework, which PJM said would reflect the actual capacity value that resources provide. The filing also would increase the granularity of risk modeling, tighten testing requirements for capacity resources and revise components of the fixed resource requirement (FRR) framework to align with the RPM. 

After the commission issued deficiency notices on both filings in November, PJM said it believes there remains a pathway to receiving approval for the market changes in time for them to be implemented for the 2025/26 BRA, which is scheduled to be conducted in June. The notices reset the 60-day timeline for the commission to issue an order on the proposals to two months after PJM’s responses; for ER24-98 that means an order by Feb. 6, and by Jan. 30 for ER24-99. 

Throughout the four CIFP phases, PJM and stakeholders developed 20 proposals ranging from revising the CP penalty structure to major reworks of the capacity market, such as shifting to a seasonal construct or paying resources for each hour they are able to offer their capacity into the energy market. None of the packages ultimately received a recommendation from the Members Committee in an Aug. 23 vote. (See PJM Stakeholders Vote Against All CIFP Proposals.) 

The board also sought to reduce the risks generators face in the capacity market by tightening the triggers to initiate a performance assessment interval (PAI), which the RTO argued in the CIFP filings would maintain an incentive to perform even with a lower maximum annual penalty. The commission approved PJM’s request on July 28. (See FERC Approves PJM Change to Emergency Triggers.) 

The new rules add a requirement that a primary reserve shortage be in place paired with any of the following: a voltage reduction warning and reduction of noncritical plant load; manual load dump warning; maximum generation emergency action; or curtailment of nonessential building load. 

In directing that the filing be made, the board chose half of a proposal endorsed by the MC in May, rejecting a stakeholder call for a reduction in the nonperformance penalties by basing the calculation on the BRA clearing price. While the annual stop-loss would be tied to capacity prices under the CIFP filing, the penalty rate would continue to be derived from net CONE. (See PJM Board Rejects Lowering Capacity Performance Penalties.) 

Settlement Reduces Elliott Penalties

While discussions on how to change PJM’s markets went on throughout the year, market sellers that underperformed during Elliott negotiated with PJM to reach a settlement to reduce the $1.8 billion in penalties they faced. 

An agreement was reached in October to reduce the total sum to $1.25 billion, and FERC granted its blessing last month, resolving the bulk of the 15 complaints filed against PJM over its assessment and application of the penalties. (See FERC Approves Settlement Reducing PJM Penalties for Elliott Underperformance.) 

In a concurrent order, FERC rejected a complaint from Energy Harbor arguing that PJM had not properly accounted for a maintenance outage that partially reduced the output of its Sammis generator. The RTO argued that the generator also experienced a forced outage that could account for the entirety of the facility’s performance shortfall and therefore the maintenance outage was not an excuse for its underperformance. 

The commission is still considering a second complaint not fully resolved by the settlement, an argument from the East Kentucky Power Cooperative (EKPC) that basing the penalty rate and annual stop-loss on net CONE, rather than the BRA clearing price, results in the potential for penalties being higher than the revenues a resource can earn in the market and is not just and reasonable. 

PJM also sought to reduce the financial shock of the penalties by creating a new payment option that allows the penalties to be paid over the course of nine months, rather than by the end of the delivery year, at the cost of being subject to interest. Penalty payments are due by the end of the delivery year in which they are assessed under the standard schedule. The commission approved the alternative on April 7, and about 30% of market sellers saddled with penalties chose the longer timeline. (See “FERC Approves Alternative Billing Schedule,” PJM: Elliott Nonperformance Penalties Total More Than $1.8B.) 

New Stakeholder Groups Continue Reliability Discussions

Stakeholders have also launched three groups to investigate further changes to PJM’s markets and planning processes aimed at reducing reliability risks posed by shocks to the grid, such as winter storms, and the balance between generation deactivations, new resource entry and load growth.  

The Deactivation Enhancements Senior Task Force and Reserve Certainty Senior Task Force were both formed by the Markets and Reliability Committee in September, and the Long-Term Regional Transmission Planning Workshop began its work in July. (See PJM MRC/MC Briefs: Sept. 20, 2023.) 

The RCSTF was created with a wide-ranging issue charge intended to address any deficiencies stakeholders identify in the near, intermediate and long terms. The areas the group is tasked with investigating include reserve performance and penalties for not meeting obligations when called upon; ensuring that market offers reflect actual resource capability and fuel procurement; how reserves are deployed and in what quantity; requirements for a resource to provide reserves; and how to incentivize resource flexibility. Thus far the group has been focused on education provided by PJM and the Independent Market Monitor around how reserve resources fit into the RTO’s markets. 

The DESTF is charged with considering changes to the timeline on which generators are required to notify PJM of their intent to deactivate and how generators that agree to retire past their desired offline date are compensated under reliability-must-run (RMR) contracts. During discussions around the task force’s creation, PJM and the Monitor said that the number of large generators deactivating is likely to accelerate over the coming years and that the RTO’s mechanisms for replacing the energy provided by retiring resources would function better with additional notice. Generation owners are only required to provide 90 days’ notice of their intent to cease operations. 

The task force began the interest identification process during its Dec. 8 meeting, with stakeholders detailing goals of ensuring that deactivation notices provide adequate time for solutions to be implemented and compensation is provided for all services resources provide. 

PJM has been forming a proposal during LTRTP meetings to create a 15-year planning horizon that would forecast the future balance between load and generation under three scenarios: a base case focused on reliability needs and near-term solutions that can resolve them, and two looking at state legislation and objectives that may affect load — such as electrification — and generation, such as environmental policies prompting deactivations or renewable development. 

New Generation Interconnection Process Intended to Clear Projects Faster

PJM has completed the process of sorting 616 generation interconnection requests into two transitional queues, one of the first steps in the transition from a first-come, first-served serialized study process to the clustered approach FERC approved in December 2022. (See FERC Approves PJM Plan to Speed Interconnection Queue.) 

In a Dec. 21 announcement of the milestone, PJM said the projects were evenly split between the expedited process, or “fast lane,” and first transition cycle (TC1). The fast lane is designed to allow projects requiring relatively smaller grid upgrades to be approved quicker, with final documentation expected through this year. Studies of projects in TC1 may be complete in 2025. 

PJM said it anticipates studies being completed on about 300 projects in 2024, allowing 26,000 MW of nameplate capacity to move another step closer to construction. By mid-2025, it expects an additional 46,000 MW to have completed the new process. 

The transition to the new study process began in mid-July when PJM opened a 60-day window for projects to meet readiness requirements, namely showing that they have site control and making deposits towards the study costs. The system of increasingly large deposits and requirements on developers as they move through the study process is meant to reduce the number of speculative projects to allow PJM staff to focus on those most likely to reach commercial operation. 

Half of the 72 GW in projects expected to have their studies completed through 2025 are solar, growing to 65% when solar-and-storage hybrids are included. Standalone solar makes up a further 12.7% of project proposals, followed by offshore wind at 8.2% and onshore wind at 6.1%. Merchant transmission contributes another 5.7%, and 1,647 MW of natural gas adds 2.3%. 

The amount of time to get a signed generation interconnection agreement has been cited as one of the key hurdles in bringing more capacity online, one of the challenges PJM identified in its February “4R’s” white paper. The report stated that the pace of new generation development is not set to keep pace with load growth, particularly from data centers, and generation deactivations. (See PJM Whitepaper to Highlight Future RA Concerns.) 

Developers at a Solar Focus conference in November said the prospect of a project proposed today not having its study initiated until 2026, and the in-service date being as far out as 2030, has made grid-connected projects a hard sell. When looking to site solar projects in the PJM footprint, Steve Swern of Sol Systems said, multiple strategies are considered, including bypassing the queue by approaching utilities to connect to their distribution grids. (See Solar Developers Sing Mid-Atlantic Interconnection Blues.) 

PJM has argued that the issues slowing renewable development go beyond the interconnection queue, stating that about 40 GW of projects have cleared the queue but have yet to be built, often because of issues with siting and permitting, procurement timelines and financing. 

During a Dec. 24 Interconnection Process Subcommittee meeting, PJM’s Jonathan Thompson said projects that have been placed in the expedited queue following the completion of their readiness studies can still be shifted to TC1 if the short-circuit, stability or feasibility analyses determine that the project will require grid upgrades larger than $5 million. 

Thompson told stakeholders that PJM will carry over the study deposits developers have already made to cover the initial deposits under the new process, but additional deposits will be required further into the process. 

PJM also introduced the Queue Scope tool, which allows users to explore the potential transmission upgrades needed to construct a generator at specific locations and how it might impact grid congestion. 

Data Center Growth, Deactivations Create Need for New Transmission

One of the largest transmission buildouts PJM has seen was given the greenlight by the board last year to address 11,000 MW in generation deactivations and about 7,500 MW of new data center load in Northern Virginia, highlighting the potential impacts of the challenges that the new stakeholder groups intend to address. (See FERC Approves PJM RTEP Projects over State Protests.) 

The estimated $5 billion package of transmission projects the board approved on Dec. 11 would build lines spanning Maryland, Pennsylvania, Virginia and West Virginia, with a particular focus on bringing power into so-called Data Center Alley, around Dulles Airport in Virginia, and into Baltimore, where the retirement of the Brandon Shores generator poses reliability risks. The Brandon Shores retirement also prompted the $796 million Grid Solutions Package as part of the Regional Transmission Expansion Plan projects the board approved in July. PJM expects to update stakeholders on the status of RMR discussions with Talen Energy, owner of Brandon Shores, in the coming months. 

State consumer advocates said both the December and July RTEP approvals highlighted flaws with PJM’s planning processes, which they argue leave inadequate time for stakeholders and the public to understand and comment on the final projects before they are brought to the board. Dozens of residents from regions the transmission lines would pass through objected to the proposal, citing disruption of historic communities, agricultural land and nature preserves; the inclusion of greenfield components rather than utilizing existing rights of way; the cost to ratepayers; and the possibility that the project would support load growth through 2028 but prove insufficient should Data Center Alley continue to grow. 

A pocket of data centers is also driving $579.5 million in transmission upgrades in Ohio, with an estimated consumption of about 3,000 MW. Unlike the projects in Virginia, the Ohio projects would affect infrastructure below the 500-kV threshold to initiate the competitive process for soliciting proposal designs. (See “Data Center Growth in Ohio Contributing to Nearly $600 Million in Transmission Upgrades,” PJM PC/TEAC Briefs: May. 9, 2023.)